First Quarter 2004
Financial Results
May 11, 2004
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 forwardlooking statements include, but are not limited to, expected earnings, future growth and financial
performance, timing of debt maturities, resolution of litigation and bankruptcy claims, the hiring of new
independent auditors, the successful closing of announced transactions, the successful implementation of our
acquisition and repowering strategy, the outcome of hearings on our RMR agreements and cost tracker for
scheduled expenses, and FERC’s approval of the basic LICAP market design . 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, our substantial
indebtedness and the possibility that we may incur additional indebtedness, adverse results in current and
future litigation, delays in hiring new independent auditors, delays in or failure to meet closing conditions in
announced transactions, failure to identify or successfully implement acquisitions and repowerings, adverse
rulings on our RMR agreements and cost tracker for scheduled expenses, resulting in us refunding certain
payments received to date, and FERC not approving the basic LICAP market design.
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.
2
Agenda
 Progress Year-to-Date
 Q1 Financial Results
 Strategy
3
Highlights
 Strong first quarter operating performance
– $266 million in adjusted EBITDA
– $316 million in Free Cash Flow
 Liquidity continues to strengthen – $1.4 billion
at end of Q1
 Post-Chapter 11 emergence plan solidly on track
 Internal reorganization proceeding in
accordance with plan
4
The First 100 Days’ Objectives
Financial Priorities
1. Simplify capital structure
2. Ensure our liquidity
3. Reduce borrowing costs
Operational Priorities
1. Keep plants running safely, reliably and efficiently
2. Increase contracted portion of merchant generation
3. Maintain momentum in asset sale program
4. Resolve commercial issues with Connecticut plants
Organizational Priorities
1. New CFO
2. Expedited phase-out of external advisers
3. Redirected management team
4. Restructured corporate organization
5
Operational Performance Core Regions
Generation
(MWh)
Equivalent
availability
%
Average heat
rate
(Btu / kWh)
Net capacity
factor
%
Net owned
capacity
MW
In-market
availability
%
2.9 million
81
11,400
38
7,884
95
South Central 2.8 million
85
10,700
57
2,469
98
0.9 million
72
11,600
18
1,321
99
Region
Northeast
West
 Our plants in the Northeast dealt successfully with periods of unusually
cold weather
 Our fuel diverse fleet of generators in New York and Connecticut,
helped maintain affordable electric prices during gas price spikes
 The Western Region successfully completed thirteen planned outages
at seven different plants
6
Operational – 2004 Hedging Activity
GigaWatt hours
10,000
8,000
“In the money”
Generation (1)
6,000
Energy Sales (2)
Fuel Hedges (3)
4,000
2,000
0
Entergy
New York
PJM
Nepool
For the balance of 2004, the Company has hedged 48% of “In the money”
generation with forward energy commitments and has locked in the energy margin
from those sales by purchasing 80% of the forward fuel requirements
(1) ‘In the money’ generation is derived by multiplying the forward positive spark spread (on an hourly basis) by the available capacity of each unit and aggregating by region
(2) Energy sales are actual monthly forward sales, including load serving contract commitments
(3) Fuel Hedges are actual fuel purchases converted, according to each plant’s heat rate, to an equivalent amount of generation (MWh)
7
Asset Sales - 2004
 We continue to make progress rationalizing the
Company’s non-core assets for value:
Name
Actual or expected
cash proceeds
(Millions)
Location
Calpine Cogen
Various, U.S.
PERC
Balance
Sheet Debt
(Millions)
Status
$3
N/A
Completed
Maine
$17
$25
Completed
Loy Yang A
Australia
$27
N/A
Completed
Cobee
Bolivia
$50
$24
Completed
Batesville
Mississippi
$27
$292
Executed PSA
Others (4)
Various
$20
$45
Executed PSAs
$144
$386
TOTAL
8
Connecticut Status
RMR Agreements

FERC has approved, subject to hearing and refund, NRG’s RMR agreements for
Middletown, Montville and Devon units 11-14 (1,392 MW in total)

These RMR agreements will remain in effect until the LICAP market is implemented

FERC has also approved, subject to hearing and refund, NRG’s Cost Tracker for
scheduled expenses incurred until LICAP implementation

The RMR Agreements, together with the Cost Tracker, will cover NRG’s cost of service for
Middletown, Montville and Devon 11-14 until the LICAP market is implemented

FERC had previously approved, subject to hearing and refund, an RMR Agreement for
Devon 7 & 8 although ISO-NE recently notified NRG that one unit is not needed for
reliability after April 2004 - as a result, NRG plans to retire Unit 8 in May.
Locational Installed Capacity (LICAP) market

Proposed LICAP market in New England that would pay Norwalk, Connecticut Jet Power,
Middletown, Montville and Devon 11-14 (1,812 MW in total) $5.34 per kW-month

Should provide a positive cash flow for the Connecticut fleet as a whole

FERC is expected to approve the basic LICAP market design sometime this summer
* These RMR agreements are expected to contribute up to $30 million of revenue per quarter *
Current Objectives: Checklist
Financial Priorities



$2.7 billion refinanced two-tier security structure with
weighted average cost of 6.8% (revolver undrawn)

96% IMA from coal-fired fleet, safety record better than
industry standard
2. Increase contracted portion of
merchant generation

High percentage of coal requirements contracted and
substantial portion of economic energy production sold forward
3. Maintain momentum in asset
sale program

$146 million in asset dispositions as of May 7, 2004 completed
- $97 million in cash, $49 million in debt reduction
4. Resolve commercial issues with
Connecticut plants

RMR agreements approved by FERC. LICAP expected
summer or fall 2004
1. Simplify capital structure
2. Ensure our liquidity
3. Reduce borrowing costs
Operational Priorities
1. Keep plants running safely, reliably
and efficiently
Organizational Priorities
1. New CFO
2. Expedited phase-out of
external advisers
3. Redirected management team
4. Restructured corporate organization




Liquidity of nearly $1.4 billion
Corporate debt maturities of less than $53 million due over
next six years
Bob Flexon appointed as CFO
Bankruptcy legal/financial advisers role severely
curtailed; positive 1Q ’04 cash flow impact
Corporate restructuring with regional emphasis
Streamlined HQ to be relocated in core region
10
Financial Results
11
First Quarter Financial Highlights
Strong financial operating performance
 Reported net income of $30 million or $0.30 per share
 Net income of $34 million or $0.34 per share excluding
non-recurring items
Improved liquidity
 Net cash flow of $280 million
 Liquidity increased by $188 million over last quarter
Strengthened financial position
 Refinanced $503 million of senior credit facility
 Executed interest rate swaps lowering interest expense
by $20 million over the next two years
12
Key Financial Highlights
$ millions
Operating revenues
621
Operating income
125
Net income
30
EBITDA
259
Adjusted EBITDA
266
13
1st Quarter 2004 Spark Spreads North America
Spark Spread
Dark
Spread1,2
Gas
Spread
Dual Fuel/Oil
Spread
$99,813
$1,507
$31,013
$31.23
$10.44
$39.15
(000s)
$/MWh
1
2
Dark spread is the spread between energy prices and coal-fired generation costs
Does not include LaGen
14
North American Generation by Fuel
Fuel Cost
‘03 ($000)
Fuel Cost
$/MWh
MWh ‘03
Coal
20,971,991
328,303
15.65
5,554,714
91,734
16.51
Gas*
5,478,208
259,725
47.41
1,372,617
70,689
51.50
Oil*
1,771,370
106,038
59.86
793,684
46,302
58.34
28,221,569
694,066
7,721,015
208,725
Total
MWh Q1 ‘04
Fuel Cost Q1 Fuel Cost
’04 ($000)
$/MWh
Fuel
* Gas and Oil MWh are estimated since certain assets are dual fuel
Q1 '04 Fuel Cost
Q1 '04 MWh
Coal
Gas
Oil
'03 Fuel Cost
'03 MWh
0%
20%
40%
60%
80%
100%
15
EBITDA by Operating Segment
($ millions)
Northeast
EBITDA
Adj
Adj EBITDA
114.5
0.3
114.8
South Central
29.0
0.7
29.7
West Coast
33.4
0.0
33.4
Other NA
20.7
(0.4)
20.3
International
55.1
(0.1)
55.0
Alt. Energy & Services
16.3
0.7
17.0
(10.0)
5.5
(4.5)
Corp – Unallocated
Total
259.0
6.7
265.7
16
First Quarter Cash Flow
$ millions
Adjusted EBITDA
266
Interest Payments
(43)
Income Tax Payments
(3)
Other funds used by operations
(20)
FFO
200
Other working capital changes
25
Xcel settlement, net
125
CFO
350
Asset Sales
CapEx
Other Cash Used by Investing
3
(35)
(2)
FCF
316
Cash Used by Financing
(38)
Other sources of cash
Net Cash Flow
2
280
17
2004 Sensitivity Analysis
Factors
Natural Gas
Factor
Increased by:
Results in the
following change to
2004 pre-tax income
$1.00/mmbtu
$39.0 million
Coal
$1.00/ton
($0.2) million
Oil
$1.00/bbl
($1.4) million
100 bps
($8.4) million
Interest rates
Pricing as of 3/31/04, assuming current hedged positions
18
Liquidity
$ millions
03/31/04
12/31/03
Domestic Unrestricted Cash
665
418
International Unrestricted Cash
168
134
123
111
52
46
1,008
709
Letter of Credit Availability
137
248
Revolver Availability
250
250
$1,395
$1,207
Unrestricted:
Restricted Cash:
Domestic
International
Total Cash
Total Current Liquidity
19
Credit/Collateral
$ millions
March 31, 2004
Use of $250 million LC facility
Xcel Energy (Resource Recovery)
Bank of New York (Peaker facility)
PMI support
Total
33
36
44
$113
Uses of Collateral supporting PMI
Letters of Credit*
49
Guarantees
56
Prepays/Deposits
28
Margin
24
Total
*
$157
Includes $5 million posted under separate LC facility
20
Near-Term Corporate Debt Maturities
$ millions
20
15
10
5
0
2004
2005
2006
2007
2008
2009
* Less than $53 million in corporate debt maturities
in aggregate over remainder of decade *
21
Other Items
 Independent Auditors
 Staff Appointment
–
–
–
–
–
Controller
Chief Risk Officer
Director Internal Audit
Director Planning and Analysis
Treasurer
22
Conclusions
 Strong financial results, cash flow and
liquidity
 Improving our reporting to enhance
understanding of results
 Building the team
23
Strategy:
“Beyond Back to Basics”
24
Corporate Strategy – Industry Perspective
Each wholesale power generation company represents a different commodity risk
proposition but their overall strategies have stayed in lockstep with each other
1997
IPP
Industry MPoM
Strategies
1998
1999
2000
2001
2002
2003
2004
MPoM
MPoM
MPoM
MPoM
BtB
BtB
BtB
Current Stated Strategies
Dynegy
Calpine
El Paso
Williams
Allegheny
Reliant
Cut G&A
Sell non-core assets
Economy–driven
(demand side) price recovery
Fuel mismatch
Leverage off logistics platform
(service provider)
Trading
Greenfield
Mothball marginal assets
Exit power business
25
NRG – Back to Basics
Our Back to Basics strategy is in full swing
and visible progress is being made:
Reduced corporate burden
33% reduction in
corporate headcount
Sale of non-core assets
$293 million in cash and $672
million in debt reduction in 2003
and year to date 2004 with more
to come
Delevering of balance sheet
In connection with asset sales
and with mandatory offer
Optimizing plant operations /
fuel handling processes
Investment in PRB conversion,
coal handling and environmental
remediation
Fixing Connecticut and
California
Connecticut on track; on to
California
26
How are We Making Money:
Diversified Asset Portfolio*
Northeast
Our Competitive Advantages
West

Sizeable asset base in the right markets

Long term contracts / relationships with retail
cooperatives in South Central

Locational
Gas advantage
Dual Fuel

Healthy balance sheet

Flexibility to act in best interest of stakeholders
693 MW
56%
Oil
Coal
2,350 MW 2,407 MW
30%
30%
628 MW
44%
South Central
Gas
842 MW
11%
Dual Fuel
2,284 MW
29%
Core Regions:
Gas
980 MW
40%
• Northeast
Coal
1,489 MW
60%
• South Central
• West
Our Competitive Advantages
Relative Weaknesses
 Sizeable asset base in the right markets
Aging fleet
 Long-term contracts / relationships with retail
Gaps in our ability to serve
load shaped contracts
cooperatives in South Central
 Locational advantage
 Healthy balance sheet
 Flexibility to act in best interest of stakeholders
Fuel, dispatch
and market
diversified
asset portfolio
* Other North America includes 27
4,172 MW outside of core regions
Market Environment in which
We Operate
Deregulation /
Reregulation
Industry
Structure
Market
Fundamentals
Role of Fuel
On the deregulation / reregulation spectrum, we are
entering a period of stasis. The five ISOs will move
forward methodically to refine their market model.
Other regions are static.
Further utility disaggregation is unlikely. Industry
consolidation, while desirable, necessary and
inevitable, will be delayed by the merchant generation
industry’s current debt mountain.
Supply-demand imbalance has peaked, but how long
we remain in the commodity price cycle trough is an
open issue. The timing of the correction depends much
more on the actions of industry participants (supply)
than on the strength of economic recovery (demand).
While one can argue about the sustainability of
currently high gas prices, higher gas volatility (on a
delivered basis) is a near certainty. And now Eastern
coal has shown more volatility.
28
Keys to Success in
Merchant Generation Industry:
Four fundamentals
Four imperatives
 Capital intensive - yes;
1 MUST own a generation
 Highly cyclical, inelastic
2 MUST be geographically
Labor intensive - no
demand, supply driven
 Pure commodity, but
inability to store cause
very high volatility
portfolio at a competitive cost
relative to replacement cost
diversified, in multiple
markets
3 MUST have scale in key
markets
4 MUST develop and expand
 Assets relatively illiquid
our route to market
and generally movable
29
Assessing NRG
Relative to the Four Imperatives
Competitive Generation
Excellent. $350/kW enterprise value
across fleet – 50% discount to
replacement cost
Geographic Diversity
Excellent. Core – 3 domestic markets
and 2 international markets
Scale
Better than average. One of the
bigger generators in the Northeast;
but not scale in the true sense
Route to Market
- Average. No retail customers,
trading activity slowly expanding
30
Hedging – in the Future
What are the elements of a successful strategy
to hedge a substantial portion of our
generation capacity with retail load providers?
We must own . . .
. . . plus it helps if we have . . .
 Generation which is price competitive
 The scale to negotiate as
 Generation that competitively serves
 Limited or no competitors
on both a SRMC and LRMC basis;
load-shaping requirements through
base, intermediate and peaking
capacity;
equals
with comparable
capabilities
 Generation, from various fuels, such
that we can offer the retail load
providers at least a partial hedge
against gas price spikes
31
Brownfield Development –
an Opportunity and a Necessity
Our key assets, while not as old as they seem, are aging
Typical life expectancy range of a steam boiler
with typical maintenance based on equivalent
operating years.
Years
70
60
50
40
30
20
The redevelopment of brownfield coal sites using clean coal
technology should be cheaper, quicker and cleaner
Oswego U6
Oswego U5
Indian River U4
Huntley U7,U8
Huntley U3
Encina U5
Encina U4
Encina U3
Encina U2
Equivalent Operating Years
Indian River U1,U2
Age (years)
Encina U1
El Segundo U4
El Segundo U3
Dunkirk U4
Dunkirk U3
Dunkirk U1,U2
Big Cajun II U1, U2
Arthur Kill U3
Arthur Kill U2
0
Big Cajun II U3
10
32
Repowering Opportunities
2008 and Beyond
Brownfield sites provide a distinct advantage in siting new
generation projects due to existing infrastructure and
transmission access.
Project
New Capacity Replaced
(net MW)
(MW)
Status
El Segundo Combined Cycle
618
350
Planning & Permitting
Big Cajun Supercritical Coal-Fired
675
New
Permitting
Arthur Kill Combined Cycle
600
300
Concept
Big Cajun Repowering
Concept
What are the
ingredients to
brownfield
success?
• Advance
planning
Dunkirk Repowering
675
600
Concept
Encina Combined Cycle
880
300 - 900
Concept
• Cheaper,
quicker, cleaner
Huntley Repowering
675
700
Concept
• Immediate relief
Indian River Repowering
675 - 900
182 - 767
Concept
• Long-term PPA
Somerset Repowering
250 - 450
112
Concept
Norwalk Harbor Combined Cycle
659
0
Concept
Middletown Combined Cycle
810
400
Concept
33
Acquisitions - Why?
Why would a company that aggressively acquired its
way into Chapter 11 consider an active acquisition
strategy just a few months after emergence?




Economies of scale (G&A, operations, procurement)



Improve optionality in capacity markets
Average down portfolio LRMC recovery (EV/kW capacity)
Increase market diversity
Enhance ability to successfully contract with retail load
providers
Secure fuel supply for our plant
Grow earnings and earnings potential (but not at the expense
of the balance sheet)
34
Select Acquisitions –
Enhancing our Regional Businesses
At a time when power plants are selling at a significant
discount to replacement cost, we may have attractively priced
opportunities to fill out gaps in our regional line-ups.
= Our line-up range
$/MWh
120
Upstate New York merit order
$/MWh
120
$6.20/MMBtu gas
$4.20/MMBtu gas
$6.20/MMBtu gas
$4.20/MMBtu gas
100
100
80
80
60
60
40
40
20
20
0
0
Entergy merit order
0
500
1,000
1,500
MWs
2,000
2,500
0
10,000
20,000
30,000
40,000
50,000
MWs
35
NRG: Working Towards a
Super-Regional Business Model
We are transitioning NRG from a loose collection of power plants into
three coherent regional businesses, each focused on developing as a
foundation to their businesses, commercial relationships with the inmarket retail load providers
Region
Northeast
South Central
West
Total MWs
180,000
50,000
60,000
Our MWs
7,884
2,469
1,321 (2,692 gross)
Market Share
4%
5%
2% (4% gross)
Principal Strength Base load coal
Base load coal /
long term contracts
Locational advantage
Principal
Vulnerability
Shortfall of our
generation relative
to load we serve
Lack of capacity
market
Reduction in
transmission
constraints
36
Summary - The New NRG
Extracting
maximum
value from
existing fleet
Northeast
West
Coast
Reinvestment
in repowering
life extension
of key assets
South
Central
Selective acquisitions
to fill out regional
line-ups
Objective: To create a set of regional businesses with
sustainable low (total) cost, fuel diversified asset portfolio
competitively positioned to secure their key customers
37
38
Supplemental information
39
Adjusted EBITDA Reconciliation
The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss) for the periods indicated:
Reorganized NRG
March 31, 2004
Predecessor NRG
March 31, 2003
(Dollars in thousands)
Net Income / (Loss)
$
30,235
$
(12,632)
Plus:
Income Tax Expense
14,208
32,878
78,543
169,345
58,637
64,071
30,968
----
Amortization of power contracts
16,477
----
Amortization of emission credits
6,270
----
23,639
6,732
$ 258,977
$ 260,394
Interest expense, excluding amortization of
debt issuance costs and debt discount/
(premium) noted on the following page
Depreciation and amortization
WCP CDWR contract amortization (included in
equity in earnings of unconsolidated affiliates)
Amortization of debt issuance costs
and debt discount/(premium)
EBITDA
Plus:
(Income) on Discontinued Operations,
net of Income taxes
(2,391)
(161,550)
Corporate relocation charges
1,116
----
Reorganization charges
6,250
----
Restructuring and impairment charges
----
22,136
1,738
16,591
$ 265,690
$ 137,571
Write downs and losses on sales of equity
method investments
Adjusted EBITDA
40
Adjusted EBITDA Reconciliation (cont.)
EBITDA, Adjusted EBITDA and adjusted net income are non-GAAP 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 believe 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.
41