1. El Paso Corporation
Second Quarter 2008
Financial & Operational Update
August 6, 2008
2. Cautionary Statement
Regarding Forward-looking Statements
This presentation includes certain forward-looking statements and projections. The company has made every reasonable effort to ensure that the
information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors
could cause actual results to differ materially from the projections, anticipated results or other expectations expressed in this presentation, including,
without limitation, changes in unaudited and/or unreviewed financial information; our ability to implement and achieve our objectives in the 2008 plan,
including earnings and cash flow targets; the effects of any changes in accounting rules and guidance; our ability to meet production volume targets in
our E&P segment; outcome of litigation; our ability to comply with the covenants in our various financing documents; our ability to obtain necessary
governmental approvals for proposed pipeline projects and our ability to successfully construct and operate such projects; the risks associated with
recontracting of transportation commitments by our pipelines; regulatory uncertainties associated with pipeline rate cases; actions by the credit rating
agencies; the successful close of our financing transactions; our ability to successfully exit the energy trading business; our ability to close our
announced asset sales on a timely basis; changes in commodity prices and basis differentials for oil, natural gas, and power and relevant basis spreads;
inability to realize anticipated synergies and cost savings associated with restructurings and divestitures on a timely basis; general economic and weather
conditions in geographic regions or markets served by the company and its affiliates, or where operations of the company and its affiliates are located; the
uncertainties associated with governmental regulation; political and currency risks associated with international operations of the company and its
affiliates; competition; and other factors described in the company’s (and its affiliates’) Securities and Exchange Commission filings. While the company
makes these statements and projections in good faith, neither the company nor its management can guarantee that anticipated future results will be
achieved. Reference must be made to those filings for additional important factors that may affect actual results. The company assumes no obligation to
publicly update or revise any forward-looking statements made herein or any other forward-looking statements made by the company, whether as a result
of new information, future events, or otherwise.
Certain of the production information in this presentation include the production attributable to El Paso’s 49 percent interest in Four Star Oil & Gas
Company (“Four Star”). El Paso’s Supplemental Oil and Gas disclosures, which are included in its Annual Report on Form 10-K, reflect its proportionate
share of the proved reserves of Four Star separate from its consolidated proved reserves. In addition, the proved reserves attributable to its proportionate
share of Four Star represent estimates prepared by El Paso and not those of Four Star.
Cautionary Note to U.S. Investors—The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to
disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally
producible under existing economic and operating conditions. We use certain terms in this presentation that the SEC's guidelines strictly prohibit us from
including in filings with the SEC. U.S. Investors are urged to consider closely the disclosures regarding proved reserves in this presentation and the
disclosures contained in our Form 10-K for the year ended December 31, 2007, File No. 001-14365, available by writing; Investor Relations, El Paso
Corporation, 1001 Louisiana St., Houston, TX 77002. You can also obtain this form from the SEC by calling 1-800-SEC-0330.
Non-GAAP Financial Measures
This presentation includes certain Non-GAAP financial measures as defined in the SEC’s Regulation G. More information on these Non-GAAP financial
measures, including EBIT, EBITDA, adjusted EBITDA, adjusted EPS, cash costs, and the required reconciliations under Regulation G, are set forth in this
presentation or in the appendix hereto. El Paso defines Resource Potential or Resource Inventory as subsurface volumes of oil and natural gas the
company believes may be present and eventually recoverable. The company utilizes a net, geologic risk mean to represent this estimated ultimate
recoverable amount.
2
3. Our Purpose
El Paso Corporation provides
natural gas and related energy
products in a safe, efficient, and
dependable manner
3
4. Our Vision & Values
the place to work
the neighbor to have
the company to own
4
5. Six-Month Scorecard:
Accomplishments
Pipelines Ruby, Line 300 Committed project inventory $8 billion
$1.2 billion future EBITDA*
E&P Inventory growth Haynesville, Niobrara, Altamont,
Raton CBM
Brazil Bia/Camarupim accelerating
Pinauna progressing
Portfolio Divestitures complete
Hedges Improved 2009 position Added $9 x $18 and
$10 x $17 collars for 2009
3.4 MM Bbls at $110
Higher earnings and cash flow
Financial Ahead of expectations Share buy back
Dividend increase
Expanded drilling program
*EBITDA run rate on pro-rata basis
5
7. 2008 Outcomes
Earnings Improved $1.40–$1.50*
40%–50% over 2007*
EBITDA Improved $3.8 billion–$3.9 billion
Capex Higher $3.8 billion
Inventory E&P Continued growth
Pipelines Largest ever
*Assumes full year average natural gas price of $9.75/MMBtu and average oil price of $118 Bbl based on
actual prices through August and recent forward prices for September through December; adjusted for MTM
impact of production-related derivatives and other items
7
9. Financial Results:
Three Months Ending June 30
$ Millions, Except EPS
Adjusted Diluted EPS Diluted EPS Adjusted
from Continuing from Continuing EBITDA
$865
$0.39 $0.25 $819
$0.22
$0.29
2008 2007
2008 2007 2008 2007
Earnings growth driven by higher gas prices and lower interest
Realized Natural
EBIT Interest Expense Gas Price ($Mcf)
$499 $231
$470 $221 $9.53
$7.67
2008 2007 2008 2007 2008 2007
Note: Appendix and slides 10 and 11 include details on non-GAAP terms
9
10. Items Impacting 2Q 2008 Results
$ Millions, Except EPS
Diluted
Pre-tax After-tax EPS
Income available to common stockholders $191 $ 0.25
Adjustments1
Change in fair value of power contracts $105 $ 67 $ 0.09
Change in fair value of legacy indemnification (9) (6) (0.01)
Other legacy litigation adjustments (27) (29) (0.04)
Change in fair value of
production-related derivatives in Marketing 52 33 0.04
61 39 0.06
Impact of MTM E&P derivatives2
$ 0.39
Adjusted EPS—Continuing operations3
1All
adjustments assume a 36% tax rate, except other legacy litigation adjustments, and 761 MM diluted shares
2Includes $75 MM of MTM losses on derivatives adjusted for $14 MM of realized losses from cash settlements
3Reflects fully diluted shares of 769 MM and includes income impact from dilutive securities
10
11. Business Unit Contribution
$ Millions
Three Months Ended
June 30, 2008
Adjusted
EBIT DD&A EBITDA EBITDA*
Core Businesses
$ 295 $ 99 $ 394 $ 428
Pipelines
304 197 501 535
E&P
$ 599 $ 296 $ 895 $ 963
Core Businesses Total
Other Businesses
(153) – (153) (153)
Marketing
12 – 12 12
Power
41 2 43 43
Corporate & Other
$ 499 $ 298 $ 797 $ 865
Total
*Adjusted Pipeline EBITDA for 50% interest in Citrus and adjusted E&P EBITDA for 49% interest in
Four Star; Appendix includes details on non-GAAP terms
11
12. Cash Flow and Capital Investment
$ Millions
Six Months Ended
June 30,
2008 2007
$ 410 $ 121
Income from continuing operations
875 939
Non-cash adjustments
1,285 1,060
Subtotal
33 (178)
Working capital changes and other*
1,318 882
Cash flow from continuing operations
– (17)
Discontinued operations
$1,318 $ 865
Cash flow from operations
$1,175 $1,130
Capital expenditures
$ 336 $ 270
Acquisitions
$ 659 $ 80
Divestitures
$ 75 $ 75
Dividends paid
*Includes change in margin collateral of $51 MM in 2008 and $72 MM in 2007
12
13. Marketing Financial Results
$ Millions
Three Months Ended Six Months Ended
June 30, June 30,
2008 2007 2008 2007
EBIT
Strategic
Change in fair value of
production-related derivatives $ (52) $ 9 $ (73) $ (78)
Other
Change in fair value of natural gas
derivative contracts 11 2 11 (22)
Change in fair value of power contracts (105) (15) (146) (32)
Settlements, demand charges, & other – (12) 5 (19)
Operating expenses & other income (7) 21 (10) 21
Other total (101) (4) (140) (52)
EBIT $(153) $ 5 $(213) $(130)
13
15. 2008 Natural Gas and
Oil Hedge Positions
Positions as of July 15, 2008
(Contract Months July 2008 – Forward)
98 TBtu
Ceiling Average cap $10.23/MMBtu
81 TBtu 17 TBtu
2008 Gas $10.75 ceiling/ $7.66
$8.00 floor fixed price
98 TBtu
Floor
Average floor $7.94/MMBtu
Balance at
Market Price
1.71 MMBbls
Ceiling Average cap $79.54/Bbl
1.26 MMBbls
0.45 MMBbls
2008 Oil $87.80
$56.40 ceiling/
fixed price
$55.00 floor
1.71 MMBbls
Floor
Average floor $79.17/Bbl
Hedging strategy preserves upside to higher prices
15
Note: See full Production-Related Derivative Schedule in Appendix
16. 2009 Natural Gas and
Oil Hedge Positions
Positions as of July 15, 2008
151 TBtu
Ceiling Average cap $14.97/MMBtu
143 TBtu
168 TBtu 8 TBtu
2009 Gas $15.41
$9.10 $7.36
ceiling
floor fixed price
176 TBtu
Floor
Balance at
Average floor $9.02/MMBtu
Market Price
3.43 MMBbls
2009 Oil $109.93
fixed price
>50% of oil and domestic natural gas hedged
2009 hedge program enhances revenues by
approximately $270 MM
Note: See full Production-Related Derivative Schedule in Appendix 16
18. 2Q Highlights
EBIT: $295 MM
Throughput increased 6% from 2007
Significant progress on growth projects
Ruby Pipeline
TGP Line 300 Expansion
CIG Raton 2010
WIC expansion
Committed backlog increased to $8 billion
18
19. Pipeline Group Financial Results
$ Millions
Three Months Ended Six Months Ended
June 30, June 30,
2008 2007
2008 2007
$ 693 $ 682
EBIT before minority interest $ 303 $ 318
17 –
Less minority interest 8 –
$ 676 $ 682
EBIT $ 295 $ 318
$ 874 $ 867
EBITDA $ 394 $ 409
$ 938 $ 935
Adjusted EBITDA1 $ 428 $ 445
$ 455 $ 426
Capital expenditures $ 266 $ 232
$ 295 $–
Acquisitions2 $– $–
1AdjustedPipeline EBITDA for 50% interest in Citrus
2Gulf LNG acquisition
Note: Appendix includes details on non-GAAP terms
19
20. Continued Throughput Increase
YTD % Increase 2008 vs. 2007
Independence Hub
TGP 5%
Elba deliveries to Florida
SNG 7%
California
EPNG 2%
Rockies supply,
CIG 9%
expansions
6% overall increase
Note: CIG includes Colorado Interstate Gas, Cheyenne Plains and Wyoming Interstate
EPNG includes El Paso Natural Gas and Mojave 20
21. El Paso Backlog: Large and Profitable
Total committed backlog $8 billion
WIC Medicine Bow
Expansion
$39 MM Ruby Pipeline
Sep 2008 $3 Billion TGP Concord
330 MMcf/d 2011 $21 MM
TGP Line 300 Expansion
1.3–1.5 Bcf/d Nov 2009
$750 MM (Phase I & II)
30 MMcf/d
2010-2011
290 MMcf/d
WIC Expansion - Kanda
CIG High Plains Pipeline
Lateral & Wamsutter
$216 MM (100%)
$55 MM Elba Expansion III & Elba
December 2008
2010–2011 Express
900 MMcf/d
240 MMcf/d $1.1 Billion
SNG SESH –Phase I 2010–2013
CIG Totem Storage $172 MM 8.4 Bcf / 0.9 Bcf/d & 1.2 Bcf/d
WIC Piceance $154 MM (100%) Sep 2008
Lateral July 2009 140 MMcf/d
$62 MM SNG Cypress Phase III
200 MMcf/d
4Q 2009 $86 MM
220 MMcf/d Jan 2011
CIG Raton 2010
160 MMcf/d
Expansion TGP Carthage
TGP Bluewater / 800 Ln Exp
$146 MM Expansion
$25 MM
2Q 2010 $39 MM SNG South System III/
Nov 2008
130 MMcf/d May 2009 SESH Phase II
340 MMcf/d
100 MMcf/d $352 MM / $69 MM
2011–2012
Gulf LNG 370 MMcf/d / 350 MMcf/d
$1+ Billion (100%)
Oct 2011
El Paso Pipeline Partners, LP FGT Phase VIII
6.6 Bcf / 1.3 Bcf/d
Expansion
$2.4 Billion (100%)
El Paso Pipeline 2011
800 MMcf/d
Note: As of August 6, 2008; El Paso Pipeline Partners owns 10% of SNG & CIG 21
22. Ruby Pipeline Update
Market commitments of 1.1 Bcf/d 670 miles of 42quot; pipeline
100% of pipe ordered $3 billion capex
Incentive-based construction contracts 1.3–1.5 Bcf/d capacity
On the ground since mid-2007 2011 in-service
Malin
OR ID
WY
Tuscarora Opal Hub
PG&E
WIC
Ruby
Pipeline Cheyenne
Paiute
Cheyenne
CA Plains
Uinta
Kern River Basin
NV
CO
Piceance
Basin
CIG
UT
22
23. TGP Line 300 Expansion
NH
VT
Marcellus
Interconnects
MA
NY
CT
MI
RI
NJ
REX-TGP PA
Interconnect
125 miles of 30quot; looping
OH
15-year contract for 300 MDth/d
with Equitable Energy LLC
EQT
Production
$750 MM capex
WV
2010–2011 in-service
Locked in pipe prices
VA
KY
23
23
24. Pipeline Summary
Committed backlog $8 billion
Highly focused on project execution
On track to achieve 2008 EBIT & EBITDA targets
24
26. 2Q Highlights
Improved earnings
4% sequential quarter production growth*
Continued improvement in controllable unit costs
Expanding domestic programs
Increasing capital by $200 MM
Haynesville and Niobrara Shale
Cotton Valley horizontal test successful
Altamont acquisition and down spacing
Bia/Camarupim project (Brazil) accelerating
*Pro forma basis; see appendix for reconciliation 26
27. E&P Results
$ Millions
Three Months Ended Six Months Ended
June 30, June 30,
2008 2008
2007 2007
EBIT1 $ 304 $235 $ 546 $414
EBITDA1 501 424 955 773
Adjusted EBITDA2 535 451 1,021 828
Capital expenditures 400 383 702 735
Acquisition capital 43 16 43 270
1Three months ended includes MTM losses on derivatives of $75 MM in 2008 and $5 MM in 2007. Cash paid related to
settlements of these derivatives were $14 MM and $12 MM, respectively. Year-to-date includes MTM losses on
derivatives of $110 MM in 2008 and $2 MM in 2007. Cash paid related to settlements of these derivatives were $18 MM
and $19 MM, respectively
2Adjusted E&P EBITDA for equity interest in Four Star
Note: Appendix includes details on non-GAAP terms 27
28. 97% Drilling Success Rate
2008 YTD Actual
Gross Wells Success
Completed Rate
High
PC < 40%
4 0%
High Impact
Exploration
Risk
PC 40%–80%
Med 12 83%
Medium Risk Development
and Exploration
PC > 80%
Low 222 99%
Low Risk Domestic Development
and Pinauna & Bia/Camarupim Development
238 97%
Increasing capital to $1.9 billion
28
29. Total Cash Costs
$/Mcfe
$2.01
$1.92
$1.92
$0.33 $0.54
$0.42
$0.06 $0.04 $0.05
$0.68 $0.64 $0.63
$1.59 $1.50 $1.47
$0.85 $0.82 $0.79
2Q 2007 1Q 2008 2Q 2008
Direct Lifting Costs General & Administrative
Taxes Other Than Production & Income Production Taxes
Controllable unit costs down 7% yr/yr
29
30. 2Q Production Update
MMcfe/d
1Q–2Q Pro Forma* 1Q–2Q As Reported
4% Increase 6% Decrease
886
857
830 833
808 798 12
14
11 11
14 12 173
134 136
141 202
130
222 236 223
201
195 202
147 155
147 149 155
144
311 308
308 295 308
316
2Q 2007 1Q 2008 2Q 2008 2Q 2007 1Q 2008 2Q 2008
Central Western TGC Central Western TGC
GOM/SLA International GOM/SLA International
Full year estimate ~860 MMcfe/d
Note: Includes proportionate share of Four Star equity volumes
Appendix includes details on non-GAAP terms
30
*Excludes volumes from domestic assets sold in 2008 and assumes full year of Peoples in 2007
31. Peoples Acquisition Update
Acquisition Rationale
Production and Active Rigs
Increased scale and
•
efficiency
Adds significant drilling
•
Closed
inventory 120 12
Sep. 2007
Lower lifting costs
•
100 10
Current Status 80 8
MMcfe/d
Drilled 51 wells thru 2Q08
Rigs
60 6
Expect 95–100 by YE08
40 4
Production growth delayed,
lower initial activity levels 20 2
Actively pursuing new 0 0
opportunities
3Q07 4Q07 1Q08 2Q08 3Q08E 4Q08E
Haynesville shale
Cotton Valley horizontal Production Active Rigs
Vicksburg program
Acquisition value up significantly
31
32. Arklatex Update
2008 Conventional Program
125–130 gross wells
AK
~ $350 MM net capital
8–9 rigs running and growing
Holly/Logansport
Bethany Longstreet
Cotton Valley Horizontal
Testing horizontal drilling
TX 1 well drilled and completed
4.4 MMcfe/d initial 30-day average
LA Additional 30 gross locations currently
identified; potential application to other
wells in inventory
Minden/SE
Brachfield
Haynesville Shale Exploration
1 well drilled; completion underway
Haynesville Shale Approximately 42,500 net acres
Lindy Britton #2H CV Horizontal Significant resource potential
Miller Land 10H #1 Haynesville
32
33. Haynesville Shale
Miller Land Co—H10#1 Perforations
Completion underway
5,300' Rodessa
6,700' Hosston
9,000' Cotton Valley
Bossier Shale
10,000'
11,500' Haynesville Shale
3,100'
11,700' Haynesville Lime
33
34. Raton Update
2008 CBM Program
CO 84 gross wells
$46 MM net capital
CBM Increased Density Drilling
Pursuing 80-acre spacing
Hearing held in July with state of
New Mexico
Would add 500 gross locations and
250 Bcfe risked resource potential
Niobrara Shale Exploration
3 wells drilled and completed
NM
2 horizontal and 1 vertical
Initial flow rates of 0.4–1.8 MMcfe/d
Niobrara Shale $2 MM–$3 MM completed well costs
Test well locations
> 300,000 prospective net acres
34
35. Niobrara Shale
VPR E-17A
Typical CBM well
1.0 MMcf/d
VPR D-95A VPR A-6A
1.8 MMcf/d 0.4 MMcf/d
Perforations
1,000'
Raton Coal
Vermejo Coal
2,000'
Trinidad Coal
3,000'
Pierre Shale
3,900'
4,000'
Niobrara A Shale
5,000' Niobrara B Shale
3,000'
Niobrara C Shale
35
36. Altamont-Bluebell Update
2008 Program
8 gross wells drilled
36 recompletions
WY
$66 MM net capital
UT Roll-up Acquisition
Consolidates WI in operated assets
Closed in 2Q 2008
1.6 MMBOE of proven reserves
Altamont-Bluebell Includes remaining interest in
Altamont gas plant
Increased Density Drilling
Pursuing 160-acre spacing
Hearing in September
175–200 gross locations and
>30 MMBOE risked resource potential
36
37. Bia/Camarupim Development
Bia Development Project
Project Overview: BM-ES-5 Block
Petrobras: 65% Operator
Petrobras operated with 24% EP El Paso: 35%
working interest Brazil
35–50 MMcfe/d net peak production 4-ESS-177 Rio de
Janeiro
Bia/
100–120 Bcfe net resources
Camarupim
$135 MM net capital total 6-ESS-168
Gas price indexed to basket of
imported fuel oils 4-ESS-164
First gas in 1Q 2009
BES-100 Camarupim DOC Area
Petrobras: 100%
4 development wells 2 KMS
0 1 2km
Gas
Discovery well
37
38. Bia/Camarupim Development
Project Status:
Commercial negotiations in final phase
Unitization agreement & plan of development subject to regulatory approval
Priority project for government with development activities underway
12quot; pipeline to PLEM completed & 24quot; pipeline being installed
FPSO in yard with Oct 2008 delivery date
Drilled 1st development well in 2Q 2008 38
39. Pinaúna Development
Brazil Pinaúna
1-BAS-64
Rio de
1-BAS-74
Janeiro
Project Statistics:
1-BAS-73
15–20 MBOE/d peak production
59–90 MMBOE total resource
potential
$700 MM–$750 MM total capital
Açai
1-ELPS-160
1-ELPS-170A
100% WI
Attractive returns at plan prices
Cacau
Açai ($70/Bbl)
East
2.5 km
0 1.5 2.5
Resource Outlook
Oil Gas
39
40. Pinaúna Development
Development Scope Project Status:
4 Horizontal producers Executed FSO letter of intent
4 Horizontal Water Injectors Awaiting approval of Terms of Reference
1 Gas Producer from IBAMA
Permitting & long lead sourcing continues
Pinaúna
Production MOPU
Wellhead First production late 2009, dependent on
25,000 BOPD Oil capacity
Platform timing of permit approvals
Utility MOPU
FSO
WD = 20m
383,000 Bbl Oil Capacity
3 Km—6quot; HP Oil, Gas Subsea Pipelines
WD = 35– 40m
10 Km—8quot; Crude Subsea Pipeline
Açai/Cacau
10 Km—6quot; Fuel Gas Subsea Pipeline
Wellhead Platform
40
41. E&P Summary
Inventory growing
Peoples (Arklatex, TGC)
Haynesville & Niobrara shale
Brazil, Egypt
Projects advancing
Bia/Camarupim faster than expected
Pinaúna
Altamont-Bluebell
Domestic activity increasing in 2H 2008
Maintain current rig activity
Advance new opportunities
Improve exit rate
On track for 8%–12% production growth (2007–2010)
41
42. Summary
Earnings and cash flow up
Pipelines
$8 billion backlog
Long-term EBIT growth 10%+
E&P
Inventory continues to grow
Brazil accelerates 2009 volume growth
Progress on all fronts
42
42
43. El Paso Corporation
Second Quarter 2008
Financial & Operational Update
August 6, 2008
45. Disclosure of Non-GAAP
Financial Measures
The SEC’s Regulation G applies to any public disclosure or release of material information that includes a non-GAAP financial measure. In the
event of such a disclosure or release, Regulation G requires (i) the presentation of the most directly comparable financial measure calculated and
presented in accordance with GAAP and (ii) a reconciliation of the differences between the non-GAAP financial measure presented and the most
directly comparable financial measure calculated and presented in accordance with GAAP. The required presentations and reconciliations are
attached. Additional detail regarding non-GAAP financial measures can be reviewed in El Paso’s full operating statistics, which will be posted at
www.elpaso.com in the Investors section.
El Paso uses the non-GAAP financial measure “earnings before interest expense and income taxes” or “EBIT” to assess the operating results and
effectiveness of the company and its business segments. The company defines EBIT as net income (loss) adjusted for (i) items that do not impact
its income (loss) from continuing operations, such as extraordinary items and discontinued operations; (ii) income taxes; and (iii) interest and
debt expense. The company excludes interest and debt expense so that investors may evaluate the company’s operating results without regard to
its financing methods or capital structure. EBITDA is defined as EBIT excluding depreciation, depletion and amortization. El Paso’s business
operations consist of both consolidated businesses as well as investments in unconsolidated affiliates. As a result, the company believes that
EBIT, which includes the results of both these consolidated and unconsolidated operations, is useful to its investors because it allows them to
evaluate more effectively the performance of all of El Paso’s businesses and investments. Adjusted EBITDA is defined as EBITDA including the
proportional share of EBITDA less our recorded equity earnings from our equity investments in Citrus and Four Star. The company believes that
adjusted EBITDA is useful to its investors because it allows them to evaluate more effectively the performance of our businesses regardless of
the type of ownership structure. Exploration and Production per-unit total cash costs or cash operating costs equal total operating expenses less
DD&A, cost of products and services, transportation costs, and ceiling test charges divided by total production. It is a valuable measure of
operating efficiency. For 2008, Adjusted EPS is earnings per share from continuing operations excluding the loss related to the change in fair
value of an indemnification from the sale of an ammonia plant in 2005, the gain related to an adjustment of the liability for indemnification of
medical benefits for retirees of the Case Corporation, gain related to the disposition of a portion of the company’s investment in its
telecommunications business, loss on other legacy litigation adjustments, changes in fair value of power contracts, changes in fair value of the
production-related derivatives in the Marketing segment and the impact of MTM E&P derivatives. For 2007, Adjusted EPS is earnings per share
from continuing operations excluding changes in fair value of production-related derivatives in the Marketing segment, the gain on the sale of
ANR and related assets and debt repurchase costs. Adjusted EPS is useful in analyzing the company’s on-going earnings potential.
El Paso believes that the non-GAAP financial measures described above are also useful to investors because these measurements are used by
many companies in the industry as a measurement of operating and financial performance and are commonly employed by financial analysts and
others to evaluate the operating and financial performance of the company and its business segments and to compare the operating and financial
performance of the company and its business segments with the performance of other companies within the industry.
These non-GAAP financial measures may not be comparable to similarly titled measurements used by other companies and should not be used
as a substitute for net income, earnings per share or other GAAP operating measurements.
45
48. Financial Results
Three Months Ended Year-to-date Ended
June 30, June 30,
($ Millions, Except EPS) 2008 2007 2008 2007
$ 499 $ 1,099
EBIT $ 470 $ 686
(221) (454)
Interest and debt expense (231) (514)
278 645
Income before income taxes 239 172
87 235
Income taxes 70 51
191 410
Income from continuing operations 169 121
– –
Discontinued operations, net of income taxes (3) 674
191 410
Net income 166 795
Preferred stock dividends* – 19
10 19
Net income available to common stockholders $ 191 $ 391
$ 156 $ 776
Diluted EPS from continuing operations $ 0.25 $ 0.54
$ 0.22 $ 0.15
Diluted EPS from discontinued operations – –
– 0.96
Total diluted EPS $ 0.25 $ 0.54
$ 0.22 $ 1.11
Diluted shares (millions) 761 760
757 699
*Due to timing of declaration, second quarter 2008 dividends were reflected in the first quarter
48
49. 2008 Analysis of
Working Capital and Other Changes
$ Millions
Six Months Ended
June 30, 2008
Margin collateral $ 51
Changes in price risk management activities 406
Settlements of derivative instruments (256)
Net changes in trade receivable/payable (112)
Settlement of liabilities (41)
Other (15)
Total working capital changes & other $ 33
49
50. Items Impacting YTD 2008 Results
$ Millions, Except EPS
Pre-tax After-tax Diluted EPS
Income available to common stockholders $391 $ 0.54
Adjustments1
Change in fair value of power contracts $146 $ 93 $ 0.12
Change in fair value of legacy indemnification 34 22 0.03
Case Corporation indemnification (65) (27) (0.04)
Gain on sale of portion of telecommunications business (18) (12) (0.01)
Other legacy litigation adjustments (27) (29) (0.04)
Change in fair value of
production-related derivatives in Marketing 73 47 0.06
Impact of MTM E&P derivatives2 92 59 0.08
Adjusted EPS—Continuing operations3 $ 0.74
1Alladjustments assume a 36% tax rate, except Case Corporation indemnification and other legacy litigation adjustments,
and 760 MM diluted shares
2Includes $110 MM of MTM losses on derivatives adjusted for $18 MM of realized losses for cash settlements
3Reflects fully diluted shares of 768 MM and includes income impact from dilutive securities
50
51. Items Impacting 2Q 2007 Results
$ Millions, Except EPS
Diluted
Pre-tax After-tax EPS
Net income available to common stockholders $156 $ 0.22
Adjustments1
Debt repurchase costs $86 $ 55 $ 0.08
Change in fair value of
production-related derivatives in Marketing (9) (6) (0.01)
Discontinued operations –
5 3
Adjusted EPS—Continuing operations2 $ 0.29
1Adjustments assume 36% tax rate, except for discontinued operations, and 757 MM diluted shares
2Based upon 757 MM diluted shares and includes the income impact from dilutive securities
51
52. Items Impacting YTD 2007 Results
$ Millions, Except EPS
Diluted
Pre-tax After-tax EPS
Net income available to common stockholders $ 776 $ 1.11
Adjustments1
Debt repurchase costs $ 287 $ 184 $ 0.26
Change in fair value of
production-related derivatives in Marketing 78 50 0.07
Sale of ANR and related assets (0.96)
(1,043) (674)
Effect of change in number of diluted shares2 (0.01)
Adjusted EPS—Continuing operations2 $ 0.47
1Adjustments assume 36% tax rate, except for discontinued operations, and 699 MM diluted shares
2Based upon 757 MM diluted shares and includes the income impact from dilutive securities
52
53. Business Unit Contribution
$ Millions
Three Months Ended
June 30, 2007
Adjusted
EBIT DD&A EBITDA EBITDA*
Core Businesses
$ 318 $ 91 $ 409 $ 445
Pipelines
235 189 424 451
E&P
$ 553 $ 280 $ 833 $ 896
Core Businesses Total
Other Businesses
5 1 6 6
Marketing
16 – 16 16
Power
Corporate & Other
(86) – (86) (86)
Debt Repurchase
Other (18) 5 (13) (13)
Total $ 470 $ 6 $ 756 $ 819
*Adjusted Pipeline EBITDA for 50% interest in Citrus and adjusted E&P EBITDA for 43% interest in
Four Star; Appendix includes details on non-GAAP terms
53
54. Business Unit Contribution
$ Millions
Year-to-date Ended
June 30, 2008
Adjusted
EBIT DD&A EBITDA EBITDA*
Core Businesses
$ 676 $ 198 $ 874 $ 938
Pipelines
546 409 955 1,021
E&P
$1,222 $ 607 $1,829 $1,959
Core Businesses Total
Other Businesses
(213) – (213) (213)
Marketing
10 – 10 10
Power
80 4 84 84
Corporate & Other
$1,099 $ 611 $1,710 $1,840
Total
*Adjusted Pipeline EBITDA for 50% interest in Citrus and adjusted E&P EBITDA for 49% interest in
Four Star; Appendix includes details on non-GAAP terms
54
55. Reconciliation of EBIT/EBITDA
$ Millions
Three Months Ended Six Months Ended
June 30, June 30,
2008 2007 2008 2007
EBITDA $ 797 $ 756 $1,710 $1,243
Less: DD&A 298 286 611 557
EBIT 499 470 1,099 686
Interest and debt expense (221) (231) (454) (514)
Income before income taxes 278 239 645 172
Income taxes 87 70 235 51
Income from continuing operations 191 169 410 121
Discontinued operations, net of taxes – (3) – 674
Net Income 191 166 410 795
Preferred stock dividends* – 10 19 19
Net income available to
common stockholders $ 191 $ 156 $ 391 $ 776
*Due to timing of declaration, second quarter 2008 dividends were reflected in the first quarter
55
56. Reconciliation of
Adjusted Pipeline EBITDA
$ Millions
Three Months Ended Six Months Ended
June 30, June 30,
2008 2007
2007
2008
Citrus equity earnings $ 19 $ 22 $ 32 $ 44
50% Citrus DD&A 13 13 26 25
50% Citrus interest 10 10 19 19
50% Citrus income taxes 12 14 20 26
Other* (1) (1) (1) (2)
50% Citrus EBITDA $ 53 $ 58 $ 96 $ 112
El Paso Pipeline EBITDA $ 394 $ 409 $ 874 $ 867
Add: 50% Citrus EBITDA 53 58 96 112
Less: Citrus equity earnings 19 22 32 44
Adjusted Pipeline EBITDA $ 938 $ 935
$ 428 $ 445
Citrus debt at June 30 (50%) $ 631 $ 466
*Other represents the excess purchase price amortization and differences between the estimated and actual
equity earnings on our investment 56
57. Reconciliation of
Adjusted E&P EBITDA
$ Millions
Three Months Ended Six Months Ended
June 30, June 30,
20081 20072 20081 20072
Four Star equity earnings $ 16 $3 $ 26 $2
Proportionate share of Four Star DD&A 5 5 11 11
Proportionate share of Four Star interest – – – –
Proportionate share of Four Star income taxes 15 10 28 17
Other3 14 12 27 27
Proportionate share of Four Star EBITDA $ 50 $ 30 $ 92 $ 57
El Paso E&P EBITDA $ 501 $ 424 $ 955 $ 773
Add: Proportionate share of Four Star EBITDA 50 30 92 57
Less: Four Star equity earnings 16 3 26 2
Adjusted E&P EBITDA $ 535 $ 451 $1,021 $ 828
1 E&P has a 49% interest in Four Star
2 E&P has a 43% interest in Four Star
3 Represents the excess purchase price amortization
57
58. E&P Cash Costs
2Q 2007 1Q 2008 2Q 2008
Total Per Unit Total Per Unit Total Per Unit
($ MM) ($/Mcfe) ($ MM) ($/Mcfe) ($ MM) ($/Mcfe)
$ 346 $ 4.84 $ 377 $ 5.11 $ 374 $ 5.40
Total operating expense
(189) (2.64) (212) (2.87) (197) (2.84)
Depreciation, depletion and amortization
(15) (0.22) (19) (0.26) (21)
Transportation costs (0.31)
(4) (0.06) (5) (0.06) (10)
Costs of products (0.15)
– – – – (7)
Other (0.09)
$ 1.92 $ 1.92 $ 2.01
Per unit cash costs*
71,493 73,762 69,366
Total equivalent volumes (MMcfe)*
*Excludes volumes and costs associated with equity investment in Four Star 58
60. Reconciliation of
Pro Forma Production Volumes
Equivalents, MMcfe/d
2Q 2007 1Q 2008 2Q 2008
Less: Less: Less:
Add: Domestic Add: Domestic Pro Add: Domestic Pro
Reported Peoples Assets Sold Pro Forma* Reported Peoples Assets Sold Forma* Reported Peoples Assets Sold Forma*
Central 224 31 15 240 241 – 8 233 237 – – 237
Western 144 8 5 147 149 – 2 147 155 – – 155
TGC 202 32 39 195 236 – 35 201 223 – 1 222
GOM/SLA 202 1 62 141 173 – 43 130 136 – 2 134
International 14 – – 14 12 – – 12 11 – – 11
Total consolidated 786 72 121 737 811 – 88 723 762 – 3 759
Proportionate share
of Four Star 71 – – 71 75 – – 75 71 – – 71
Total with
Four Star 857 72 121 808 886 – 88 798 833 – 3 830
*Pro forma excludes volumes from domestic assets sold in 2008 and assumes full year of Peoples in 2007
60
61. PJM Basis Description
Exposure to Day-Ahead price differentials between PJM West Hub
and 4 locations within East Hub
Total exposure equals 20 MM MWh and extends through April 2016
Energy typically flows from supply areas in West Hub to high
demand areas in East Hub
East-West spread settlements driven by transmission congestion
and marginal production costs
West Hub price often set by baseload coal; East Hub price often
set by natural gas-fired generation
32% increase in forward natural gas price led to 45% increase in
forward PJM basis spread during 2Q 2008
61
