atmos enerrgy 36_pres

Conference Call to Review
Fiscal 2006 Third Quarter
Financial Results

August 10, 2006
10:00 a.m. EDT

Forward Looking Statements
The matters discussed or incorporated by reference in this presentation may 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. All statements other than
statements of historical fact included in this presentation are forward-looking statements
made in good faith by the Company and are intended to qualify for the safe harbor from
liability established by the Private Securities Litigation Reform Act of 1995. When used
in this presentation or in any of the Company’s other documents or oral presentations,
the words “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “goal,” “intend,”
“objective,” “plan” “projection,” “seek,” “strategy” or similar words are intended to identify
forward-looking statements. Such forward-looking statements are subject to risks and
uncertainties that could cause actual results to differ materially from those discussed in
this presentation, including the Company’s acquisition of the TXU Gas operations, the
Company’s ability to continue to access the capital markets and the other factors
discussed in the Company’s SEC filings. These factors include the risks and
uncertainties discussed in the Company’s Form 10-K for the fiscal year ended September
30, 2005 and the Company’s Form 10-Q for the three and nine month periods ended
June 30, 2006. Although the Company believes these forward-looking statements to be
reasonable, there can be no assurance that they will approximate actual experience or
that the expectations derived from them will be realized. The Company undertakes no
obligation to update or revise forward-looking statements, whether as a result of new
information, future events or otherwise.

Further, the Company will only update earnings guidance through its quarterly and
annual earnings releases. All estimated financial metrics for fiscal year 2006 and beyond
that appear in this presentation are current as of the date noted on each relevant slide.
2

Consolidated Financial Results – Fiscal 2006 3Q

Net Income (Loss) Key Drivers
Unrealized mark-to-market losses in the
natural gas marketing segment
Weather that was 31 percent warmer than
normal and 29 percent warmer than the
$15.0 $4.5 prior-year quarter, as adjusted for
jurisdictions with weather-normalized
rates
$5.0
Increase in O&M expense due to higher
employee costs
($5.0)
Increase in realized storage margins in
the natural gas marketing segment
($15.0)
Reversal of Louisiana rate adjustment
deferral
($18.1)
($25.0)
Rate increases associated with Texas
3Q 2005 3Q 2006
GRIP recovery of 2003 and 2004 capital
($ in millions) investment
Increased interest expense due to higher
average short-term debt balances and an
increase in the 3-month LIBOR rate

3


Earnings per Diluted Share

$0.06
$0.10
Notes
$0.00
Quarter-over-quarter increase of
approximately 700 thousand
($0.10) weighted average diluted shares
outstanding
($0.20)
($0.22)
($0.30)
3Q 2005 3Q 2006

4


Net Income (Loss) by Segment

8.8
$10.0 5.8
2.4
0.1
$5.0
($ in millions)

(0.0)
$0.0

($5.0) (5.2)
(6.7)
($10.0)

($15.0)
(19.0)
($20.0)
3Q 2005 3Q 2006
Utility Natural gas marketing
Pipeline and storage Other nonutility
5

Drivers
$16.8 million decrease in gross profit
$5.3 million decrease in utility gross profit primarily
due to
o $16.2 million decrease primarily due to a 10.4 Bcf
decrease in throughput, as a result of weather that was
29 percent warmer than last year and 31 percent
warmer than normal
o $1.3 million decrease due to the impact of Hurricane
Katrina in the Louisiana Division
o $6.2 million increase due to recognition of previously
deferred revenue associated with 2003 Rate
Stabilization Filing with Louisiana Public Service
Commission
o $3.9 million increase from GRIP rate adjustments
in Mid-Tex and West Texas Divisions 6

Jurisdictions Adjusted for WNA
At June 30, 2006, we had WNA in the following service areas for the
following periods as noted, which covered approximately 1.3 million of
our meters in service:
Tennessee November – April
Georgia October – May
Mississippi November – April
Kentucky November – April
Kansas October – May
Louisiana December – March*
Amarillo, TX October – May
October – May
West Texas
Lubbock, TX October – May
January – December
Virginia
In July 2006, the Mid-Tex Division received interim WNA effective
October 1, 2006, for the period October – May and covers about 1.5
million meters in service.
* Effective with the 2006-2007 winter heating season
7

Warmer Than Normal Weather Effect by Utility Division
d
ate
s
na
ate ky as id
ex
S ol
ia
uc
St ex
/K uis d- T
t ns
id- T
n
W.
MS Mi
CO Ke Co
Lo
M
40
• Utility gross profit in
the quarter was
15%
Percent (Warmer) Colder than Normal

adversely affected
by $15.3 million due
1%
to weather that was
0
31% warmer than
2%
normal, as adjusted
13% for jurisdictions with
15%
weather-normalized
27%
rates
30% 31%
(40) 35% • Louisiana and Mid-
44%
Tex Divisions did
49% 51%
not have weather-
normalized rates,
and experienced
(80) warmer than normal
weather of 86% and
86%
93%, respectively
93%

(120)

Actual / Normal Adjusted for WNA
8

Drivers
$16.8 million decrease in gross profit (continued)
$11.3 million decrease in natural gas marketing gross profit primarily
due to
o $22.8 million increase in unrealized storage mark-to-market losses
primarily due to unfavorable movement in the forward prices used
to value financial hedges on physical storage inventory, coupled
with an increase in the physical storage position of 4.9 Bcf quarter
over quarter
o $1.7 million increase in unrealized marketing mark-to-market gains
primarily due to favorable movement in the forward prices used to
value the financial derivatives used in these activities
o $9.5 million increase in realized storage contribution due to
capturing favorable arbitrage spread opportunities compared with
the prior year quarter
o $0.3 million increase in realized marketing margins primarily due to
higher margins realized on incremental volumes sold of 13.8 Bcf
quarter over quarter 9


Three Months Ended June 30
Natural Gas Marketing Segment 2006 2005 Change
(In thousands, except physical position)

Storage Activities
Realized margin $7,717 ($1,777) $9,494
Unrealized margin (21,873) 961 (22,834)
Total Storage Activities (14,156) (816) (13,340)

Marketing Activities
Realized margin 12,691 12,347 344
Unrealized margin 579 (1,136) 1,715
Total Marketing Activities 13,270 11,211 2,059

GROSS PROFIT ($886) $10,395 ($11,281)

Net physical position (Bcf) 19.0 14.1 4.9

10


Drivers
Increased O&M expenses of $13.0 million primarily
due to
$12.1 million increase in employee costs associated
with increased headcount and benefit costs,
resulting from changes in the pension assumptions
used to determine the fiscal 2006 costs
$2.0 million decrease from reversal of accrual for
Hurricane Katrina losses due to improved outlook to
fully recover losses
$1.8 million decrease in provision for doubtful
accounts primarily due to lower revenues and strong
customer account collection efforts
11


Drivers
Increased taxes, other than income, of $1.6 million
Primarily due to increased franchise fees and state
gross receipts taxes

Increased interest charges of $2.2 million
$3.4 million increase primarily due to higher short-term
debt balances used for natural gas purchases made at
significantly higher prices coupled with an increase in
the 3-month LIBOR rate, partially offset by
$1.2 million decrease in interest charges from the
early payoff of $72.5 million of First Mortgage Bonds in
June 2005
12


Pension, Post-Retirement & Other Benefits Expense

(in millions)

Other
$14.8
$18.0
Medical & Dental
$11.6
$15.0 Post-Retirement
2.4
Pension
$12.0
2.8
6.2
$9.0
2006 Pension Assumptions
4.7
$6.0 8.50% return on plan assets
3.7 5.00% discount rate
$3.0 3.0 4.00% wage increase
2.5
1.1
$0.0
3Q 2005 3Q 2006

13


Capital Expenditures

Utility CAPEX Nonutility CAPEX
(in millions) (in millions)

$33.6
$40
$100 $80.3
$75.9

$30
$75
15.6
$20
57.4
$50 54.7 $9.1

$10 18.0
$25
8.7
22.9 21.2
$0
$0
2005 3Q 2006 3Q
2005 3Q 2006 3Q
Maintenance
Growth
Fiscal 2006 3Q Expenditures
Maintenance Capital: $70.3 million
Growth Capital: $39.2 million 14

Consolidated Financial Results – Fiscal YTD

Net Income
Key Drivers
Increased contribution from
nonutility businesses, primarily
natural gas marketing segment,
due to higher margins and market
volatility
$152.6 (7%)
$175.0 $141.7
Year to date, weather was 13%
warmer than normal and 3%
$150.0
warmer than the prior year period,
as adjusted for jurisdictions with
$125.0
weather-normalized rates
Absence in fiscal 2006 of
$100.0
accelerated acquisition synergies
realized in fiscal 2005
$75.0
Increase in O&M expenses due to
$50.0 higher employee-related costs
YTD 2005 YTD 2006
GRIP rate adjustments in Texas
($ in millions) effective in 2006

15

Earnings per Diluted Share

$1.94
(10%)
$2.00
Notes
$1.75

Period-over-period increase of
$1.75
2.5 million weighted average
diluted shares outstanding
$1.50

$1.25
YTD 2005 YTD 2006

16


Net Income by Segment

104.0

84.1
$100.0
($ in millions)

$80.0

$60.0

28.2 29.1
19.4 28.6
$40.0

0.3
$20.0 0.6

$0.0
YTD 2005 YTD 2006
Utility Natural gas marketing
Pipeline and storage Other nonutility
17


Drivers
$37.2 million increase in gross profit
$10.2 million increased utility gross profit primarily from

o $22.6 million increase related to higher franchise fees, higher
state gross receipts taxes paid and other items

o $22.1 million decrease primarily due to decreased throughput
of 20.8 Bcf, due to weather that was 3 percent warmer than the
prior-year period

o $8.3 million increase due to rate adjustments resulting from the
GRIP-related recovery for 2003 and 2004 capital expenditures

o $6.2 million increase due to recognition of previously deferred
revenue associated with 2003 Rate Stabilization Filing with the
Louisiana Public Service Commission

o $4.8 million decrease due to the impact of Hurricane Katrina 18

YTD Warmer than Normal Weather Effect by Division
d
ate
es na
ky s id
t at xa x
S ol
ia
uc - Te
/K S Te uis
t ns
id- n id
.
MS CO Ke Co
Lo
M W M
10
• Year to date gross
profit was adversely
Percent (Warmer) Colder than Normal

affected by $47.5
2%
0% 0% million due to
0 weather that was
13% warmer than
2% normal, as adjusted
for jurisdictions with
5%
weather-normalized
8% rates
(10)
10% 10%
10% • Louisiana and Mid-
Tex Divisions did
13%
not have weather-
15%
normalized rates,
and experienced
(20)
19% warmer than normal
weather of 22% and
22%
28%, respectively

28%
(30)

Actual / Normal Adjusted for WNA
19


Relationship of Utility EPS to Heating Degree Days

Degree Days*
EPS
3,249
$1.50 3,250
$1.36
$1.33
3,000
$1.25
2,750
2,580 $1.04
$1.00
2,500
2,507

$0.75 2,250
YTD 2004 YTD 2005 YTD 2006

*Adjusted for WNA
20


Drivers
$37.2 million increase in gross profit (continued)
$21.0 million increase in natural gas marketing gross profit primarily
due to
o $20.1 million increase in realized marketing margins primarily due
to increased volumes sold of 27.7 Bcf year over year and
capturing higher margins in certain market areas that experienced
increased volatility
o $29.1 million increase in realized storage contribution primarily
due to more favorable arbitrage spreads as a result of increased
market volatility period over period
o $35.9 million increase in unrealized storage mark-to-market
losses primarily due to unfavorable movement in the forward
prices used to value financial hedges on physical storage
positions, coupled with an increase in physical storage positions
of 4.9 Bcf period over period
o $7.7 million increase in unrealized marketing mark-to-market
gains primarily due to favorable movement in the forward prices
used to value the financial derivatives used in these activities 21


Nine Months Ended June 30
Natural Gas Marketing Segment 2006 2005 Change
(In thousands, except physical position)

Storage Activities
Realized margin $44,600 $15,482 $29,118
Unrealized margin (42,924) (7,065) (35,859)
Total Storage Activities 1,676 8,417 (6,741)

Marketing Activities
Realized margin 63,263 43,182 20,081
Unrealized margin 4,471 (3,200) 7,671
Total Marketing Activities 67,734 39,982 27,752

GROSS PROFIT $69,410 $48,399 $21,011

Net physical position (Bcf) 19.0 14.1 4.9

22

Consolidated Financial Results- Fiscal YTD

Fair Value of Contracts at June 30, 2006
Maturity in Years
Total Fair
Source of Fair Value <1 1-3 4-5 >5 Value
(In thousands)

$ — $ — $ (24,080)
Prices actively quoted $ (15,365) $(8,715)

Prices provided by other
—
external sources 2,519 (50) — 2,469

Prices based on models &
other valuation methods (285) (270) — — (555)

$ $ — $ (22,166)
—
Total Fair Value $ (13,131) $(9,035)

23


Drivers
$37.2 million increase in gross profit (continued)

$ 6.7 million increase in pipeline and storage
gross profit
o $9.7 million primarily due to a 23.2 Bcf increase in
total transportation volumes, higher transportation &
services margins and favorable arbitrage spreads,
offset by
o $3.0 million decrease due to the absence of
inventory sales year over year

24


Drivers
Increased O&M expenses of $19.7 million primarily
due to
$4.0 million increase in provision for doubtful
accounts primarily due to increased collection risk
associated with higher gas prices
$20.8 million increase in employee costs associated
with increased headcount and increased benefit
costs, resulting from changes in the pension
assumptions used to determine the fiscal 2006 costs
$2.1 million decrease due to absence of UCG
acquisition-related M&I costs which became fully
amortized in December 2004
25



(in millions)

Other
$43.0
$50.0
Medical & Dental
$33.4
Post-Retirement
$40.0 7.5
Pension
$30.0 7.8
16.7
$20.0 12.3 2006 Pension Assumptions
8.50% return on plan assets
11.3
5.00% discount rate
$10.0 9.6 4.00% wage increase
7.5
3.7
$0.0
YTD 2005 YTD 2006

26


Utility Bad Debt Expense as a Percent of Revenues

2.0 1.86

1.5
Percent

1.0 0.83
0.58
0.55
0.5 0.29

0.0
0.0
2001 2002 2003 2004 2005 2006
YTD
27


Drivers
Increased taxes, other than income, of $18.2 million
Primarily due to increased franchise fees and state gross receipts
taxes resulting from higher revenues, compared to the privilege period

Increased interest charges of $8.3 million
$11.9 million increase primarily due to higher short-term debt
balances used for natural gas purchases made at significantly higher
prices coupled with an increase in the 3-month LIBOR rate, partially
offset by
$3.6 million decrease in interest charges from the early payoff of
$72.5 million of First Mortgage Bonds in June 2005

Increased miscellaneous expense of $3.9 million primarily due to
$3.3 million increase due to an adverse regulatory ruling in
Tennessee related to the calculation of a performance-based rate
mechanism related to gas purchases and
$0.6 million decrease primarily due to lower interest income earned

28


Capital Expenditures


$90.6
$232.1 $120
$300
$209.4 $100
$250
$80
$200
55.0
$60
$150 167.6
145.3
$17.5
$40
$100
$20 35.6
$50 17.0
64.1 64.5
$0
$0 2005 YTD 2006 YTD
2005 YTD 2006 YTD
Maintenance
Growth
Fiscal 2006 YTD Expenditures
Maintenance Capital: $222.6 million
Growth Capital: $100.1 million 29

Highlights – Fiscal YTD
Natural Gas Gathering Project - (map in Appendix)
May 10, 2006, announced plans to construct a natural
gas gathering system in eastern Kentucky
Expected to relieve severe pipeline constraints and
accommodates rapidly expanding production in the region
(Big Sandy)
Estimated project cost is $75-$80 million
An independent producer in the area will have ownership
interest in the project
Project is pending all required regulatory approvals,
including exemption from regulatory oversight by the
Federal Energy Regulatory Commission
Anticipate construction to begin in the first half of fiscal
2007, and operations to begin in fiscal 2008
30

Louisiana Rate Settlement
May 25, 2006, Louisiana Public Service Commission
(LPSC) approved settlement of several existing dockets
Allows modified WNA which provides partial decoupling
Renews the Rate Stabilization Clause (RSC) with
provisions reducing regulatory lag and a refund of
$400,000
First RSC filing for the LGS service area should be made
in August 2006, with an expected effective date of
August 12, 2006
First RSC filing for the Trans La service area should be
made by December 31, 2006, with an expected effective
date of April 1, 2007
WNA in both service areas will be effective for an initial
three year period beginning with the 2006-2007 winter
31

Rate Case Filing in Mid-Tex Division
May 31, 2006, filed rate increase of $60 million and
several rate design changes including WNA, Revenue
Stabilization, and recovery of the gas cost component of
bad debt
July 6, 2006, an interim agreement was reached to
implement WNA effective October 1, 2006
Interim WNA uses 30 years of weather history and
permanent WNA will allow the parties to contest the period
of weather data used to calculate normal weather
Anticipate decision on the case in first quarter of calendar
2007
Any rate increase will be effective the day of final order;
any rate decrease will be effective from May 31, 2006.
Affects approximately 1.5 million customers in Texas
32

Mid-Tex Division Rate Case – Proposed Schedule
2006 2007
Event September October November December January February
9/15/06
Last Day to File Discovery in
Company’s Direct Case
10/3/06
Staff and Intervenor Direct
Testimony
10/24/06
Company Rebuttal
10/31/06
Hearing on the Merits BEGINS
Hearing on the Merits 11/10/06
CONCLUDES
11/28/06
Initial Briefs Due
12/7/06
Reply Briefs Due
Proposal for Decision (PFD) 1/8/07
Issued
1/23/07
Exceptions Due
1/30/07
Replies to Exceptions
First Possible RRC Conference 2/6/07
(Oral Argument)
Second Possible RRC Conference 2/20/07
(Decision)

As of July 6, 2006
Source: Railroad Commission of Texas 33

GRIP Filings – State of Texas
April 13, 2006, Atmos Pipeline-Texas 2005 GRIP filing of $3.3 million
revenue increase related to return and capital-related expenses on $21.6
million in net investment during calendar 2005, implemented August 2006
March 31, 2006, Mid-Tex Division 2005 GRIP filing of $11.8 million related
to return and capital-related expenses on $62.1 million increase in net
investment during calendar 2005; anticipate implementation September 2006
September 2005, Mid-Tex Division 2004 GRIP filing of $6.7 million related
to return and capital-related expenses on $29.4 million increase in net
investment during calendar 2004, implemented Feb. 2006
September 2005, Atmos Pipeline-Texas 2004 GRIP filing of $1.9 million
revenue increase related to return and capital-related expenses on $10.6
million in net investment during calendar 2004, implemented January 2006
September 2005, West Texas Division 2004 GRIP filing for $3.8 million on
increase in net investment of $22.6 million
Implementation of new charges in January 2006, except for the inside city limits
customers, which went into effect in May 2006.

34


GRIP Filing Process in Texas

Effective Immediately
ACCEPT

60 Effective under “Operation of Law”
IGNORE
days
Atmos files
with cities

Atmos appeals
to RRC within
DENY Up to
30 days
105
days

RRC
SUSPEND
Rules
45
days

35

Rate Case Filing – Missouri
April 7, 2006, filed request for 1st rate increase in
over 9 years in Missouri

Request for revenue increase of about $3.4
million, or 5.9%

Investments approximate $22.0 million over the
9-year period

Serve approximately 60,000 residential,
commercial and industrial customers in Missouri
36

Rate Stabilization Results - Mississippi
October 3, 2005, Mississippi Public Utilities Staff reached an agreement with the
Mississippi Division of Atmos Energy, requiring an up-front rate reduction of
$600,000 effective October 1, 2005 and the following revisions:
Annual filings to be made, effective November 1 each year, beginning September
5, 2006
New earnings sharing mechanism established
50/50 sharing of all earnings above allowed ROE for the first year
Thereafter, Atmos allowed to retain up to 250 additional basis points above ROE
Calculated ROE plus a performance adjuster of up to 50 basis points (currently
9.8%)
Shifts $10 million in annual margins from volumetric to customer charge
Revised WNA to include approximately 4% of additional heating degree days
Reduces regulatory lag, adjusts for forward-looking known and measurable
expenses and utilizes an average expected rate base
Changes affect approximately 251,000 customers
37


Gas Held in Underground Storage – by Segment

June 30, 2006 June 30, 2005
Segment Balance Volumes WACOG Balance Volumes WACOG
($MM’s) (Bcf) ($MM’s) (Bcf)

Atmos Utility $ 305.4 46.7 $ 6.54 $ 221.1 40.0 $ 5.53

Natural Gas 114.9 20.1 8.62 94.8 15.2 6.01
Marketing

Pipeline & Storage 16.8 2.5 8.56 18.3 2.8 6.54

Total: $ 437.1 69.3 $ 7.22 $ 334.2 58.0 $ 5.70

38

Credit Facilities
October 18, 2005, Atmos Energy entered into a $600 million, 3-year
committed revolving credit facility through October 18, 2008
Replaces $600 million, 364-day working capital facility on essentially the same
terms and serves as a backup liquidity facility for our commercial paper
program
November 10, 2005, Atmos Energy entered into a new $300 million
364-day committed revolving credit facility
Supplements amounts available under existing $18 million committed credit
facility and $25 million uncommitted credit facility, under essentially the same
terms as the $600 million 3-year committed revolving credit facility
November 28, 2005, Atmos Energy Marketing (AEM) increased its $250
million uncommitted credit facility to $580 million, with essentially same
terms
On March 31, 2006, AEM subsequently amended and extended this facility
to March 31, 2007
April 1, 2006, Atmos Energy renewed its existing $18 million committed
credit facility, with no material changes to terms and pricing

39

Investment Grade Credit Ratings
Moody’s Rating
Senior Unsecured Debt: Baa3
Commercial Paper: P-3
Outlook: stable
Standard & Poor’s
Senior Unsecured Debt: BBB
Commercial Paper: A-2
Outlook: stable
Fitch
Senior Unsecured Debt: BBB+
Commercial Paper: F-2
Outlook: stable

40


Quarterly Dividend

On August 9, 2006, the Atmos Board of Directors
declared a quarterly dividend of $0.315 per share

91st consecutive dividend declared

To be paid September 11, 2006, to shareholders of
record on August 25, 2006

Annual dividend of $1.26 per share

41

Consolidated Financial Results – Fiscal 2006E

Annual Dividend Growth - 1984 to 2006
$1.26

$1.20

$1.00

$0.80

$0.60

$0.40

$0.20

$0.00

'0
'0
'9
'9
'0
'0
'0
'0
'0
'9
'9
'9
'9
'9
'9
'9
'8
'8
'8
'8
'8
'8
'9

5
6
4
5
6
7
8
9
0
1
2
3
4
7
8
9
0
1
2
3
4
5
6

Note: Amounts are adjusted for mergers and acquisitions.

42


Earnings Guidance – 2006 Fiscal Year
Atmos Energy anticipates earnings to be at the lower end of the range of
$1.80 - $1.90 per fully diluted share for the 2006 fiscal year
Assumptions include:
• Adverse impact of Hurricane Katrina on margin of between $8 million and
$10 million
• Greater contribution from nonutility businesses due to higher gas price
volatility
o Expected gross margin contribution from the marketing segment in the range of
$85 million to $95 million
o Assumes a reversal of between $10 million to $15 million of mark-to-market
losses by fiscal year end
• Continued execution of rate strategy and collections efforts
• Bad debt expense of no more than $20 million
• Average short-term interest rate @ 4.5%
• No material acquisitions
Capital expenditures are expected to be between $400 million and $415
million
Note: Changes in these events or other circumstances that the company cannot currently anticipate could
materially impact earnings, and could result in earnings for fiscal 2006 significantly above or below this outlook. 43


Net Income by Segment

2006E
2004
2003 2005
($ millions, except EPS)

$ 63
$ 62 $ 81 $ 75 - 80
Utility
17
(1) 23 39 - 41
Natural Gas Marketing
3
7 31 31 - 32
Pipeline & Storage
3
4 1 1-2
Other
86
72 136 146 - 155
Total
54.4
46.5 79.0 81.3
Avg. Diluted Shares
$ 1.58
$ 1.54 $ 1.72 $1.80 - $1.90
Earnings Per Share

44

Estimated Capital Expenditures – 2006 Fiscal Year


$127-$132
$301 $273-$283
$350 $140
$300 $120
37-39
$250 $100
211 183-189
$200 $80
$32
$150 $60
90-93
$100 $40
30
90 90-94
$50 $20
2
$0 $0
2005 2006E 2005 2006E
Maintenance
Growth

Consolidated fiscal 2006 CAPEX projection is $400-$415 million
45



(in millions)

Other
$51.9
$60.0
Medical & Dental
$44.3
$50.0 6.7 Post-Retirement
Pension
10.0
$40.0
22.2
$30.0
16.8
$20.0 2006 Pension Assumptions
13.4 8.50% return on plan assets
12.8
$10.0 5.00% discount rate
9.6 4.00% wage increase
4.7
$0.0
2005 2006E

46

Consolidated Financial Results
Fiscal 2006 3Q

47

Consolidated Income Statements –
Fiscal 2006 3Q
(000s except EPS) 2006 2005

Operating Revenues:
Utility Segment $ 402,044 $ 501,735
Natural Gas Marketing Segment 562,447 466,835
Pipeline and Storage Segment 35,862 33,449
Other Nonutility Segment 1,413 1,421
Intersegment Eliminations (138,523) (96,563)
863,243 906,877
Purchased Gas Cost:
Utility Segment 232,192 326,502
Natural Gas Marketing Segment 563,333 456,440
Pipeline and Storage Segment 379 (1,733)
Other Nonutility Segment - -
658,743 685,603
Gross Profit 204,500 221,274

Operation and Maintenance Expense 104,380 91,443
Depreciation and Amortization 46,838 43,448
Taxes, other than income 48,479 46,915
Miscellaneous Income 963 1,524
Interest Charges 35,944 33,689
Income (Loss) Before Income Taxes (30,178) 7,303
Income Tax Expense (Benefit) (12,033) 2,817
Net Income (Loss) $ (18,145) $ 4,486
Net Income (Loss) Per Share:
Basic $ (0.22) $ 0.06
Diluted $ (0.22) $ 0.06
Average Shares Outstanding:
Basic 80,840 79,683
Diluted 80,840 80,144

48

Consolidated Income Statements –
Fiscal 2006 YTD
(000s except EPS) 2006 2005

Operating Revenues:
Utility Segment $ 3,254,674 $ 2,650,793
Natural Gas Marketing Segment 2,482,921 1,473,527
Pipeline and Storage Segment 121,057 122,685
Other Nonutility Segment 4,500 4,058
5,180,909 3,960,586
Purchased Gas Cost:
Utility Segment 2,488,906 1,895,181
Natural Gas Marketing Segment 2,413,511 1,425,128
Pipeline and Storage Segment 590 8,895
Other Nonutility Segment - -
4,224,416 3,041,315
Gross Profit 956,493 919,271

Operation and Maintenance Expense 325,295 305,640
Depreciation and Amortization 137,174 132,771
Taxes, other than income 158,691 140,537
Miscellaneous Income (Expense) (1,028) 2,867
Interest Charges 107,625 99,304
Income Before Income Taxes 226,680 243,886
Income Tax Expense 85,002 91,299
Net Income $ 141,678 $ 152,587
Net Income Per Share:
Basic $ 1.76 $ 1.96
Diluted $ 1.75 $ 1.94
Average Shares Outstanding:
Basic 80,520 78,009
Diluted 81,013 78,478
49

Utility Operating Income (Loss) – By Division
Fiscal 2006 3Q

2006 2005

Utility Operating Income (Loss)
Colorado-Kansas Division $ 163 $ 2,451
Kentucky Division (371) 1,260
Louisiana Division 8,715 4,358
Mid-States Division (2,734) 1,600
(12,819) 2,432
Mid-Tex Division
Mississippi Division (1,265) (2,455)
West Texas Division 4,383 4,992
Other 1,018 403
$ (2,910) $ 15,041
Total Utility Operating Income (Loss)

50

Utility Operating Income – By Division
Fiscal 2006 YTD

2006 2005

Utility Operating Income
Colorado-Kansas Division $ 23,423 $ 26,934
Kentucky Division 14,876 17,863
Louisiana Division 25,202 26,941
Mid-States Division 36,459 37,443
67,423 82,002
Mid-Tex Division
Mississippi Division 25,480 24,661
West Texas Division 24,053 26,080
Other 4,187 1,402
$ 221,103 $ 243,326
Total Utility Operating Income

51

Utility Volumes - Fiscal 2006 3Q

2006 2005 Change % Change

Sales Volumes (MMcf)
Residential 13,176 20,528 (7,352) (36%)
Commercial 11,719 15,148 (3,429) (23%)
Public authority and other 838 1,467 (629) (43%)
Industrial 4,161 5,995 (1,834) (31%)
Irrigation 2,759 787 1,972 251%
Total 32,653 43,925 (11,272) (26%)
29,630 28,753 877 3%
Transportation (MMcf)
Total Consolidated
62,283 72,678 (10,395) (14%)
Utility Volumes (MMcf)

52

Utility Volumes - Fiscal 2006 YTD

2006 2005 Change % Change

Sales Volumes (MMcf)
Residential 132,754 149,774 (17,020) (11%)
Commercial 74,691 80,059 (5,368) (7%)
Public authority and other 7,778 8,445 (667) (8%)
Industrial 21,224 23,886 (2,662) (11%)
Irrigation 3,115 913 2,202 241%
Total 239,562 263,077 (23,515) (9%)
91,384 88,635 2,749 3%
Transportation (MMcf)
Total Consolidated
330,946 351,712 (20,766) (6%)
Utility Volumes (MMcf)

53

Cash Flow Statements - Fiscal 2006 YTD

2006 2005
(000s)
$ 141,678 $ 152,587
Net income
Depreciation and amortization 137,533 133,405
Deferred income taxes 36,160 17,703
Other 12,063 7,593
Net change in operating assets and liabilities (103,991) 76,122
223,443 387,410
Operating cash flow

Acquisitions - (1,916,654)
Capital expenditures - growth (100,047) (64,570)
Capital expenditures - non-growth (222,644) (162,281)
Other, net (4,811) (1,648)
(104,059) (1,757,743)
Operating cash flow after investing activities

Repayment of long-term debt (2,618) (102,801)
Settlement of Treasury lock agreements - (43,770)
Dividends paid (76,559) (74,048)

Cash flow after acquisitions
$ (183,236) $ (1,978,362)
and growth capital

54

Capitalization - Fiscal 2006 YTD

As of June 30
2006 2005
(000s)

Short-term debt $ 297,087 7.2% $ - 0.0%

Long-term debt 2,184,083 52.7% 2,186,881 57.5%

Shareholders' equity 1,664,556 40.1% 1,616,010 42.5%

Total capitalization $ 4,145,726 100.0% $ 3,802,891 100.0%

55

As a Reminder…

The audio and slide presentation of this
conference call will be available on Atmos
Energy’s Web site by 10:00 a.m. Eastern Daylight
Time on August 10, 2006, through midnight on
November 9, 2006. Atmos Energy’s Web site
address is: www.atmosenergy.com.

To listen to the live conference call, dial 800-218-
0204 by 10:00 a.m. Eastern Daylight Time on
August 10, 2006.

56

Atmos Energy Marketing
Economic Value vs. GAAP Reported Results
We commercially manage our storage assets by capturing arbitrage value through
optimization strategies that create embedded (forward) value in the portfolio. We
report the transactions for external reporting purposes in accordance with GAAP.

GAAP Reported Value is the period to period net change in fair value of the
portfolio reported in the income statement that results from the process of marking
to market the physical storage volumes and corresponding financial instruments in
an interim period.

Economic Value is the period to period forward margin of our storage portfolio
that results from the process of calculating our weighted average cost of inventory
(WACOG), and our weighted average sales price of our forward financials
(WASP), then multiplying the difference times inventory volumes. This margin will
be realized in cash when the hedged transaction is settled.

Economic Value represents the “forward” economic margin of the transactions, while GAAP
reported results reflect that portion of our “forward” margin that has been recorded in the income
statement.
Volatility in earnings includes the impact of the accounting treatment of our storage portfolio and is
reflective of relatively high price volatility of the prompt month and the relatively low volatility of the
offsetting forward months.

58



Reported GAAP Economic Value*
Reported GAAP
Value (Commercial Value)
Value
- -Physical and Financial
Physical and Financial - Physical and Financial
Positions Positions
Positions
$28.4 MM
($57.7 MM)
($57.7 MM)
Market Spread
Embedded margin
difference
*Realizing Economic Value
$86.1 MM is dependent on ability to
execute – deliver physical
gas & close financial hedges
Supporting data appears on
the following slide
At June 30, 2006
59



Physical Economic Value (EV) GAAP Reported Value - MTM Market Spread
($ per mmbtu)
Period Volume Total Total Total
WASP WACOG EV ($ in millions) ($ per mmbtu) ($ in millions) ($ per mmbtu) ($ in millions)
Ending (Bcf)

12.5 7.1916 6.5459 0.6457 (0.7044) 1.3501
3/31/2005 8.0 (8.8) 16.8

14.1 7.7606 6.5967 1.1639 (0.5559) 1.7198
6/30/2005 16.4 (7.8) 24.2

23.6 10.3880 9.0806 1.3074 (1.5195) 2.8269
3/31/2006 30.8 (35.8) 66.6

19.0 10.2353 8.7417 1.4936 (3.0297) 4.5233
6/30/2006 28.4 (57.7) 86.1

(4.6) $ (0.1527) $ (0.3389) $ 0.1862 (1.5105) (21.9) $ 1.6967
Variance $ (2.4) $ $ 19.5

WASP: Weighted average sales price for gas held in storage
WACOG: Weighted average cost of AEM’s gas in storage
EV: “Economic Value” which equals gas sales price (WASP) minus cost of gas (WACOG) on a per unit basis

60

Atmos Pipeline and Storage

Straight Creek Gathering
System
Interstate transmission
lines continue on to major
Construction of approximately 65 miles
cities in the Northeast

of gathering facilities in eastern Kentucky
Should relieve severe pipeline
constraints and accommodate rapidly
expanding production in the region (Big
Sandy)
Estimated cost is $75-$80 million
Kinzer Drilling will have an ownership
interest in the project
Pending all regulatory approvals
including exemption from regulatory
oversight by the Federal Energy
Regulatory Commission
Anticipate construction to begin in first
half of fiscal 2007 with operations
beginning in fiscal 2008

61

Atmos Pipeline - Texas

62

Atmos Pipeline - Texas
Project Update
CAPEX* GRIP Filings **
Actual Estimated
Project 2005 2006 2005 2006
Northside Loop
JV with Energy $1.6 million $49.8 million $15.2 million $36.2 million
Transfer

Enbridge
---
$4.0 million $17.8 million
Line/Corridor $21.8 million
Compression

Devon Line/
Corridor ---- ---- ---- ----
Compression

Katy Capacity ----
Expansion/ $1.3 million $13.7 million $15.0 million
Compression

Total: $6.9 million $81.3 million $15.2 million $73.0 million
Estimated total annual revenues are $15.0 million, of which $6.7 million are expected to occur in fiscal 2006. All
projects were placed in-service in June 2006.
* CAPEX is calculated on a fiscal year basis
** Capital expenditures are included in GRIP filings on a calendar year basis and when the asset is operational 63

Project Map

North Side
Loop

Enbridge
Compression

64

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