atmos enerrgy 46_pres

Conference Call to Review2006 Fiscal2006 Fiscal Year and Fourth QuarterYear and Fourth Quarter

Financial Results

November 8, 20068:00 a.m. EST

2

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 risks relating to regulatory trends and decisions, the Company’s ability to continue to access the capital markets and the other factors discussed in the Company’s filings with the Securities and Exchange Commission. These factors include the risks and uncertainties discussed in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2005, and the Company’s Quarterly Report on Form 10-Q for the three and nine months 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 any 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 2007 and beyond that appear in this presentation are current as of the date noted on each relevant slide.

3

Consolidated Financial Results – Fiscal 2006

$135.8$147.7

$162.3

$110.0$120.0$130.0$140.0$150.0$160.0$170.0

2005 2006 2006 (excl.charge)

($ in millions)($ in millions)

Net IncomeNet Income

9%

Key DriversKey DriversIncreased contribution from nonutility businesses, primarily natural gas marketing segment, due to higher margins and market volatilityRate increase adjustments, primarily GRIP in Texas effective in 2006Nonrecurring, noncash charge of $14.6 million due to impairment of irrigation properties in West TexasWeather was 13% warmer than normal and 2% warmer than the prior year, as adjusted for jurisdictions with weather-normalized ratesIncrease in O&M expenses due to higher employee-related costsIncrease in interest expense due to higher S-T Debt balances and interest rate increases

20%

4

Earnings per Diluted ShareEarnings per Diluted Share


$1.72$1.82

$2.00

$1.25

$1.50

$1.75

$2.00

2005 2006 2006 (excl.charge)

NotesNotes2006 includes $0.18 per diluted share related to nonrecurring, noncash charge for impairment of irrigation properties in utility segmentDelivered on company’s 2006 guidance range of $1.80-$1.90 per diluted share, despite 13% warmer than normal weather Period-over-period increase of almost 2.4 million weighted average diluted shares outstanding

6%

16%

5

Net Income by SegmentNet Income by Segment


81.1

23.430.6

0.7

53.0

58.6

35.6

0.5

$0.0

$15.0

$30.0

$45.0

$60.0

$75.0

$90.0

2005 2006Utility Natural gas marketingPipeline and storage Other nonutility

($ in

mill

ions

)

6

DriversDrivers$98.9 million increase in gross profit

$17.7 million increased utility gross profit primarily from

o $22.9 million decrease primarily due to decreased throughput of 17.1 Bcf, due to weather that was 2 percent warmer than the prior year

o $16.1 million increase related to higher franchise fees, higher state gross receipts taxes paid and other items

o $13.8 million increase due to rate adjustments resulting from the GRIP-related recovery for 2004 and 2005 capital expenditures in Texas

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 $2.9 million decrease due to the impact of Hurricane Katrina


7


JurisdictionsJurisdictions Adjusted for WNAAdjusted for WNA

At September 30, 2006, we had WNA in the following service areas for the following periods as noted, which covers over 90% of our customer meters in service:

Tennessee November – AprilGeorgia October – MayMississippi November – AprilKentucky November – AprilKansas October – MayLouisiana * December – MarchMid-Tex * October – MayAmarillo, TX October – MayWest Texas October – MayLubbock, TX October – MayVirginia January – December

* New for the 2006-2007 winter heating season

8

7%

9% 9% 10%

15%

22%

28%

18%

2%

1%

5%

0% 0%

13%

(30)

(20)

(10)

0

10MS CO / K

SMid-States

Kentucky

W. Texas

Louisiana

Mid-TexConsolidated

Actual / Normal Adjusted for WNA

Perc

ent (

War

mer

) Col

der t

han

Nor

mal


• Fiscal 2006 utility gross profit was adversely affected by $49.2 million due to weather that was 13% warmer than normal, as adjusted for jurisdictions with weather-normalized rates

• Louisiana and Mid-Tex Divisions did not have weather-normalized rates and experienced warmer than normal weather of 22% and 28%, respectively

YTD Warmer than Normal Weather Effect by DivisionYTD Warmer than Normal Weather Effect by Division

9

$0.83

$1.16$1.03

2,5272,587

3,271

$0.25

$0.50

$0.75

$1.00

$1.25

2004 2005 20062,250

2,500

2,750

3,000

3,250

3,500

EPSDegree Days


Relationship of Relationship of Utility EPSUtility EPS to Heating Degree Daysto Heating Degree Days

(Adjusted for WNA)

* Excludes negative impact of asset impairment

*

10

36%51%

13%

2003–2004 Heating Season(Before TXU Gas)

Weather Normalized

Weather-Sensitive Margin

Nonweather-Sensitive Margin*

48%35%

17%

2004–2006Heating Seasons

(Post-TXU Gas)

* Non-weather sensitive margin is gas consumption not correlated to weather, i.e., gas clothes dryer, gas water heater, gas cooking, and includes monthly fixed charge

5%

86%

9%

2006–2007EHeating Season


Utility Margin SensitivityUtility Margin Sensitivity

11

Drivers Drivers $98.9 million increase in gross profit (continued)

$68.6 million increase in natural gas marketing gross profit primarily due to

o $27.3 million increase in realized marketing margins primarily due to increased volumes sold of 45.9 Bcf year over year and capturing higher margins in certain market areas that experienced increased volatility

o $1.8 million decrease in realized storage contribution as a result of unfavorable arbitrage spreads related to storage optimization efforts, coupled with increased storage fees on incremental storage capacity added in the third quarter of fiscal 2005

o $12.7 million decrease in unrealized storage mark-to-market losses primarily due to favorable movement between the forward prices used to value financial hedges and the spot prices used to value the physical storage positions, coupled with an increase in physical storage positions of 7.6 Bcf year over year

o $30.4 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


12


Natural Gas Marketing Segment 2006 2005 Change

Storage Activities Realized margin $26,225 $28,008 ($1,783)

Unrealized margin (1,293) (14,007) 12,714Total Storage Activities 24,932 14,001 10,931

Marketing Activities Realized margin 87,236 59,971 27,265

Unrealized margin 18,459 (11,999) 30,458Total Marketing Activities 105,695 47,972 57,723

GROSS PROFIT $130,627 $61,973 $68,654

Net physical position (Bcf) 14.5 6.9 7.6

Year Ended September 30

(In thousands, except physical position)

13

Consolidated Financial Results- Fiscal 2006

Fair Value of Contracts at September 30, 2006 Maturity in Years Source of Fair Value

< 1

1 - 3

4 - 5

> 5

Total FairValue

(In thousands) Prices actively quoted $ (17,421)

$ 7,122 $ — $ — $ (10,299)

Prices provided by other external sources

(440)

(936) — —

(1,376)

Prices based on models &

other valuation methods

(255)

(276) — —

(531) Total Fair Value $ (18,116) $ 5,910 $ — $ — $ (12,206)

14

Drivers Drivers

$98.9 million increase in gross profit (continued)

$13.2 million increase in pipeline and storage gross profit primarily due to

o $16.2 million increase due to a 34.9 Bcf increase in total transportation volumes, higher transportation & related service margins and more favorable arbitrage spreads captured in asset management contracts, partially offset by a

o $3.0 million decrease due to the absence of inventory sales realized in the prior year


15


DriversDriversIncreased O&M expenses of $17.1 million primarily

due to $19.6 million increase in employee costs associated with increased headcount and benefit costs primarily resulting from changes in the pension assumptions used to determine the fiscal 2006 costs$2.1 million decrease due to the absence of UCG acquisition-related M&I costs which became fully amortized in fiscal 2005$1.5 million increase in provision for doubtful accounts due to due to increased collection risk on higher customer bills caused by higher gas prices

16

Pension, PostPension, Post--Retirement & Other Benefits ExpenseRetirement & Other Benefits Expense

(in in millions))

4.7

12.8

16.7

9.9

9.7

14.2

20.1

9.3

$0.0

$10.0

$20.0

$30.0

$40.0

$50.0

$60.0

2005 2006

OtherMedical & DentalPost-RetirementPension

$53.3


$44.1

2006 Pension Assumptions8.50% return on plan assets5.00% discount rate4.00% wage increase

17


Utility Bad Debt Expense as a Percent of RevenuesUtility Bad Debt Expense as a Percent of Revenues

1.86

0.0

0.83

0.29

0.58 0.58

0.0

0.5

1.0

1.5

2.0

2001 2002 2003 2004 2005 2006

Perc

ent

18

DriversDriversIncreased taxes, other than income, of $17.3 million primarily due to increased franchise fees and state gross receipts taxes

Increased operating expenses due to $22.9 million noncash charge to recognize the impairment of West Texas irrigation properties in fiscal 2006

Increased interest charges of $13.9 million $18.7 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 $4.8 million decrease in interest charges from the early payoff of $72.5 million of First Mortgage Bonds in June 2005

Decreased miscellaneous income of $1.1 million due to $3.3 million noncash charge in fiscal 2006 related to an adverse regulatory ruling in Tennessee associated with gas purchases and the PBR calculation


19


West Texas Irrigation Volumes Decline West Texas Irrigation Volumes Decline

Num

ber o

f Wat

er W

ells 15.2 14.512.8 12.2

10.59.6

8.37.0

15.816.4

12.2

16.3

11.8 13.1

8.09.5

7.2

4.1 3.15.0

0.0

5.0

10.0

15.0

20.0

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

0.0

5.0

10.0

15.0

20.0

Irrigation Volumes

(in thousands) (in BCF)

20

90.2

210.4

89.1

218.6

$0

$75

$150

$225

$300

$375

2005 2006 MaintenanceGrowth

Utility CAPEX(in millions)

Nonutility CAPEX (in millions)

Fiscal 2006 ExpendituresMaintenance Capital: $287.1 millionGrowth Capital: $138.2 million

$307.7


Capital Expenditures Capital Expenditures

$300.6

32.6 49.1

68.5

$0

$30

$60

$90

$120

$150

2005 2006

$117.6

$32.6

21

($16.8)

$6.1

$20.9

($25.0)($15.0)

($5.0)$5.0

$15.0$25.0

4Q 2005 4Q 2006 4Q 2006(excl.

charge)

($ in millions)

Key DriversKey DriversIncrease in natural gas marketing margins, primarily unrealized marketing and storage margins Nonrecurring, after-tax charge of $14.8 million due to impairment of irrigation properties in West TexasRate increases associated with Texas GRIPIncreased interest expense due to higher average short-term debt balances and an increase in the 3-month LIBOR rate

Net Income (Loss)Net Income (Loss)

Consolidated Financial Results – Fiscal 2006 4Q

22

($0.21)

$0.07

$0.25

($0.40)

($0.20)

$0.00

$0.20

$0.40

Q4 2005 Q4 2006 Q4 2006(excl.

charge)

Notes Notes Includes a nonrecurring, after-tax charge due to impairment of irrigation properties in West Texas Utility Division of $0.18 per diluted shareQuarter-over-quarter increase of approximately 1.7 million weighted average diluted shares outstanding

Net Income (Loss) per Diluted ShareNet Income (Loss) per Diluted Share


23

25.6

65.6

24.6

51.0

$0

$30

$60

$90

$120

2005 4Q 2006 4Q MaintenanceGrowth

Utility CAPEX(in millions)

Nonutility CAPEX (in millions)

Fiscal 2006 4Q ExpendituresMaintenance Capital: $64.5 millionGrowth Capital: $38.1 million

$75.6


Capital Expenditures Capital Expenditures

$91.2

15.1 13.5

13.5

$0

$10

$20

$30

$40

2005 4Q 2006 4Q

$27.0

$15.1

24


Natural Gas Marketing Segment 2006 2005 Change

Storage Activities Realized margin ($18,375) $12,526 ($30,901)

Unrealized margin 41,631 (6,942) 48,573Total Storage Activities 23,256 5,584 17,672

Marketing Activities Realized margin 23,973 16,790 7,183

Unrealized margin 13,988 (8,800) 22,788Total Marketing Activities 37,961 7,990 29,971

GROSS PROFIT $61,217 $13,574 $47,643

Net physical position (Bcf) 14.5 6.9 7.6

Quarter Ended September 30

(In thousands, except physical position)

25

Highlights – Fiscal 2006

Natural Gas Gathering Project Natural Gas Gathering Project (map in appendix)(map in appendix)

May 10, 2006, announced plans to construct 60-mile, 20-inch natural gas gathering system in eastern KentuckyExpected to relieve severe pipeline constraints and accommodates rapidly expanding production in the region (Big Sandy)Estimated project cost is $75-$80 millionAn independent producer in the area will have ownership interest in the projectProject received exemption from regulatory oversight by the Federal Energy Regulatory Commission in early October; other required regulatory approvals pendingAnticipate construction to begin in the first half of fiscal 2007, and operations to begin in fiscal 2008

26


Louisiana Rate SettlementLouisiana Rate Settlement

May 25, 2006, Louisiana Public Service Commission (LPSC) approved settlement of several existing dockets Allows modified WNA which provides for partial decouplingRenews the Rate Stabilization Clause (RSC) with provisions reducing regulatory lag and a refund of $400,000

First RSC filing for the LGS service area made in August 2006, with an effective date of August 12, 2006, based on a test year ended December 31, 2005 First RSC filing for the Trans La service area should be made byDecember 31, 2006, for the test period ending September 30, 2006, with effective date of April 1, 2007WNA in both service areas will be effective for an initial three year period beginning with the 2006-2007 winter

Implemented new rates subject to refund in September 2006, reflecting reduction of about 26,500 customers and recovery of costs as a result of damage related to Hurricane Katrina

27


Rate Case Filing in MidRate Case Filing in Mid--Tex DivisionTex DivisionMay 31, 2006, filed for rate increase of $60 million and several rate design changes including WNA, Revenue Stabilization, and recovery of the gas cost component of bad debtJuly 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

Hearing is currently in progress and expected to continue through November 15, 2006Anticipate decision on the case by April 2007Any rate increase will be effective from the day of final order; any rate decrease will be effective from May 31, 2006 Affects approximately 1.5 million customers in Texas

28

2/6/07

February March

4/2/07

April

Second Possible RRC Conference (Decision)

First Possible RRC Conference (Oral Argument)

1/30/07Replies to Exceptions

1/23/07Exceptions Due

1/8/07Proposal for Decision (PFD) Issued

12/7/06Reply Briefs Due

11/28/06Initial Briefs Due

11/15/06Hearing on the Merits CONCLUDES

10/31/06Hearing on the Merits BEGINS

10/24/06Company Rebuttal

10/3/06Staff and IntervenorDirect Testimony

9/15/06Last Day to File Discovery in Company’s Direct Case

2007 January DecemberNovemberOctober

2006 September Event


MidMid--Tex Division Rate Case Tex Division Rate Case –– Proposed ScheduleProposed Schedule

29

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; implemented 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.

Highlights – Fiscal 2006GRIP Filings GRIP Filings –– State of TexasState of Texas

30

ACCEPT

IGNORE

DENY

SUSPEND

GRIP Filing Process in TexasGRIP Filing Process in Texas


60 days

Effective Immediately

Atmos appeals Atmos appeals to RRC within to RRC within

30 days30 days

Effective under “Operation of Law”

Up to 105

days

45 days

RRCRRCRulesRules

Atmos files Atmos files with citieswith cities

31


Rate Case Filing Rate Case Filing –– MissouriMissouriApril 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%

Total company investments approximate $22.0 million over the 9-year period

Currently in settlement discussions with commission

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

32


Rate Case Result Rate Case Result –– TennesseeTennessee

November 2005, Tennessee Regulatory Authority (TRA) began investigation into allegations by the Consumer Advocate’s Office of the Tennessee Attorney General’s Office that Atmos Energy was overcharging customers by approximately $10 million

On October 27, 2006, the TRA voted to reduce rates by $6.1 million, effective December 1, 2006

We are currently analyzing the timing of a new rate case filing

Serve approximately 125,000 residential, commercial and industrial customers in Tennessee

33

Rate Stabilization Results Rate Stabilization Results -- MississippiMississippiOctober 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, effective September 5, 2006New 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 chargeRevised WNA to include approximately 4% of additional heating degree daysReduces regulatory lag, adjusts for forward-looking known and measurable expenses and utilizes an average expected rate base Changes affect approximately 251,000 customers


34

64.7

1.8

8.2

54.7

Volumes(Bcf)

September 30, 2005September 30, 2006

Total:

Pipeline & Storage

Natural Gas Marketing

Atmos Utility

Segment

$ 461.5

13.0

63.0

$ 385.5

Balance($MM’s)

$ 5.99$ 450.8$ 6.7677.8

6.0612.17.892.6

5.80110.17.8815.3

$ 6.01$ 328.6$ 6.4359.9

WACOGBalance($MM’s)

WACOGVolumes(Bcf)


Gas Held in Underground Storage Gas Held in Underground Storage –– by Segmentby Segment

35

November 7, 2006, 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

April 1, 2006, Atmos Energy renewed its existing $18 million committed credit facility, with no material changes to terms and pricingNovember 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

On October 18, 2005, Atmos Energy entered into a $600 million, 3-year committed revolving credit facility through October 18, 2008, which serves as a backup liquidity facility for our commercial paper program


Credit FacilitiesCredit Facilities

36

Moody’s RatingSenior Unsecured Debt: Baa3Commercial Paper: P-3Outlook: stable

Standard & Poor’sSenior Unsecured Debt: BBBCommercial Paper: A-2Outlook: stable

FitchSenior Unsecured Debt: BBB+Commercial Paper: F-2Outlook: stable

Investment Grade Credit RatingsInvestment Grade Credit Ratings


37

Annual Dividend Increase Annual Dividend Increase

19th consecutive annual dividend increase

92nd consecutive dividend declared

1.6 percent annual increase from $0.315 per share to $0.32 per share each quarter

Indicated annual dividend of $1.28 per share

To be paid on December 11, 2006, to shareholders of record on November 27, 2006


38

Consolidated Financial Results – Fiscal 2007E

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

'84 '85 '86 '87 '88 '89 '90 '91 '92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07

Annual Dividend GrowthAnnual Dividend Growth

Note: Amounts are adjusted for mergers and acquisitions. For fiscal 2007, $1.28 is the indicated annual dividend.

$1.28E

39

Atmos Energy anticipates earnings to be in the range of $1.90 - $2.00 per fully diluted share for the 2007 fiscal year

Assumptions include:• Contribution from natural gas marketing segment reflects less

volatility in gas prices o Total expected gross margin contribution from the marketing segment in

the range of $75 million to $85 million, including $10 million positive mark-to-market impact

• Continued execution of rate strategy and collection efforts• Normal weather in non-WNA jurisdictions• Bad debt expense of no more than $22 million • Average short-term interest rate @ 6.3% • No material acquisitions

Earnings Guidance Earnings Guidance –– Fiscal 2007EFiscal 2007E


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 2007 significantly above or below this outlook.

40

UtilityNatural Gas Marketing Pipeline & StorageOtherTotalAvg. Diluted SharesEarnings Per Share

2005

$ 8123311

13679.0

$ 1.72

($ millions, except EPS)

2004

$ 631733

8654.4

$ 1.58

$ 88 - 8928 - 3239 - 41

2 - 3157 - 165

82.6$1.90 - $2.00

2007E

Projected Net Income by SegmentProjected Net Income by SegmentConsolidated Financial Results – Fiscal 2007E

2006

$ 5358361

14881.4

$ 1.82

41

Atmos Energy Marketing Atmos Energy Marketing –– Gross Profit Margin CompositionGross Profit Margin Composition

Marketing

(Bundled gas deliveries &peaking sales)

Marketing

(Bundled gas deliveries &peaking sales)

Asset Optimization

(Storage & transportationmanagement)

Asset Optimization

(Storage & transportationmanagement)

Total AEMMarginsTotal AEMMargins

Impacted by customer volume demand Sales prices are:

• Cost plus profit margin• Cost plus demand charges

Margins: More predictable

Impacted by gas price spread values in the market (arbitrage opportunity)Physical storage capabilitiesAvailable storage and transport capacity Margins: More variable

Total margins reflect:Stability from marketing margins Upside from optimizing our storage and transportation assets to capture arbitrage value

Margins: Stable with potential upside

2007E

$43 - $46 Million

$32 - $39 Million

$75 - $85 Million

=


42

Capital ExpendituresCapital ExpendituresIn the 2006 fiscal year, Atmos Energy spent $425.3

million in capital expenditures

For fiscal 2007, we project between $425-$440 million in capital expenditures

Approximately $251 - $262 million maintenance o Nonutility: $42 million - $47 milliono Utility: $209 million - $215 million

Approximately $174 - $178 million growth o Nonutility: $78 million - $79 milliono Utility: $96 million – $99 million


43

Minimizing Volatility With Gas Supply HedgingMinimizing Volatility With Gas Supply Hedging

For the 2006-2007 heating season, Atmos Energy is hedging approximately 49 percent of its expected winter gas utility supply requirements

22 percent are naturally hedged through a combination of owned underground storage assets and contract pipeline storage 27 percent is hedged through the use of financial derivatives (primarily futures and fixed forward contracts)

We project the weighted-average cost for storage gas and financial contracts to be approximately $7.53 per Mcf. This compares to a weighted-average cost of approximately $9.06 per Mcf for the same period last year

Hedging provides relative protection to the company and its customers against volatility in gas prices

Customers will pay a blended rate for gas costsAtmos Energy should reduce the effects of higher gas prices on its customer receivables and working capital requirements


44

Pension, PostPension, Post--Retirement & Other Benefits ExpenseRetirement & Other Benefits Expense

(in in millions))

9.7

14.2

20.1

9.3

10.6

12.8

25.3

10.4

$0.0

$10.0

$20.0

$30.0

$40.0

$50.0

$60.0

2006 2007E

OtherMedical & DentalPost-RetirementPension

$59.1


$53.3

2007 Pension Assumptions8.25% return on plan assets6.30% discount rate4.00% wage increase

45

Consolidated Financial Results2006 Fiscal Year and Fourth Quarter

46

Consolidated Income Statements –Fiscal 2006

Year Ended September 30(000s except EPS) 2006 2005

Operating Revenues:Utility Segment 3,650,591$ 3,103,140$ Natural Gas Marketing Segment 3,156,524 2,106,278 Pipeline and Storage Segment 160,567 153,289 Other Nonutility Segment 5,898 5,302 Intersegment Eliminations (821,217) (406,136)

6,152,363 4,961,873 Purchased Gas Cost:

Utility Segment 2,725,534 2,195,774 Natural Gas Marketing Segment 3,025,897 2,044,305 Pipeline and Storage Segment 838 6,811 Other Nonutility Segment - - Intersegment Eliminations (816,476) (402,654)

4,935,793 3,844,236 Gross Profit 1,216,570 1,117,637

Operation and Maintenance Expense 433,418 416,281 Depreciation and Amortization 185,596 178,005 Taxes, other than income 191,993 174,696 Impairment of Long-lived Assets 22,947 - Miscellaneous Income 881 2,021 Interest Charges 146,607 132,658 Income Before Income Taxes 236,890 218,018 Income Tax Expense 89,153 82,233 Net Income 147,737$ 135,785$ Net Income Per Share: Basic 1.83$ 1.73$ Diluted 1.82$ 1.72$ Average Shares Outstanding: Basic 80,731 78,508 Diluted 81,390 79,012

47

Consolidated Income Statements –Fiscal 2006 4Q

Three Months Ended September 30(000s except EPS) 2006 2005

Operating Revenues:Utility Segment 395,917$ 452,347$ Natural Gas Marketing Segment 673,603 632,751 Pipeline and Storage Segment 39,510 30,604 Other Nonutility Segment 1,398 1,244 Intersegment Eliminations (138,974) (115,659)

971,454 1,001,287 Purchased Gas Cost:

Utility Segment 236,628 300,593 Natural Gas Marketing Segment 612,386 619,177 Pipeline and Storage Segment 248 (2,084) Other Nonutility Segment - - Intersegment Eliminations (137,885) (114,765)

711,377 802,921 Gross Profit 260,077 198,366

Operation and Maintenance Expense 108,123 110,641 Depreciation and Amortization 48,422 45,234 Taxes, other than income 33,302 34,159 Impairment of Long-lived Assets 22,947 - Miscellaneous Income (Expense) 1,909 (846) Interest Charges 38,982 33,354 Income (Loss) Before Income Taxes 10,210 (25,868) Income Tax Expense (Benefit) 4,151 (9,066) Net Income (Loss) 6,059$ (16,802)$ Net Income (Loss) Per Share: Basic 0.07$ (0.21)$ Diluted 0.07$ (0.21)$ Average Shares Outstanding: Basic 81,073 80,030 Diluted 81,762 80,030

48

Utility Operating Income – By DivisionFiscal 2006

Year Ended September 302006 2005

Utility Operating Income Colorado-Kansas Division 22,524$ 25,157$ Kentucky Division 14,338 18,657 Louisiana Division 27,772 24,819 Mid-States Division 35,555 35,687 Mid-Tex Division 71,703 84,965 Mississippi Division 23,276 19,045 West Texas Division 2,215 27,520 Other 4,511 515 Total Utility Operating Income 201,894$ 236,365$

49

Utility Operating Income (Loss) – By DivisionFiscal 2006 4Q

Three Months Ended September 302006 2005

Utility Operating Income (Loss) Colorado-Kansas Division (899)$ (1,777)$ Kentucky Division (538) 794 Louisiana Division 2,570 (2,122) Mid-States Division (904) (1,756) Mid-Tex Division 4,280 2,963 Mississippi Division (2,204) (5,616) West Texas Division (21,838) 1,440 Other 324 (887) Total Utility Operating Income (Loss) (19,209)$ (6,961)$

50

Utility Volumes - Fiscal 2006

Year Ended September 302006 2005 Change % Change

Sales Volumes (MMcf) Residential 144,780 162,016 (17,236) (11%) Commercial 87,006 92,401 (5,395) (6%) Public authority and other 8,457 9,084 (627) (7%) Industrial 26,161 29,434 (3,273) (11%) Irrigation 5,629 3,348 2,281 68% Total 272,033 296,283 (24,250) (8%)Transportation (MMcf) 121,962 114,851 7,111 6% Total Consolidated Utility Volumes (MMcf) 393,995 411,134 (17,139) (4%)

51

Utility Volumes - Fiscal 2006 4Q

Three Months Ended September 302006 2005 Change % Change

Sales Volumes (MMcf) Residential 12,026 12,242 (216) (2%) Commercial 12,315 12,342 (27) - Public authority and other 679 639 40 6% Industrial 4,937 5,548 (611) (11%) Irrigation 2,514 2,435 79 3% Total 32,471 33,206 (735) (2%)Transportation (MMcf) 30,578 26,216 4,362 17% Total Consolidated Utility Volumes (MMcf) 63,049 59,422 3,627 6%

52

Cash Flow Statements - Fiscal 2006

2006 2005(000s)

Net income 147,737$ 135,785$ Impairment of long-lived assets 22,947 - Depreciation and amortization 185,967 178,796 Deferred income taxes 86,128 12,669 Other 18,530 11,522 Net change in operating assets and liabilities (149,860) 48,172

Operating cash flow 311,449 386,944

Acquisitions - (1,916,696) Capital expenditures - growth (138,242) (90,194) Capital expenditures - non-growth (287,082) (242,989) Other, net (5,767) (2,131)

Operating cash flow after investing activities (119,642) (1,865,066)

Repayment of long-term debt (3,264) (103,425) Settlement of Treasury lock agreements - (43,770) Dividends paid (102,275) (98,978)

Cash flow after acquisitions and growth capital (225,181)$ (2,111,239)$

Year Ended September 30

53

Capitalization - Fiscal 2006

(000s)

Short-term debt 382,416$ 9.1% 144,809$ 3.7%

Long-term debt 2,183,548 51.8% 2,186,368 55.6%

Shareholders' equity 1,648,098 39.1% 1,602,422 40.7%

Total capitalization 4,214,062$ 100.0% 3,933,599$ 100.0%

As of September 302006 2005

54

As a Reminder…

The audio and slide presentation of this conference call will be available on Atmos Energy’s Web site by 8:00 a.m. Eastern Standard Time on November 8, 2006, through midnight on February 6, 2007. Atmos Energy’s Web site address is: www.atmosenergy.com.

To listen to the live conference call, dial 800-257-1836 by 8:00 a.m. Eastern Standard Time on November 8, 2006.

55

Appendix

56

Atmos Energy Marketing

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.

Economic Value vs. GAAP Reported Results Economic Value vs. GAAP Reported Results

57

Economic Value vs. GAAP Reported ResultsEconomic Value vs. GAAP Reported Results


Reported GAAPValue

- Physical and FinancialPositions

($16.0 MM)

Reported GAAPValue


($16.0 MM)

Economic Value*(Commercial Value)


$60.0 MM

Market Spread

Embedded margindifference

$76.0 MM*Realizing Economic Value is dependent on ability toexecute – deliver physical gas & close financial hedges

Supporting data appears onthe following slide

At September 30, 2006

58

Physical Period Volume Total Total TotalEnding (Bcf) WASP WACOG EV ($ in millions) ($ per Bcf) ($ in millions) ($ per Bcf) ($ in millions)

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

9/30/2005 6.9 6.3466 4.4435 1.9031 13.1 (2.1502) (14.8) 4.0533 27.9

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

9/30/2006 14.5 11.9716 7.8329 4.1387 60.0 (1.1076) (16.0) 5.2463 76.0

Variance (4.5) 1.7363$ (0.9088)$ 2.6451$ 31.6$ 1.9221 41.7$ 0.7230$ (10.1)$

($ per Bcf)Economic Value (EV) Market SpreadGAAP Reported Value - MTM

Economic Value vs. GAAP Reported ResultsEconomic Value vs. GAAP Reported Results


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

59

Straight Creek Gathering System

Interstate transmission lines continue on to major cities in the Northeast Construction of approximately 60 miles

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

Received exemption from regulatory oversight by the Federal Energy Regulatory Commission but pending other regulatory approvals

Anticipate construction to begin in first half of fiscal 2007 with operations beginning in fiscal 2008

Atmos Pipeline and Storage

60

Atmos Pipeline - Texas

61

$14.3 million----

$13.0 million$1.3 millionKaty Capacity

Expansion/ Compression

----------------Devon Line/

Corridor Compression

$15.2 million

---

$15.2 million

2005

GRIP Filings **

$6.9 million

$4.0 million

$1.6 million

2005

CAPEX*

$83.7 million

$16.1 million

$54.6 million

2006

$75.4 million

$20.1 million

$41.0 million

2006 Northside Loop JV with Energy

Transfer

Total:

Enbridge Line/Corridor Compression

Project

Project UpdateProject Update

Estimated total annual revenues are $15.0 million. 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


62

Project Map

North SideLoop

EnbridgeCompression


atmos enerrgy 46_pres

Economy & Finance

financial results fiscal

forwardlooking statements

fiscal year

actual results

quarterfinancial results

rate increase adjustments

prior year o

statements of historical