atmos enerrgy 36_pres
TRANSCRIPT
Conference Call to ReviewFiscal 2006 Third Quarter
Financial Results
August 10, 200610:00 a.m. EDT
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 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.
3
$4.5
($18.1)($25.0)
($15.0)
($5.0)
$5.0
$15.0
3Q 2005 3Q 2006
($ in millions)($ in millions)
Key DriversKey DriversUnrealized mark-to-market losses in the natural gas marketing segmentWeather that was 31 percent warmer than normal and 29 percent warmer than the prior-year quarter, as adjusted for jurisdictions with weather-normalized rates Increase in O&M expense due to higher employee costs Increase in realized storage margins in the natural gas marketing segmentReversal of Louisiana rate adjustment deferral Rate increases associated with Texas GRIP recovery of 2003 and 2004 capital investmentIncreased 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 3Q
4
$0.06
($0.22)
($0.30)
($0.20)
($0.10)
$0.00
$0.10
3Q 2005 3Q 2006
Notes Notes Quarter-over-quarter increase of approximately 700 thousand weighted average diluted shares outstanding
Earnings per Diluted ShareEarnings per Diluted Share
Consolidated Financial Results – Fiscal 2006 3Q
5
Net Income (Loss) by SegmentNet Income (Loss) by Segment
Consolidated Financial Results – Fiscal 2006 3Q
(6.7)
2.4
8.8
(0.0)
(19.0)
(5.2)
5.8
0.1
($20.0)
($15.0)
($10.0)
($5.0)
$0.0
$5.0
$10.0
3Q 2005 3Q 2006
Utility Natural gas marketingPipeline and storage Other nonutility
($ in
mill
ions
)
6
DriversDrivers$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 adjustmentsin Mid-Tex and West Texas Divisions
Consolidated Financial Results – Fiscal 2006 3Q
7
Consolidated Financial Results – Fiscal 2006 3Q JurisdictionsJurisdictions Adjusted for WNAAdjusted 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 – AprilGeorgia October – MayMississippi November – AprilKentucky November – AprilKansas October – MayLouisiana December – March*Amarillo, TX October – MayWest Texas October – MayLubbock, TX October – MayVirginia January – December
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
8
44%
27%
35% 30%
49%
86%93%
51%
15%
13% 15%
1%
2%
31%
(120)
(80)
(40)
0
40MS CO / K
SMid-States
Kentucky
W. Texas
Louisiana
Mid-TexConsolidated
Actual / Normal Adjusted for WNA
Warmer Than Normal Weather Effect by Utility DivisionWarmer Than Normal Weather Effect by Utility Division
Perc
ent (
War
mer
) Col
der t
han
Nor
mal
Consolidated Financial Results – Fiscal 2006 3Q
• Utility gross profit in the quarter was adversely affected by $15.3 million due to weather that was 31% 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 86% and 93%, respectively
9
Drivers 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 usedto value financial hedges on physical storage inventory, coupledwith 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 withthe 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
Consolidated Financial Results – Fiscal 2006 3Q
10
Consolidated Financial Results – Fiscal 2006 3Q
Natural Gas Marketing Segment 2006 2005 Change
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) 1,715Total 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
Three Months Ended June 30
(In thousands, except physical position)
11
Consolidated Financial Results – Fiscal 2006 3Q
DriversDriversIncreased 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
12
DriversDriversIncreased 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
Consolidated Financial Results – Fiscal 2006 3Q
13
Pension, PostPension, Post--Retirement & Other Benefits ExpenseRetirement & Other Benefits Expense
(in in millions))
1.13.0
4.7
2.8
2.5
3.7
6.2
2.4
$0.0
$3.0
$6.0
$9.0
$12.0
$15.0
$18.0
3Q 2005 3Q 2006
OtherMedical & DentalPost-RetirementPension
$14.8
$11.6
Consolidated Financial Results – Fiscal 2006 3Q
2006 Pension Assumptions8.50% return on plan assets5.00% discount rate4.00% wage increase
14
22.9
57.4
21.2
54.7
$0
$25
$50
$75
$100
2005 3Q 2006 3Q MaintenanceGrowth
Utility CAPEX(in millions)
Nonutility CAPEX (in millions)
Fiscal 2006 3Q ExpendituresMaintenance Capital: $70.3 millionGrowth Capital: $39.2 million
$75.9
Consolidated Financial Results – Fiscal 2006 3Q
Capital Expenditures Capital Expenditures
$80.3
8.7 18.0
15.6
$0
$10
$20
$30
$40
2005 3Q 2006 3Q
$33.6
$9.1
15
$152.6 $141.7
$50.0
$75.0
$100.0
$125.0
$150.0
$175.0
YTD 2005 YTD 2006
($ in millions)($ in millions)
Key DriversKey DriversIncreased contribution from nonutility businesses, primarily natural gas marketing segment, due to higher margins and market volatilityYear to date, weather was 13% warmer than normal and 3% warmer than the prior year period, as adjusted for jurisdictions with weather-normalized ratesAbsence in fiscal 2006 of accelerated acquisition synergies realized in fiscal 2005Increase in O&M expenses due to higher employee-related costsGRIP rate adjustments in Texas effective in 2006
Net IncomeNet Income
(7%)
Consolidated Financial Results – Fiscal YTD
16
$1.94
$1.75
$1.25
$1.50
$1.75
$2.00
YTD 2005 YTD 2006
NotesNotesPeriod-over-period increase of 2.5 million weighted average diluted shares outstanding
Earnings per Diluted ShareEarnings per Diluted ShareConsolidated Financial Results – Fiscal YTD
(10%)
17
Net Income by SegmentNet Income by Segment
Consolidated Financial Results – Fiscal YTD
104.0
19.4 28.6
0.6
84.1
28.2 29.1
0.3
$0.0
$20.0
$40.0
$60.0
$80.0
$100.0
YTD 2005 YTD 2006Utility Natural gas marketingPipeline and storage Other nonutility
($ in
mill
ions
)
18
DriversDrivers$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
Consolidated Financial Results – Fiscal YTD
19
8% 10% 10% 10%
15%
22%
28%
19%
2%
2%
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
• Year to date gross profit was adversely affected by $47.5 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 DivisionConsolidated Financial Results – Fiscal YTD
20
$1.04
$1.36 $1.33
2,507
2,580
3,249
$0.75
$1.00
$1.25
$1.50
YTD 2004 YTD 2005 YTD 20062,250
2,500
2,750
3,000
3,250
EPS Degree Days*
Consolidated Financial Results – Fiscal YTD
Relationship of Relationship of Utility EPSUtility EPS to Heating Degree Daysto Heating Degree Days
*Adjusted for WNA
21
DriversDrivers$37.2 million increase in gross profit (continued)
$21.0 million increase in natural gas marketing gross profit primarily due too $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 increasedmarket 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
Consolidated Financial Results – Fiscal YTD
22
Consolidated Financial Results – Fiscal YTD
Natural Gas Marketing Segment 2006 2005 Change
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) 7,671Total 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
Nine Months Ended June 30
(In thousands, except physical position)
23
Consolidated Financial Results- Fiscal YTD
Fair Value of Contracts at June 30, 2006 Maturity in Years Source of Fair Value
< 1
1 - 3
4 - 5
> 5
Total FairValue
(In thousands) Prices actively quoted $ (15,365)
$(8,715) $ — $ — $ (24,080)
Prices provided by other external sources
2,519
(50) — — 2,469
Prices based on models &
other valuation methods
(285)
(270) — — (555) Total Fair Value $ (13,131) $(9,035) $ — $ — $ (22,166)
24
Drivers 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
Consolidated Financial Results – Fiscal YTD
25
Consolidated Financial Results – Fiscal YTD
DriversDriversIncreased 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
26
Pension, PostPension, Post--Retirement & Other Benefits ExpenseRetirement & Other Benefits Expense
(in in millions))
3.7
9.6
12.3
7.8
7.5
11.3
16.7
7.5
$0.0
$10.0
$20.0
$30.0
$40.0
$50.0
YTD 2005 YTD 2006
OtherMedical & DentalPost-RetirementPension
$43.0
$33.4
Consolidated Financial Results – Fiscal YTD
2006 Pension Assumptions8.50% return on plan assets5.00% discount rate4.00% wage increase
27
1.86
0.0
0.83
0.29
0.580.55
0.0
0.5
1.0
1.5
2.0
2001 2002 2003 2004 2005 2006YTD
Perc
ent
Utility Bad Debt Expense as a Percent of RevenuesUtility Bad Debt Expense as a Percent of Revenues
Consolidated Financial Results – Fiscal YTD
28
DriversDriversIncreased 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
Consolidated Financial Results – Fiscal YTD
29
64.1
145.3
64.5
167.6
$0
$50
$100
$150
$200
$250
$300
2005 YTD 2006 YTD MaintenanceGrowth
Utility CAPEX(in millions)
Nonutility CAPEX (in millions)
Fiscal 2006 YTD ExpendituresMaintenance Capital: $222.6 millionGrowth Capital: $100.1 million
$232.1
Consolidated Financial Results – Fiscal YTD
Capital Expenditures Capital Expenditures
$209.4
17.0 35.6
55.0
$0
$20
$40
$60
$80
$100
$120
2005 YTD 2006 YTD
$90.6
$17.5
30
Highlights – Fiscal YTD
Natural Gas Gathering Project Natural Gas Gathering Project -- (map in Appendix) (map in Appendix)
May 10, 2006, announced plans to construct a 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 is pending all required regulatory approvals, including exemption from regulatory oversight by the Federal Energy Regulatory CommissionAnticipate construction to begin in the first half of fiscal 2007, and operations to begin in fiscal 2008
31
Highlights – Fiscal YTD
Louisiana Rate SettlementLouisiana Rate SettlementMay 25, 2006, Louisiana Public Service Commission (LPSC) approved settlement of several existing dockets Allows modified WNA which provides 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 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, 2007WNA in both service areas will be effective for an initial three year period beginning with the 2006-2007 winter
32
Highlights – Fiscal YTD
Rate Case Filing in MidRate Case Filing in Mid--Tex DivisionTex DivisionMay 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 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
Anticipate decision on the case in first quarter of calendar 2007Any 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
33
Event2006
September October November December2007
January February Last Day to File Discovery in Company’s Direct Case
9/15/06
Staff and Intervenor Direct Testimony
10/3/06
Company Rebuttal 10/24/06
Hearing on the Merits BEGINS 10/31/06
Hearing on the Merits CONCLUDES
11/10/06
Initial Briefs Due 11/28/06
Reply Briefs Due 12/7/06
Proposal for Decision (PFD) Issued
1/8/07
Exceptions Due 1/23/07
Replies to Exceptions 1/30/07
First Possible RRC Conference (Oral Argument)
2/6/07
Second Possible RRC Conference (Decision)
2/20/07
As of July 6, 2006Source: Railroad Commission of Texas
Highlights – Fiscal YTD
MidMid--Tex Division Rate Case Tex Division Rate Case –– Proposed ScheduleProposed Schedule
34
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.
Highlights – Fiscal YTDGRIP Filings GRIP Filings –– State of TexasState of Texas
35
ACCEPT
IGNORE
DENY
SUSPEND
GRIP Filing Process in TexasGRIP Filing Process in Texas
60 days
Effective Immediately
Highlights – Fiscal YTD
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
36
Highlights – Fiscal YTD
Rate Case Filing Rate Case Filing –– MissouriMissouri
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
37
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, beginning 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 $10 million in annual margins from volumetric to customer chargeRevised WNA to include approximately 4% of additional heating degree daysReduces regulatory lag, adjusts for forward-looking known and measurable expenses and utilizes an average expected rate base Changes affect approximately 251,000 customers
Highlights – Fiscal YTD
38
June 30, 2006 June 30, 2005
Volumes(Bcf)
40.0
15.2
2.8
58.0
Segment Balance($MM’s)
Volumes(Bcf)
WACOG Balance($MM’s)
WACOG
Atmos Utility
Natural Gas Marketing
Pipeline & Storage
Total:
46.7 $ 6.54 $ 221.1 $ 5.53$ 305.4
114.9
16.8
20.1 8.62 94.8 6.01
2.5 8.56 18.3 6.54
$ 437.1 69.3 $ 7.22 $ 334.2 $ 5.70
Highlights – Fiscal YTD
Gas Held in Underground Storage Gas Held in Underground Storage –– by Segmentby Segment
39
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
Highlights – Fiscal YTD
Credit FacilitiesCredit Facilities
40
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
Highlights – Fiscal YTD
41
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
Quarterly DividendQuarterly DividendHighlights – Fiscal YTD
42
$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
Note: Amounts are adjusted for mergers and acquisitions.
$1.26
Annual Dividend Growth Annual Dividend Growth -- 1984 to 20061984 to 2006
Consolidated Financial Results – Fiscal 2006E
43
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
volatilityo Expected gross margin contribution from the marketing segment in the range of
$85 million to $95 milliono 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
Earnings Guidance Earnings Guidance –– 2006 Fiscal Year2006 Fiscal Year
Consolidated Financial Results – Fiscal 2006E
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.
44
Net Income by SegmentNet Income by Segment
UtilityNatural Gas Marketing Pipeline & StorageOtherTotalAvg. Diluted SharesEarnings Per Share
2005
$ 8123311
13679.0
$ 1.72
($ millions, except EPS) 2004
$ 631733
8654.4
$ 1.58
$ 75 - 8039 - 4131 - 32
1 - 2146 - 155
81.3$1.80 - $1.90
2006E2003
$ 62(1)
74
7246.5
$ 1.54
Consolidated Financial Results – Fiscal 2006E
45
90
211
90-94
183-189
$0
$50
$100
$150
$200
$250
$300
$350
2005 2006E MaintenanceGrowth
Estimated Capital Expenditures Estimated Capital Expenditures –– 2006 Fiscal Year2006 Fiscal Year
Utility CAPEX(in millions)
2 30
90-93
37-39
$0$20$40
$60$80
$100
$120$140
2005 2006E
Nonutility CAPEX (in millions)
$301 $273-$283 $127-$132
$32
Consolidated fiscal 2006 CAPEX projection is $400-$415 million
Consolidated Financial Results – Fiscal 2006E
46
Pension, PostPension, Post--Retirement & Other Benefits ExpenseRetirement & Other Benefits Expense
(in millions)in millions)
4.7
12.8
16.8
10.0
9.6
13.4
22.2
6.7
$0.0
$10.0
$20.0
$30.0
$40.0
$50.0
$60.0
2005 2006E
OtherMedical & DentalPost-RetirementPension
$51.9$44.3
Consolidated Financial Results – Fiscal 2006E
2006 Pension Assumptions8.50% return on plan assets5.00% discount rate4.00% wage increase
47
Consolidated Financial ResultsFiscal 2006 3Q
48
Consolidated Income Statements –Fiscal 2006 3Q
Three Months Ended June 30(000s except EPS) 2006 2005
Operating Revenues:Utility Segment 402,044$ 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 - - Intersegment Eliminations (137,161) (95,606)
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
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Consolidated Income Statements –Fiscal 2006 YTD
Nine Months Ended June 30(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 Intersegment Eliminations (682,243) (290,477)
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 - - Intersegment Eliminations (678,591) (287,889)
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
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Utility Operating Income (Loss) – By DivisionFiscal 2006 3Q
Three Months Ended June 302006 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 Mid-Tex Division (12,819) 2,432 Mississippi Division (1,265) (2,455) West Texas Division 4,383 4,992 Other 1,018 403 Total Utility Operating Income (Loss) (2,910)$ 15,041$
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Utility Operating Income – By DivisionFiscal 2006 YTD
Nine Months Ended June 302006 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 Mid-Tex Division 67,423 82,002 Mississippi Division 25,480 24,661 West Texas Division 24,053 26,080 Other 4,187 1,402 Total Utility Operating Income 221,103$ 243,326$
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Utility Volumes - Fiscal 2006 3Q
Three Months Ended June 302006 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%)Transportation (MMcf) 29,630 28,753 877 3% Total Consolidated Utility Volumes (MMcf) 62,283 72,678 (10,395) (14%)
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Utility Volumes - Fiscal 2006 YTD
Nine Months Ended June 302006 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%)Transportation (MMcf) 91,384 88,635 2,749 3% Total Consolidated Utility Volumes (MMcf) 330,946 351,712 (20,766) (6%)
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Cash Flow Statements - Fiscal 2006 YTD
2006 2005(000s)
Net income 141,678$ 152,587$ 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
Operating cash flow 223,443 387,410
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)
Operating cash flow after investing activities (104,059) (1,757,743)
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 and growth capital (183,236)$ (1,978,362)$
Nine Months Ended June 30
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Capitalization - Fiscal 2006 YTD
(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%
As of June 302006 2005
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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.
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Appendix
58
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 ResultsEconomic Value vs. GAAP Reported Results
59
Economic Value vs. GAAP Reported ResultsEconomic Value vs. GAAP Reported Results
Atmos Energy Marketing
Reported GAAPValue
- Physical and FinancialPositions
($57.7 MM)
Reported GAAPValue
- Physical and FinancialPositions
($57.7 MM)
Economic Value*(Commercial Value)
- Physical and FinancialPositions
$28.4 MM
Market Spread
Embedded margindifference
$86.1 MM*Realizing Economic Value is dependent on ability toexecute – deliver physical gas & close financial hedges
Supporting data appears onthe following slideAt June 30, 2006
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Physical Period Volume Total Total TotalEnding (Bcf) WASP WACOG EV ($ in millions) ($ per mmbtu) ($ in millions) ($ per mmbtu) ($ in millions)
3/31/2005 12.5 7.1916 6.5459 0.6457 8.0 (0.7044) (8.8) 1.3501 16.8
6/30/2005 14.1 7.7606 6.5967 1.1639 16.4 (0.5559) (7.8) 1.7198 24.2
3/31/2006 23.6 10.3880 9.0806 1.3074 30.8 (1.5195) (35.8) 2.8269 66.6
6/30/2006 19.0 10.2353 8.7417 1.4936 28.4 (3.0297) (57.7) 4.5233 86.1
Variance (4.6) (0.1527)$ (0.3389)$ 0.1862$ (2.4)$ (1.5105) (21.9)$ 1.6967$ 19.5$
($ per mmbtu)Economic Value (EV) Market SpreadGAAP Reported Value - MTM
Economic Value vs. GAAP Reported ResultsEconomic Value vs. GAAP Reported Results
Atmos Energy Marketing
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
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Straight Creek Gathering Straight Creek Gathering SystemSystem
Interstate transmission lines continue on to major cities in the Northeast Construction of approximately 65 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
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
Atmos Pipeline and Storage
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Atmos Pipeline - Texas
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CAPEX* GRIP Filings **Actual
2005 2005
$15.2 million
---
Devon Line/ Corridor
Compression---- ---- ---- ----
Katy Capacity Expansion/
Compression$1.3 million $13.7 million
----$15.0 million
$15.2 million
$1.6 million
$4.0 million
$6.9 million
Project Estimated
2006 2006 Northside Loop JV with Energy
Transfer$36.2 million$49.8 million
$17.8 million
$81.3 million
$21.8 million
$73.0 million
Enbridge Line/Corridor Compression
Total:
Project UpdateProject Update
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
Atmos Pipeline - Texas
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Project Map
North SideLoop
EnbridgeCompression