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atmos enerrgy 36_pres atmos enerrgy 36_pres Presentation Transcript

  • 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
  • Consolidated Financial Results – Fiscal 2006 3Q 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
  • Consolidated Financial Results – Fiscal 2006 3Q 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
  • Consolidated Financial Results – Fiscal 2006 3Q 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
  • Consolidated Financial Results – Fiscal 2006 3Q 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
  • Consolidated Financial Results – Fiscal 2006 3Q 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
  • Consolidated Financial Results – Fiscal 2006 3Q 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
  • Consolidated Financial Results – Fiscal 2006 3Q 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
  • Consolidated Financial Results – Fiscal 2006 3Q 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
  • Consolidated Financial Results – Fiscal 2006 3Q 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
  • Consolidated Financial Results – Fiscal 2006 3Q 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
  • Consolidated Financial Results – Fiscal 2006 3Q 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
  • Consolidated Financial Results – Fiscal YTD 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
  • Consolidated Financial Results – Fiscal YTD 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
  • Consolidated Financial Results – Fiscal YTD 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
  • Consolidated Financial Results – Fiscal YTD 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
  • Consolidated Financial Results – Fiscal YTD 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
  • Consolidated Financial Results – Fiscal YTD 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
  • Consolidated Financial Results – Fiscal YTD 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
  • Consolidated Financial Results – Fiscal YTD 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
  • Consolidated Financial Results – Fiscal YTD 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
  • Consolidated Financial Results – Fiscal YTD Pension, Post-Retirement & Other Benefits Expense (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
  • Consolidated Financial Results – Fiscal YTD 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
  • Consolidated Financial Results – Fiscal YTD 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
  • Consolidated Financial Results – Fiscal YTD Capital Expenditures Utility CAPEX Nonutility CAPEX (in millions) (in millions) $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
  • Highlights – Fiscal YTD 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
  • Highlights – Fiscal YTD 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
  • Highlights – Fiscal YTD 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
  • Highlights – Fiscal YTD 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
  • Highlights – Fiscal YTD 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
  • Highlights – Fiscal YTD 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
  • Highlights – Fiscal YTD 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 $10 million in annual margins from volumetric to customer charge Revised WNA to include approximately 4% of additional heating degree days Reduces regulatory lag, adjusts for forward-looking known and measurable expenses and utilizes an average expected rate base Changes affect approximately 251,000 customers 37
  • Highlights – Fiscal YTD Gas Held in Underground Storage – by Segment June 30, 2006 June 30, 2005 Segment Balance Volumes WACOG Balance Volumes WACOG ($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
  • Highlights – Fiscal YTD 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
  • Highlights – Fiscal YTD 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
  • Highlights – Fiscal YTD 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
  • Consolidated Financial Results – Fiscal 2006E 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 $415 million Note: Changes in these events or other circumstances that the company cannot currently anticipate could materially impact earnings, and could result in earnings for fiscal 2006 significantly above or below this outlook. 43
  • Consolidated Financial Results – Fiscal 2006E Net Income by Segment 2006E 2004 2003 2005 ($ 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
  • Consolidated Financial Results – Fiscal 2006E Estimated Capital Expenditures – 2006 Fiscal Year Utility CAPEX Nonutility CAPEX (in millions) (in millions) $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
  • Consolidated Financial Results – Fiscal 2006E Pension, Post-Retirement & Other Benefits Expense (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 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 48
  • 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 49
  • Utility Operating Income (Loss) – By Division Fiscal 2006 3Q Three Months Ended June 30 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 Nine Months Ended June 30 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 Three Months Ended June 30 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 Nine Months Ended June 30 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 Nine Months Ended June 30 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
  • Appendix 57
  • 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
  • Atmos Energy Marketing Economic Value vs. GAAP Reported Results 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 $86.1 MM is dependent on ability to execute – deliver physical gas & close financial hedges Supporting data appears on the following slide At June 30, 2006 59
  • Atmos Energy Marketing Economic Value vs. GAAP Reported Results Physical Economic Value (EV) GAAP Reported Value - MTM Market Spread ($ 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