atmos enerrgy 26_pres

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atmos enerrgy 26_pres

  1. 1. Conference Call to Review Fiscal 2006 Second Quarter Financial Results May 5, 2006 9:00 a.m. EDT
  2. 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-month period ended December 31, 2005. 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
  3. 3. Consolidated Financial Results – Fiscal 2006 2Q Net Income Key Drivers Increased contribution from natural gas marketing segment Weather was 16% warmer than normal and 6% warmer than the prior-year quarter, as adjusted for jurisdictions with $88.8 $88.5 weather-normalized rates $100.0 Net increase in sales taxes Increased interest expense due to higher $75.0 average short-term debt balances and an increase in the 3-month LIBOR rate Increase in O&M expense due to higher employee costs $50.0 Increase in bad debt expense due to higher customer bills from higher gas prices $25.0 2Q 2005 2Q 2006 Rate increases associated with Texas GRIP recovery of 2003 and 2004 capital investment ($ in millions) 3
  4. 4. Consolidated Financial Results – Fiscal 2006 2Q Earnings per Diluted Share $1.11 $1.10 $1.20 Notes $1.00 Quarter-over-quarter increase of 1.3 million weighted average $0.80 diluted shares outstanding $0.60 $0.40 2Q 2005 2Q 2006 4
  5. 5. Consolidated Financial Results – Fiscal 2006 2Q Net Income by Segment 73.7 $80.0 54.7 $60.0 ($ in millions) $40.0 21.9 12.1 3.8 10.6 $20.0 0.4 0.1 $0.0 2Q 2005 2Q 2006 Utility Natural gas marketing Pipeline and storage Other nonutility 5
  6. 6. Consolidated Financial Results – Fiscal 2006 2Q Drivers $29.5 million increase in gross profit $7.4 million decrease in utility gross profit primarily due to o $14.7 million decrease primarily due to a 17.2 Bcf decrease in throughput, as a result of weather that was 6 percent warmer than last year o $1.4 million decrease due to the impact of Hurricane Katrina in the Louisiana Division o $6.4 million increase in transportation margins o $2.9 million increase from GRIP rate adjustments in Mid-Tex and West Texas Divisions 6
  7. 7. Consolidated Financial Results – Fiscal 2006 2Q Weather Adjusted for WNA Jurisdictions For the second quarter of fiscal 2006, weather was 16 percent warmer than normal, and 6 percent warmer than the same period last year, as adjusted for jurisdictions with weather-normalized operations At March 31, 2006, we had WNA in the following service areas for the following periods as noted, which covered approximately 1.1 million of our meters in service: Tennessee November – April Georgia October – May Mississippi November – April* Kentucky November – April Kansas October – May Amarillo, TX October – May October – May West Texas Lubbock, TX October – May January – December Virginia *Effective in fiscal 2006, WNA period was 11/1 – 4/30. Prior to October 1, 2005, WNA period was 11/15 – 5/15. 7
  8. 8. Consolidated Financial Results – Fiscal 2006 2Q Warmer Than Normal Weather Effect by Utility Division ted es da a ky s t at ia n li xa x S tuc - Te so /K S Te uis d- n n d W. MS Mi Mi CO Ke Co Lo 10 • Utility gross profit in the quarter was Percent (Warmer) Colder than Normal adversely affected 0% 0% 0% 0% by $24.3 million due 0 to weather that was 16% warmer than normal, as adjusted 7% for jurisdictions with (10) weather-normalized 11% rates 14% 14% • Louisiana and Mid- 16% 16% 17% Tex Divisions do not (20) have weather- normalized rates, 23% and experienced warmer than normal (30) weather of 30% and 30% 32%, respectively 32% (40) Actual / Normal Adjusted for WNA 8
  9. 9. Consolidated Financial Results – Fiscal 2006 2Q Relationship of Diluted EPS to Heating Degree Days* Degree Days* EPS $1.20 $1.12 2,250 $1.11 $1.10 2,000 $1.00 1,772 1,750 $0.80 1,422 1,500 1,330 $0.60 1,250 $0.40 1,000 $0.20 750 2Q 2004 2Q 2005 2Q 2006 *Adjusted for WNA 9
  10. 10. Consolidated Financial Results – Fiscal 2006 2Q Drivers $29.5 million increase in gross profit (continued) $4.2 million increase in pipeline and storage gross profit primarily due to favorable arbitrage spreads and higher transportation & services margins, offset by 8.0 Bcf decrease in transportation volumes, before intersegment eliminations, due to warmer than normal weather in the Mid-Tex Division $32.8 million increase in natural gas marketing gross profit primarily due to o $23.3 million increase in unrealized storage mark-to-market gains primarily due to favorable movement in the forward prices used to value financial hedges on physical storage inventory and fixed-price forward contracts, coupled with an increase in physical storage position of 11.1 Bcf quarter-over-quarter o $9.8 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 $4.1 million decrease in realized storage contribution due to warmer weather which resulted in fewer withdrawal opportunities compared with the prior-year quarter o $3.8 million increase in realized marketing margins primarily due to higher margins realized on increased volumes sold of 2.9 Bcf quarter- over-quarter 10
  11. 11. Consolidated Financial Results – Fiscal 2006 2Q Three Months Ended March 31 Natural Gas Marketing Segment 2006 2005 Change (In thousands, except physical position) Storage Activities Realized margin $10,611 $14,669 ($4,058) Unrealized margin 2,741 (20,545) 23,286 Total Storage Activities 13,352 (5,876) 19,228 Marketing Activities Realized margin 21,005 17,236 3,769 Unrealized margin 9,620 (200) 9,820 Total Marketing Activities 30,625 17,036 13,589 GROSS PROFIT $43,977 $11,160 $32,817 Net physical position (Bcf) 23.6 12.5 11.1 11
  12. 12. Consolidated Financial Results – Fiscal 2006 2Q Drivers Increased O&M expenses of $9.3 million primarily due to $4.8 million net 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 $4.5 million increase in provision for doubtful accounts primarily due to increased collection risk on higher customer bills caused by higher gas prices 12
  13. 13. Consolidated Financial Results – Fiscal 2006 2Q Drivers Increased taxes, other than income, of $9.8 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 $2.4 million $3.6 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 Increased miscellaneous expense of $3.4 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 associated with gas purchases 13
  14. 14. Consolidated Financial Results – Fiscal 2006 2Q Pension, Post-Retirement & Other Benefits Expense (in millions) $14.2 Other $16.0 Medical & Dental $14.0 $10.7 2.5 Post-retirement $12.0 Pension $10.0 2.6 5.2 $8.0 3.3 $6.0 2006 Pension Assumptions 3.9 8.50% return on plan assets $4.0 3.4 5.00% discount rate 4.00% wage increase $2.0 2 .6 1.4 $0.0 2Q 2005 2Q 2006 14
  15. 15. Consolidated Financial Results – Fiscal 2006 2Q Capital Expenditures Utility CAPEX Nonutility CAPEX (in millions) (in millions) $83.8 $40 $100 $26.9 $63.2 $30 $75 59.7 $20 $50 41.2 24.7 $7.1 $10 $25 24.1 22.0 2.2 $0 $0 2005 2Q 2006 2Q 2005 2Q 2006 2Q Maintenance Growth Fiscal 2006 2Q Expenditures Maintenance Capital: $84.4 million 15 Growth Capital: $26.3 million
  16. 16. Consolidated Financial Results – Fiscal YTD Key Drivers Net Income Increased contribution from nonutility businesses, primarily natural gas marketing segment, due to higher margins and market volatility Higher interest expense due to $159.8 8% higher average short-term debt $175.0 $148.1 balances used to fund higher- priced natural gas purchases $150.0 Year to date, weather was 12% warmer than normal and 1% $125.0 warmer than the prior-year period, as adjusted for jurisdictions with $100.0 weather normalized rates $75.0 Increase in provision for doubtful accounts $50.0 Lost margin and increased O&M YTD 2005 YTD 2006 expenses related to Hurricane Katrina ($ in millions) GRIP rate adjustments in Texas effective in 2006 16
  17. 17. Consolidated Financial Results – Fiscal YTD Earnings per Diluted Share $2.25 Notes 4% $1.98 $1.90 $2.00 Period-over-period increase of 3.1 million weighted average $1.75 diluted shares outstanding $1.50 $1.25 YTD 2005 YTD 2006 17
  18. 18. Consolidated Financial Results – Fiscal YTD Net Income by Segment 110.7 $125.0 103.0 $100.0 ($ in millions) $75.0 33.4 $50.0 23.3 19.7 17.1 $25.0 0.1 0.6 $0.0 YTD 2005 YTD 2006 Utility Natural gas marketing Pipeline and storage Other nonutility 18
  19. 19. Consolidated Financial Results – Fiscal YTD Drivers $54.0 million increase in gross profit $15.5 million increased utility gross profit primarily from o $20.3 million increase from higher franchise fees and gross receipts taxes paid by the customer, primarily in the Mid-Tex Division o $5.9 million decrease primarily due to decreased throughput of 10.3 Bcf, due to weather that was 1 percent warmer than the prior-year period o $4.1 million increase due to rate adjustments resulting from the GRIP-related recovery for 2003 and 2004 capital expenditures in Mid-Tex Division o $0.4 million increase due to rate adjustments from GRIP filings in West Texas Division o $3.5 million decrease due to the impact of Hurricane Katrina 19
  20. 20. Consolidated Financial Results – Fiscal YTD Utility Margin Sensitivity 2004–2006E 2003–2004 Heating Season Heating Season (Post-TXU Gas Acquisition) (Prior to TXU Gas Acquisition) 35% 36% 48% 51% 13% 17% Weather Weather- Nonweather- Normalized Sensitive Margin Sensitive Margin* * 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 20
  21. 21. Consolidated Financial Results – Fiscal YTD YTD Warmer than Normal Weather Effect by Division ted s i da a ate ky s ia n xa ex S ol tuc St /K Te uis d- T s d- n n W. MS Mi Mi CO Ke Co Lo 10 • Year to date gross profit was adversely Percent (Warmer) Colder than Normal affected by $32.3 1% 0% 0% 0% million due to 0 weather that was 12% warmer than normal, as adjusted 4% for jurisdictions with 6% weather-normalized 7% 8% 8% rates (10) • Louisiana and Mid- 12% Tex Divisions do not 13% have weather- 16% normalized rates, and experienced (20) warmer than normal 20% weather of 20% and 26%, respectively 26% (30) Actual / Normal Adjusted for WNA 21
  22. 22. Consolidated Financial Results – Fiscal YTD Mid-Tex Division Estimated Annual Earnings Impact of Warmer Than Normal Weather* Percent Warmer than Normal 5% 10% 15% 20% $0.00 ($0.02) ($0.04) EPS Impact ($.05) ($0.06) ($0.08) ($.09) ($0.10) ($0.12) ($.12) ($0.14) ($0.16) ($.16) *Reflects changes in gross profit and related changes in bad debt and state and federal taxes 22
  23. 23. Consolidated Financial Results – Fiscal YTD Relationship of EPS to Heating Degree Days Degree Days* EPS $1.98 $2.00 3,500 $1.90 3,250 $1.69 $1.75 3,012 3,000 $1.50 2,750 $1.25 2,415 2,500 2,387 $1.00 2,250 $0.75 2,000 YTD 2004 YTD 2005 YTD 2006 *Adjusted for WNA 23
  24. 24. Consolidated Financial Results – Fiscal YTD Drivers $54.0 million increase in gross profit (continued) $32.3 million increase in natural gas marketing gross profit primarily due to o $19.7 million increase in realized marketing margins primarily due to increased volumes sold of 14.0 Bcf year over year and capturing higher margins in certain market areas that experienced increased volatility o $19.6 million increase in realized storage contribution primarily due to favorable arbitrage spreads as a result of increased market volatility period over period o $13.0 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 and fixed-price forward contracts, coupled with an increase in physical storage positions of 11.1 Bcf period-over-period o $6.0 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 24
  25. 25. Consolidated Financial Results – Fiscal YTD Six Months Ended March 31 Natural Gas Marketing Segment 2006 2005 Change (In thousands, except physical position) Storage Activities Realized margin $36,883 $17,259 $19,624 Unrealized margin (21,051) (8,027) (13,024) Total Storage Activities 15,832 9,232 6,600 Marketing Activities Realized margin 50,572 30,835 19,737 Unrealized margin 3,892 (2,063) 5,955 Total Marketing Activities 54,464 28,772 25,692 GROSS PROFIT $70,296 $38,004 $32,292 Net physical position (Bcf) 23.6 12.5 11.1 25
  26. 26. Consolidated Financial Results- Fiscal YTD Fair Value of Contracts at March 31, 2006 Maturity in Years Total Fair Source of Fair Value <1 1-3 4-5 >5 Value (In thousands) $ — $ —$ Prices actively quoted $ 6,607 $(1,396) 5,211 Prices provided by other — external sources 4,492 (196) — 4,296 Prices based on models & other valuation methods (300) (269) — — (569) $ $ —$ — Total Fair Value $ 10,799 $(1,861) 8,938 26
  27. 27. Consolidated Financial Results – Fiscal YTD Drivers $54.0 million increase in gross profit (continued) $ 6.4 million increase in pipeline and storage gross profit o $9.4 million due to favorable arbitrage spreads coupled with a 9.0 Bcf increase in total transportation volumes and higher transportation & services margins, offset by o $3.0 million decrease due to the absence of inventory sales year over year 27
  28. 28. Consolidated Financial Results – Fiscal YTD Drivers Increased O&M expenses of $6.7 million primarily due to $5.8 million increase in provision for doubtful accounts primarily due to increased collection risk associated with higher gas prices $2.0 million increase in Hurricane Katrina related losses $0.9 million increase due to higher administrative costs year over year $2.1 million decrease due to absence of UCG acquisition-related M&I costs which became fully amortized in December 2004 28
  29. 29. Consolidated Financial Results – Fiscal YTD Pension, Post-Retirement & Other Benefits Expense (in millions) Other $28.2 $35.0 Medical & Dental $22.2 $30.0 Post-retirement 5.1 $25.0 Pension 5.1 $20.0 10.5 $15.0 7.7 2006 Pension Assumptions $10.0 8.50% return on plan assets 7.6 5.00% discount rate 6.8 $5.0 4.00% wage increase 5 .0 2 .6 $0.0 YTD 2005 YTD 2006 29
  30. 30. 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 30
  31. 31. Consolidated Financial Results – Fiscal YTD Drivers Increased taxes, other than income, of $16.6 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 $6.1 million $8.5 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 $2.4 million decrease in interest charges from the early payoff of $72.5 million of First Mortgage Bonds in June 2005 Increased miscellaneous expense of $3.3 million $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 31
  32. 32. Consolidated Financial Results – Fiscal YTD Capital Expenditures Utility CAPEX Nonutility CAPEX (in millions) (in millions) $80 $200 $156.2 $57.0 $129.1 $60 $150 $40 $100 112.9 39.4 87.9 $8.4 $20 $50 17.6 41.2 43.3 $0 $0 2005 YTD 2006 YTD 2005 YTD 2006 YTD Maintenance Growth Fiscal 2006 YTD Expenditures Maintenance Capital: $152.3 million 32 Growth Capital: $ 60.9 million
  33. 33. Highlights – Fiscal YTD Senior Leadership Changes April 13, 2006, Atmos Energy announced Kim R. Cocklin to succeed R. Earl Fischer as senior vice president, utility operations Earl Fischer will be retiring October 1, 2006 Kim Cocklin, who joins Atmos Energy from Piedmont Natural Gas Company, will begin transitioning this summer March 31, 2006, Atmos Energy named Mark H. Johnson to succeed the retiring JD Woodward as senior vice president, nonutility operations, effective April 1, 2006 Johnson previously held the position of vice president, nonutility operations and president of Atmos Energy Marketing, LLC 33
  34. 34. Highlights – Fiscal YTD Rate Case Filing – Missouri April 7, 2006, filed 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 34
  35. 35. Highlights – Fiscal YTD GRIP Filings – State of Texas April 13, 2006, Atmos Pipeline-Texas 2005 GRIP filing of $3.4 million revenue increase related to return and capital-related expenses on $22.1 million in net investment during calendar 2005 March 31, 2006, Mid-Tex Division 2005 GRIP filing of $12.1 million related to return and capital-related expenses on $63.6 million increase in net investment during calendar 2005 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, subsequently 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, subsequently 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. 35
  36. 36. 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 36
  37. 37. 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 $10 million in annual margins from volumetric to customer charge Revised WNA to include approximately 4% of additional heating degree days Reduced regulatory lag, adjusts for forward-looking known and measurable expenses and utilizes an average expected rate base Changes affect approximately 251,000 customers 37
  38. 38. Highlights – Fiscal YTD Gas Held in Underground Storage March 31, 2006 March 31, 2005 Segment Balance Volumes WACOG Balance Volumes WACOG ($MM’s) (Bcf) ($MM’s) (Bcf) Atmos Utility $ 267.1 38.8 $ 6.88 $ 180.6 35.1 $ 5.15 Natural Gas 158.4 23.2 6.83 77.4 11.4 6.79 Marketing Pipeline & Storage 15.5 2.1 7.38 15.8 2.7 5.85 Total: $ 441.0 64.1 $ 6.88 $ 273.8 49.2 $ 5.57 38
  39. 39. 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 the existing $18 million committed credit facility, with no material changes to terms and pricing 39
  40. 40. 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
  41. 41. Consolidated Financial Results – Fiscal 2006E Annual Dividend Growth - 1984 to 2006E $1.26 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 '8 '8 '8 '8 '8 '8 '9 '9 '9 '9 '9 '9 '9 '9 '9 '9 '0 '0 '0 '0 '0 '0 '0 4 5 6 7 8 9 0 1 2 3 4 5 6 7 8 9 0 1 2 3 4 5 6 Note: Amounts are adjusted for mergers and acquisitions. For fiscal 2006, $1.26 is the indicated annual dividend. 41
  42. 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 $80 million to $90 million o No material mark-to-market impact at 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 $415 million Note: Changes in these events or other circumstances that the company cannot currently anticipate could materially impact earnings, and could result in earnings for fiscal 2006 significantly above or below this outlook. 42
  43. 43. Consolidated Financial Results – Fiscal 2006E Selected Income Statement Components ($ in millions) 1200 2006E Consolidated 1000 ($ millions) 425-450 O&M $425 - $450 800 D&A $187 - $198 428 Interest $138 - $140 Income Tax $83 - $95 600 Net Income $146 - $155 187-198 178 215 400 205 158 138-140 133 140 97 87 82 83-95 200 82 68 65 64 59 47 52 42 146-155 35 33 136 86 72 60 56 0 01 02 03 04 05 6E 00 20 20 20 20 20 2 43
  44. 44. Consolidated Financial Results – Fiscal 2006E Net Income by Segment 2006E 2004 2003 2005 ($ 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 - $1.90 Earnings Per Share 44
  45. 45. Consolidated Financial Results – Fiscal 2006E Cash Flow ($ millions) 2003 2004 2005 2006E $ 49 $ 271 $ 387 $ 390 - 410 Cash flows from operations (110) (126) (243) (220 - 228) Maintenance/Non-growth capital (55) (67) (99) (103) Dividend $ 45 $ 67 - 79 $ (116) Cash available for debt reduction $ 78 and growth projects Note: The company issued approximately $2.0 billion in debt and equity in 2004. Net cash proceeds exceeded the TXU Gas purchase price by approximately $56 million (after $43 million related to Treasury lock obligations) in anticipation of funding significant and attractive growth projects. 45
  46. 46. 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 46
  47. 47. Consolidated Financial Results – Fiscal 2006E Pension, Post-Retirement & Other Benefits Expense (in millions) Other $51.9 $60.0 Medical & Dental $44.3 $50.0 Post-retirement 6.7 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 47
  48. 48. Consolidated Financial Results Fiscal 2006 2Q 48
  49. 49. Consolidated Income Statements – Fiscal 2006 2Q Three Months Ended March 31 (000s except EPS) 2006 2005 Operating Revenues: Utility Segment $ 1,447,620 $ 1,235,377 Natural Gas Marketing Segment 818,629 512,891 Pipeline and Storage Segment 45,483 45,546 Other Nonutility Segment 1,595 1,278 Intersegment Eliminations (279,481) (110,007) 2,033,846 1,685,085 Purchased Gas Cost: Utility Segment 1,131,885 912,309 Natural Gas Marketing Segment 774,652 501,731 Pipeline and Storage Segment 211 4,407 Other Nonutility Segment - - Intersegment Eliminations (278,305) (109,256) 1,628,443 1,309,191 Gross Profit 405,403 375,894 Operation and Maintenance Expense 112,698 103,420 Depreciation and Amortization 47,076 45,326 Taxes, other than income 64,796 54,967 Miscellaneous Income (Expense) (2,439) 958 Interest Charges 35,492 33,073 Income Before Income Taxes 142,902 140,066 Income Tax Expense 54,106 51,564 Net Income $ 88,796 $ 88,502 Net Income Per Share: Basic $ 1.10 $ 1.12 Diluted $ 1.10 $ 1.11 Average Shares Outstanding: Basic 80,573 79,270 Diluted 81,040 79,760 49
  50. 50. Consolidated Income Statements – Fiscal 2006 YTD Six Months Ended March 31 (000s except EPS) 2006 2005 Operating Revenues: Utility Segment $ 2,852,630 $ 2,149,058 Natural Gas Marketing Segment 1,920,474 1,006,692 Pipeline and Storage Segment 85,195 89,236 Other Nonutility Segment 3,087 2,637 Intersegment Eliminations (543,720) (193,914) 4,317,666 3,053,709 Purchased Gas Cost: Utility Segment 2,256,714 1,568,679 Natural Gas Marketing Segment 1,850,178 968,688 Pipeline and Storage Segment 211 10,628 Other Nonutility Segment - - Intersegment Eliminations (541,430) (192,283) 3,565,673 2,355,712 Gross Profit 751,993 697,997 Operation and Maintenance Expense 220,915 214,197 Depreciation and Amortization 90,336 89,323 Taxes, other than income 110,212 93,622 Miscellaneous Income (Expense) (1,991) 1,343 Interest Charges 71,681 65,615 Income Before Income Taxes 256,858 236,583 Income Tax Expense 97,035 88,482 Net Income $ 159,823 $ 148,101 Net Income Per Share: Basic $ 1.99 $ 1.92 Diluted $ 1.98 $ 1.90 Average Shares Outstanding: Basic 80,444 77,290 Diluted 80,911 77,769 50
  51. 51. Utility Operating Income – By Division Fiscal 2006 2Q Three Months Ended March 31 2006 2005 Utility Operating Income Colorado-Kansas Division $ 14,650 $ 16,248 Kentucky Division 9,055 10,758 Louisiana Division 8,596 16,250 Mid-States Division 24,895 24,705 Mid-Tex Division 29,455 41,022 Mississippi Division 16,752 18,509 West Texas Division 13,539 15,302 Other 822 404 $ 117,764 $ 143,198 Total Utility Operating Income 51
  52. 52. Utility Operating Income – By Division Fiscal 2006 YTD Six Months Ended March 31 2006 2005 Utility Operating Income Colorado-Kansas Division $ 23,260 $ 24,483 Kentucky Division 15,247 16,603 Louisiana Division 16,487 22,583 Mid-States Division 39,193 35,843 Mid-Tex Division 80,242 79,570 Mississippi Division 26,745 27,116 West Texas Division 19,670 21,088 Other 3,169 999 $ 224,013 $ 228,285 Total Utility Operating Income 52
  53. 53. Utility Volumes - Fiscal 2006 2Q Three Months Ended March 31 2006 2005 Change % Change Sales Volumes (MMcf) Residential 65,869 78,477 (12,608) (16%) Commercial 33,833 37,048 (3,215) (9%) Public authority and other 3,649 2,962 687 23% Industrial 8,054 9,648 (1,594) (17%) Irrigation 316 60 256 427% Total 111,721 128,195 (16,474) (13%) 31,152 31,904 (752) (2%) Transportation (MMcf) Total Consolidated 142,873 160,099 (17,226) (11%) Utility Volumes (MMcf) 53
  54. 54. Utility Volumes - Fiscal 2006 YTD Six Months Ended March 31 2006 2005 Change % Change Sales Volumes (MMcf) Residential 119,578 129,246 (9,668) (7%) Commercial 62,972 64,911 (1,939) (3%) Public authority and other 6,940 6,978 (38) (1%) Industrial 17,063 17,891 (828) (5%) Irrigation 356 126 230 183% Total 206,909 219,152 (12,243) (6%) 61,754 59,882 1,872 3% Transportation (MMcf) Total Consolidated 268,663 279,034 (10,371) (4%) Utility Volumes (MMcf) 54
  55. 55. Cash Flow Statements - Fiscal 2006 YTD Six Months Ended March 31 2006 2005 (000s) $ 159,823 $ 148,101 Net income Depreciation and amortization 90,670 89,800 Deferred income taxes 58,199 42,605 Other 7,587 3,315 Net change in operating assets and liabilities (167,888) 116,272 148,391 400,093 Operating cash flow Acquisitions - (1,912,532) Capital expenditures - growth (60,889) (41,337) Capital expenditures - non-growth (152,341) (96,129) Other, net (2,842) (1,957) (67,681) (1,651,862) Operating cash flow after investing activities Repayment of long-term debt (2,162) (3,849) Settlement of Treasury lock agreements - (43,770) Dividends paid (50,933) (49,211) Cash flow after acquisitions $ (120,776) $ (1,748,692) and growth capital 55
  56. 56. Capitalization - Fiscal 2006 YTD As of March 31 2006 2005 (000s) Short-term debt $ 262,315 6.3% $ - 0.0% Long-term debt 2,184,428 52.6% 2,260,704 58.1% Shareholders' equity 1,706,291 41.1% 1,632,270 41.9% Total capitalization $ 4,153,034 100.0% $ 3,892,974 100.0% 56
  57. 57. As a Reminder… The audio and slide presentation of this conference call will be available on Atmos Energy’s Web site by 9:00 a.m. Eastern Daylight Time on May 5, 2006, through midnight on August 9, 2006. Atmos Energy’s Web site address is: www.atmosenergy.com. To listen to the live conference call, dial 800-218- 9073 by 9:00 a.m. Eastern Daylight Time on May 5, 2006. 57
  58. 58. Appendix 58
  59. 59. Atmos Energy Marketing - Storage 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 financially 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 executed or when financials are settled and then reset to stay hedged against physical volumes. 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. 59
  60. 60. 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 $30.8 MM ($35.8 MM) ($35.8 MM) Market Spread Embedded margin difference *Realizing Economic Value $66.6 MM is dependent on ability to execute – deliver physical gas & close financial hedges Support data appears on the following slide At March 31, 2006 60
  61. 61. Atmos Energy Marketing Economic Value vs. GAAP Reported Results Physical Economic Value (EV) GAAP Reported Value - MTM Market Spread ($ per mmbtu) Period Volume Total Total Total WASP WACOG EV ($ in millions) ($ per mmbtu) ($ in millions) ($ per mmbtu) ($ in millions) Ending (Bcf) 6.4 8.3569 6.3385 2.0184 1.8401 0.1783 12/31/2004 12.9 11.8 1.1 12.5 7.1916 6.5459 0.6457 (0.7044) 1.3501 3/31/2005 8.0 (8.8) 16.8 12.8 9.3918 8.8366 0.5552 (3.0094) 3.5646 12/31/2005 7.1 (38.6) 45.7 23.6 10.3880 9.0806 1.3074 (1.5195) 2.8269 3/31/2006 30.8 (35.8) 66.6 61
  62. 62. Atmos Pipeline - Texas Project Update CAPEX* GRIP Filings ** Actual Estimated Project 2005 2006 2005 2006 Northside Loop JV with Energy $1.6 million $48.2 million $15.2 million $34.6 million Transfer Enbridge --- Line/Corridor $4.0 million $17.8 million $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 $79.7 million $15.2 million $71.4 million Estimated total annual revenues are $15.0 million; of which $6.7 million are expected to occur in fiscal 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
  63. 63. Atmos Pipeline - Texas 63
  64. 64. Project Map North Side Loop Enbridge Compression 64
  65. 65. Trans Louisiana Gas Pipeline h ris h Pa Orleans Paris s rl e Storage is held on upstream pipelines ha h .C ris St Jefferson Pa • Bridgeline • Acadian • Gulf South Entergy Louisiana Entergy Louisiana (TLGP Sales) (TLGP Sales) S5,T13S,R20E Gulf South Pipeline S5,T13S,R20E Gulf South Pipeline S48,T13S,R21E S48,T13S,R21E Atmos Energy Louisiana Atmos Energy Louisiana S5,T13S,R23E S5,T13S,R23E Acadian Gas Pipeline Acadian Gas Pipeline S48,T13S,R21E S48,T13S,R21E AEL 18” TLGP 24” Bridgeline Gas Bridgeline Gas (Paradis) TLGP 16” (Paradis) S39,T14S,R20E S39,T14S,R20E Future Interconnect Future Interconnect Columbia Gulf Columbia Gulf S24,T13S,R23E TLGP Pipeline TLGP Pipeline B’line 14” October 26, 2001 N Metropolitan New Orleans Area 21 Miles of 24” TLGP Pipe Metropolitan New Orleans Area W E .95 Miles of 12” TLGP Pipe TLGP Transmission // TLGP Sales Points TLGP Transmission TLGP Sales Points 65 S

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