atmos enerrgy 46_pres

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atmos enerrgy 46_pres

  1. 1. Conference Call to Review 2006 Fiscal Year and Fourth Quarter Financial Results November 8, 2006 8:00 a.m. EST
  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 risks relating to regulatory trends and decisions, the Company’s ability to continue to access the capital markets and the other factors discussed in the Company’s filings with the Securities and Exchange Commission. These factors include the risks and uncertainties discussed in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2005, and the Company’s Quarterly Report on Form 10-Q for the three and nine months ended June 30, 2006. Although the Company believes these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. The Company undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Further, the Company will only update earnings guidance through its quarterly and annual earnings releases. All estimated financial metrics for fiscal year 2007 and beyond that appear in this presentation are current as of the date noted on each relevant slide. 2
  3. 3. Consolidated Financial Results – Fiscal 2006 Key Drivers Net Income Increased contribution from nonutility businesses, primarily natural gas marketing segment, due to higher margins and market volatility $162.3 Rate increase adjustments, primarily $170.0 20 % GRIP in Texas effective in 2006 $160.0 $147.7 Nonrecurring, noncash charge of 9% $14.6 million due to impairment of $150.0 $135.8 irrigation properties in West Texas $140.0 Weather was 13% warmer than normal and 2% warmer than the $130.0 prior year, as adjusted for jurisdictions with weather- $120.0 normalized rates $110.0 Increase in O&M expenses due to 2005 2006 2006 (excl. higher employee-related costs charge) Increase in interest expense due to higher S-T Debt balances and ($ in millions) interest rate increases 3
  4. 4. Consolidated Financial Results – Fiscal 2006 Earnings per Diluted Share Notes 2006 includes $0.18 per diluted $2.00 share related to nonrecurring, 16% $2.00 noncash charge for impairment of irrigation $1.82 6% properties in utility segment $1.72 $1.75 Delivered on company’s 2006 guidance range of $1.80-$1.90 per diluted share, despite 13% warmer than normal weather $1.50 Period-over-period increase of almost 2.4 million weighted average diluted shares $1.25 outstanding 2005 2006 2006 (excl. charge) 4
  5. 5. Consolidated Financial Results – Fiscal 2006 Net Income by Segment 81.1 $90.0 58.6 $75.0 53.0 ($ in millions) $60.0 35.6 $45.0 30.6 23.4 $30.0 0.5 0.7 $15.0 $0.0 2005 2006 Utility Natural gas marketing Pipeline and storage Other nonutility 5
  6. 6. Consolidated Financial Results – Fiscal 2006 Drivers $98.9 million increase in gross profit $17.7 million increased utility gross profit primarily from o $22.9 million decrease primarily due to decreased throughput of 17.1 Bcf, due to weather that was 2 percent warmer than the prior year o $16.1 million increase related to higher franchise fees, higher state gross receipts taxes paid and other items o $13.8 million increase due to rate adjustments resulting from the GRIP-related recovery for 2004 and 2005 capital expenditures in Texas o $6.2 million increase due to recognition of previously deferred revenue associated with 2003 Rate Stabilization Filing with the Louisiana Public Service Commission o $2.9 million decrease due to the impact of Hurricane Katrina 6
  7. 7. Consolidated Financial Results – Fiscal 2006 Jurisdictions Adjusted for WNA At September 30, 2006, we had WNA in the following service areas for the following periods as noted, which covers over 90% of our customer meters in service: Tennessee November – April Georgia October – May Mississippi November – April Kentucky November – April Kansas October – May Louisiana * December – March Mid-Tex * October – May Amarillo, TX October – May October – May West Texas Lubbock, TX October – May January – December Virginia * New for the 2006-2007 winter heating season 7
  8. 8. Consolidated Financial Results – Fiscal 2006 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 • Fiscal 2006 utility gross profit was Percent (Warmer) Colder than Normal adversely affected 2% 0% 0% by $49.2 million due 0 to weather that was 13% warmer than 1% normal, as adjusted for jurisdictions with 5% weather-normalized 7% rates (10) 9% 10% 9% • Louisiana and Mid- Tex Divisions did 13% not have weather- 15% normalized rates and 18% experienced warmer (20) than normal weather of 22% and 28%, 22% respectively 28% (30) Actual / Normal Adjusted for WNA 8
  9. 9. Consolidated Financial Results – Fiscal 2006 Relationship of Utility EPS to Heating Degree Days Degree Days EPS (Adjusted for WNA) $1.25 3,500 $1.16 3,271 $1.03 3,250 $1.00 $0.83 * 3,000 $0.75 2,587 2,750 2,527 $0.50 2,500 $0.25 2,250 2004 2005 2006 * Excludes negative impact of asset impairment 9
  10. 10. Consolidated Financial Results – Fiscal 2006 Utility Margin Sensitivity 2004–2006 2006–2007E 2003–2004 Heating Season Heating Seasons Heating Season (Post-TXU Gas) (Before TXU Gas) 9% 5% 35% 36% 48% 51% 86% 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 10
  11. 11. Consolidated Financial Results – Fiscal 2006 Drivers $98.9 million increase in gross profit (continued) $68.6 million increase in natural gas marketing gross profit primarily due to o $27.3 million increase in realized marketing margins primarily due to increased volumes sold of 45.9 Bcf year over year and capturing higher margins in certain market areas that experienced increased volatility o $1.8 million decrease in realized storage contribution as a result of unfavorable arbitrage spreads related to storage optimization efforts, coupled with increased storage fees on incremental storage capacity added in the third quarter of fiscal 2005 o $12.7 million decrease in unrealized storage mark-to-market losses primarily due to favorable movement between the forward prices used to value financial hedges and the spot prices used to value the physical storage positions, coupled with an increase in physical storage positions of 7.6 Bcf year over year o $30.4 million increase in unrealized marketing mark-to-market gains primarily due to favorable movement in the forward prices used to value the financial derivatives used in these activities 11
  12. 12. Consolidated Financial Results – Fiscal 2006 Year Ended September 30 Natural Gas Marketing Segment 2006 2005 Change (In thousands, except physical position) Storage Activities Realized margin $26,225 $28,008 ($1,783) Unrealized margin (1,293) (14,007) 12,714 Total Storage Activities 24,932 14,001 10,931 Marketing Activities Realized margin 87,236 59,971 27,265 Unrealized margin 18,459 (11,999) 30,458 Total Marketing Activities 105,695 47,972 57,723 GROSS PROFIT $130,627 $61,973 $68,654 Net physical position (Bcf) 14.5 6.9 7.6 12
  13. 13. Consolidated Financial Results- Fiscal 2006 Fair Value of Contracts at September 30, 2006 Maturity in Years Total Fair Source of Fair Value <1 1-3 4-5 >5 Value (In thousands) $ — $ — $ (10,299) Prices actively quoted $ (17,421) $ 7,122 Prices provided by other — external sources (440) (936) — (1,376) Prices based on models & other valuation methods (255) (276) — — (531) $ $ — $ (12,206) — Total Fair Value $ (18,116) $ 5,910 13
  14. 14. Consolidated Financial Results – Fiscal 2006 Drivers $98.9 million increase in gross profit (continued) $13.2 million increase in pipeline and storage gross profit primarily due to o $16.2 million increase due to a 34.9 Bcf increase in total transportation volumes, higher transportation & related service margins and more favorable arbitrage spreads captured in asset management contracts, partially offset by a o $3.0 million decrease due to the absence of inventory sales realized in the prior year 14
  15. 15. Consolidated Financial Results – Fiscal 2006 Drivers Increased O&M expenses of $17.1 million primarily due to $19.6 million increase in employee costs associated with increased headcount and benefit costs primarily resulting from changes in the pension assumptions used to determine the fiscal 2006 costs $2.1 million decrease due to the absence of UCG acquisition-related M&I costs which became fully amortized in fiscal 2005 $1.5 million increase in provision for doubtful accounts due to due to increased collection risk on higher customer bills caused by higher gas prices 15
  16. 16. Consolidated Financial Results – Fiscal 2006 Pension, Post-Retirement & Other Benefits Expense (in millions) $53.3 Other $60.0 Medical & Dental $44.1 $50.0 9.3 Post-Retirement Pension $40.0 9.9 20.1 $30.0 16.7 2006 Pension Assumptions $20.0 14.2 8.50% return on plan assets 5.00% discount rate 12.8 $10.0 4.00% wage increase 9.7 4.7 $0.0 2005 2006 16
  17. 17. Consolidated Financial Results – Fiscal 2006 Utility Bad Debt Expense as a Percent of Revenues 2.0 1.86 1.5 Percent 1.0 0.83 0.58 0.58 0.5 0.29 0.0 0.0 2001 2002 2003 2004 2005 2006 17
  18. 18. Consolidated Financial Results – Fiscal 2006 Drivers Increased taxes, other than income, of $17.3 million primarily due to increased franchise fees and state gross receipts taxes Increased operating expenses due to $22.9 million noncash charge to recognize the impairment of West Texas irrigation properties in fiscal 2006 Increased interest charges of $13.9 million $18.7 million increase primarily due to higher short-term debt balances used for natural gas purchases made at significantly higher prices coupled with an increase in the 3-month LIBOR rate, partially offset by $4.8 million decrease in interest charges from the early payoff of $72.5 million of First Mortgage Bonds in June 2005 Decreased miscellaneous income of $1.1 million due to $3.3 million noncash charge in fiscal 2006 related to an adverse regulatory ruling in Tennessee associated with gas purchases and the PBR calculation 18
  19. 19. Consolidated Financial Results – Fiscal 2006 West Texas Irrigation Volumes Decline (in thousands) (in BCF) 20.0 20.0 15.8 16.4 15.2 Number of Water Wells 14.5 15.0 15.0 Irrigation Volumes 12.8 16.3 12.2 10.5 12.2 13.1 9.6 11.8 10.0 10.0 8.3 7.0 9.5 8.0 7.2 5.0 5.0 5.0 4.1 3.1 0.0 0.0 97 98 99 00 01 02 03 04 05 06 19 19 19 20 20 20 20 20 20 20 19
  20. 20. Consolidated Financial Results – Fiscal 2006 Capital Expenditures Utility CAPEX Nonutility CAPEX (in millions) (in millions) $300.6 $307.7 $117.6 $150 $375 $120 $300 $90 $225 68.5 218.6 210.4 $32.6 $60 $150 $30 $75 49.1 32.6 90.2 89.1 $0 $0 2005 2006 2005 2006 Maintenance Growth Fiscal 2006 Expenditures Maintenance Capital: $287.1 million Growth Capital: $138.2 million 20
  21. 21. Consolidated Financial Results – Fiscal 2006 4Q Net Income (Loss) Key Drivers Increase in natural gas marketing $20.9 margins, primarily unrealized $25.0 marketing and storage margins $15.0 $6.1 Nonrecurring, after-tax charge of $14.8 million due to impairment of $5.0 irrigation properties in West Texas ($5.0) Rate increases associated with Texas GRIP ($15.0) ($16.8) Increased interest expense due to ($25.0) higher average short-term debt 4Q 2005 4Q 2006 4Q 2006 balances and an increase in the 3- (excl. month LIBOR rate charge) ($ in millions) 21
  22. 22. Consolidated Financial Results – Fiscal 2006 4Q Net Income (Loss) per Diluted Share Notes $0.40 $0.25 Includes a nonrecurring, after- $0.20 tax charge due to impairment $0.07 of irrigation properties in West Texas Utility Division of $0.18 $0.00 per diluted share Quarter-over-quarter increase ($0.20) ($0.21) of approximately 1.7 million weighted average diluted ($0.40) shares outstanding Q4 2005 Q4 2006 Q4 2006 (excl. charge) 22
  23. 23. Consolidated Financial Results – Fiscal 2006 4Q Capital Expenditures Utility CAPEX Nonutility CAPEX (in millions) (in millions) $40 $120 $91.2 $27.0 $75.6 $30 $90 $15.1 13.5 $20 $60 65.6 51.0 $10 $30 15.1 13.5 25.6 24.6 $0 $0 2005 4Q 2006 4Q 2005 4Q 2006 4Q Maintenance Growth Fiscal 2006 4Q Expenditures Maintenance Capital: $64.5 million Growth Capital: $38.1 million 23
  24. 24. Consolidated Financial Results – Fiscal 2006 4Q Quarter Ended September 30 Natural Gas Marketing Segment 2006 2005 Change (In thousands, except physical position) Storage Activities Realized margin ($18,375) $12,526 ($30,901) Unrealized margin 41,631 (6,942) 48,573 Total Storage Activities 23,256 5,584 17,672 Marketing Activities Realized margin 23,973 16,790 7,183 Unrealized margin 13,988 (8,800) 22,788 Total Marketing Activities 37,961 7,990 29,971 GROSS PROFIT $61,217 $13,574 $47,643 Net physical position (Bcf) 14.5 6.9 7.6 24
  25. 25. Highlights – Fiscal 2006 Natural Gas Gathering Project (map in appendix) May 10, 2006, announced plans to construct 60-mile, 20- inch 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 received exemption from regulatory oversight by the Federal Energy Regulatory Commission in early October; other required regulatory approvals pending Anticipate construction to begin in the first half of fiscal 2007, and operations to begin in fiscal 2008 25
  26. 26. Highlights – Fiscal 2006 Louisiana Rate Settlement May 25, 2006, Louisiana Public Service Commission (LPSC) approved settlement of several existing dockets Allows modified WNA which provides for 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 made in August 2006, with an effective date of August 12, 2006, based on a test year ended December 31, 2005 First RSC filing for the Trans La service area should be made by December 31, 2006, for the test period ending September 30, 2006, with 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 Implemented new rates subject to refund in September 2006, reflecting reduction of about 26,500 customers and recovery of costs as a result of damage related to Hurricane Katrina 26
  27. 27. Highlights – Fiscal 2006 Rate Case Filing in Mid-Tex Division May 31, 2006, filed for rate increase of $60 million and several rate design changes including WNA, Revenue Stabilization, and recovery of the gas cost component of bad 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 Hearing is currently in progress and expected to continue through November 15, 2006 Anticipate decision on the case by April 2007 Any rate increase will be effective from the day of final order; any rate decrease will be effective from May 31, 2006 Affects approximately 1.5 million customers in Texas 27
  28. 28. Highlights – Fiscal 2006 Mid-Tex Division Rate Case – Proposed Schedule 2006 2007 Event September October November December January February March April Last Day to File 9/15/06 Discovery in Company’s Direct Case 10/3/06 Staff and Intervenor Direct Testimony 10/24/06 Company Rebuttal Hearing on the Merits 10/31/06 BEGINS 11/15/06 Hearing on the Merits CONCLUDES 11/28/06 Initial Briefs Due 12/7/06 Reply Briefs Due 1/8/07 Proposal for Decision (PFD) Issued 1/23/07 Exceptions Due 1/30/07 Replies to Exceptions First Possible RRC 2/6/07 Conference (Oral Argument) 4/2/07 Second Possible RRC Conference (Decision) 28
  29. 29. Highlights – Fiscal 2006 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; implemented September 2006 September 2005, Mid-Tex Division 2004 GRIP filing of $6.7 million related to return and capital-related expenses on $29.4 million increase in net investment during calendar 2004, implemented Feb. 2006 September 2005, Atmos Pipeline-Texas 2004 GRIP filing of $1.9 million revenue increase related to return and capital-related expenses on $10.6 million in net investment during calendar 2004, implemented January 2006 September 2005, West Texas Division 2004 GRIP filing for $3.8 million on increase in net investment of $22.6 million Implementation of new charges in January 2006, except for the inside city limits customers, which went into effect in May 2006. 29
  30. 30. Highlights – Fiscal 2006 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 30
  31. 31. Highlights – Fiscal 2006 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% Total company investments approximate $22.0 million over the 9-year period Currently in settlement discussions with commission Serve approximately 60,000 residential, commercial and industrial customers in Missouri 31
  32. 32. Highlights – Fiscal 2006 Rate Case Result – Tennessee November 2005, Tennessee Regulatory Authority (TRA) began investigation into allegations by the Consumer Advocate’s Office of the Tennessee Attorney General’s Office that Atmos Energy was overcharging customers by approximately $10 million On October 27, 2006, the TRA voted to reduce rates by $6.1 million, effective December 1, 2006 We are currently analyzing the timing of a new rate case filing Serve approximately 125,000 residential, commercial and industrial customers in Tennessee 32
  33. 33. Highlights – Fiscal 2006 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, effective 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 $10 million in annual margins from volumetric to customer charge Revised WNA to include approximately 4% of additional heating degree days Reduces regulatory lag, adjusts for forward-looking known and measurable expenses and utilizes an average expected rate base Changes affect approximately 251,000 customers 33
  34. 34. Highlights – Fiscal 2006 Gas Held in Underground Storage – by Segment September 30, 2006 September 30, 2005 Segment Balance Volumes WACOG Balance Volumes WACOG ($MM’s) (Bcf) ($MM’s) (Bcf) Atmos Utility $ 385.5 59.9 $ 6.43 $ 328.6 54.7 $ 6.01 Natural Gas 63.0 15.3 7.88 110.1 8.2 5.80 Marketing Pipeline & Storage 13.0 2.6 7.89 12.1 1.8 6.06 Total: $ 461.5 77.8 $ 6.76 $ 450.8 64.7 $ 5.99 34
  35. 35. Highlights – Fiscal 2006 Credit Facilities November 7, 2006, Atmos Energy entered into a new $300 million, 364-day committed revolving credit facility Supplements amounts available under existing $18 million committed credit facility and $25 million uncommitted credit facility, under essentially the same terms as the $600 million 3-year committed revolving credit facility April 1, 2006, Atmos Energy renewed its existing $18 million committed credit facility, with no material changes to terms and pricing 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 On October 18, 2005, Atmos Energy entered into a $600 million, 3-year committed revolving credit facility through October 18, 2008, which serves as a backup liquidity facility for our commercial paper program 35
  36. 36. Highlights – Fiscal 2006 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 36
  37. 37. Highlights – Fiscal 2006 Annual Dividend Increase 19th consecutive annual dividend increase 92nd consecutive dividend declared 1.6 percent annual increase from $0.315 per share to $0.32 per share each quarter Indicated annual dividend of $1.28 per share To be paid on December 11, 2006, to shareholders of record on November 27, 2006 37
  38. 38. Consolidated Financial Results – Fiscal 2007E Annual Dividend Growth $1.28E $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 '0 4 5 6 7 8 9 0 1 2 3 4 5 6 7 8 9 0 1 2 3 4 5 6 7 Note: Amounts are adjusted for mergers and acquisitions. For fiscal 2007, $1.28 is the indicated annual dividend. 38
  39. 39. Consolidated Financial Results – Fiscal 2007E Earnings Guidance – Fiscal 2007E Atmos Energy anticipates earnings to be in the range of $1.90 - $2.00 per fully diluted share for the 2007 fiscal year Assumptions include: • Contribution from natural gas marketing segment reflects less volatility in gas prices o Total expected gross margin contribution from the marketing segment in the range of $75 million to $85 million, including $10 million positive mark-to-market impact • Continued execution of rate strategy and collection efforts • Normal weather in non-WNA jurisdictions • Bad debt expense of no more than $22 million • Average short-term interest rate @ 6.3% • No material acquisitions Note: Changes in these events or other circumstances that the company cannot currently anticipate could materially impact earnings, and could result in earnings for fiscal 2007 significantly above or below this outlook. 39
  40. 40. Consolidated Financial Results – Fiscal 2007E Projected Net Income by Segment ($ millions, except EPS) 2007E 2005 2006 2004 $ 88 - 89 $ 63 Utility $ 81 $ 53 28 - 32 17 Natural Gas Marketing 23 58 39 - 41 3 Pipeline & Storage 31 36 2-3 3 Other 1 1 157 - 165 86 Total 136 148 82.6 54.4 Avg. Diluted Shares 79.0 81.4 $1.90 - $2.00 $ 1.58 Earnings Per Share $ 1.72 $ 1.82 40
  41. 41. Consolidated Financial Results – Fiscal 2007E Atmos Energy Marketing – Gross Profit Margin Composition 2007E Impacted by customer volume demand Marketing Sales prices are: Marketing • Cost plus profit margin $43 - $46 Million (Bundled gas deliveries & • Cost plus demand charges (Bundled gas deliveries & peaking sales) peaking sales) Margins: More predictable Impacted by gas price spread values in the market (arbitrage opportunity) Asset Optimization Asset Optimization $32 - $39 Million Physical storage capabilities Available storage and transport (Storage & transportation (Storage & transportation capacity management) management) Margins: More variable = Total margins reflect: Stability from marketing margins $75 - $85 Million Upside from optimizing our storage Total AEM Total AEM and transportation assets to capture Margins Margins arbitrage value Margins: Stable with potential upside 41
  42. 42. Consolidated Financial Results – Fiscal 2007E Capital Expenditures In the 2006 fiscal year, Atmos Energy spent $425.3 million in capital expenditures For fiscal 2007, we project between $425-$440 million in capital expenditures Approximately $251 - $262 million maintenance o Nonutility: $42 million - $47 million o Utility: $209 million - $215 million Approximately $174 - $178 million growth o Nonutility: $78 million - $79 million o Utility: $96 million – $99 million 42
  43. 43. Consolidated Financial Results – Fiscal 2007E Minimizing Volatility With Gas Supply Hedging For the 2006-2007 heating season, Atmos Energy is hedging approximately 49 percent of its expected winter gas utility supply requirements 22 percent are naturally hedged through a combination of owned underground storage assets and contract pipeline storage 27 percent is hedged through the use of financial derivatives (primarily futures and fixed forward contracts) We project the weighted-average cost for storage gas and financial contracts to be approximately $7.53 per Mcf. This compares to a weighted-average cost of approximately $9.06 per Mcf for the same period last year Hedging provides relative protection to the company and its customers against volatility in gas prices Customers will pay a blended rate for gas costs Atmos Energy should reduce the effects of higher gas prices on its customer receivables and working capital requirements 43
  44. 44. Consolidated Financial Results – Fiscal 2007E Pension, Post-Retirement & Other Benefits Expense (in millions) $59.1 $53.3 Other $60.0 Medical & Dental 10.4 $50.0 9.3 Post-Retirement Pension $40.0 25.3 20.1 $30.0 2007 Pension Assumptions $20.0 14.2 12.8 8.25% return on plan assets 6.30% discount rate $10.0 4.00% wage increase 10.6 9.7 $0.0 2006 2007E 44
  45. 45. Consolidated Financial Results 2006 Fiscal Year and Fourth Quarter 45
  46. 46. Consolidated Income Statements – Fiscal 2006 Year Ended September 30 (000s except EPS) 2006 2005 Operating Revenues: Utility Segment $ 3,650,591 $ 3,103,140 Natural Gas Marketing Segment 3,156,524 2,106,278 Pipeline and Storage Segment 160,567 153,289 Other Nonutility Segment 5,898 5,302 Intersegment Eliminations (821,217) (406,136) 6,152,363 4,961,873 Purchased Gas Cost: Utility Segment 2,725,534 2,195,774 Natural Gas Marketing Segment 3,025,897 2,044,305 Pipeline and Storage Segment 838 6,811 Other Nonutility Segment - - Intersegment Eliminations (816,476) (402,654) 4,935,793 3,844,236 Gross Profit 1,216,570 1,117,637 Operation and Maintenance Expense 433,418 416,281 Depreciation and Amortization 185,596 178,005 Taxes, other than income 191,993 174,696 Impairment of Long-lived Assets 22,947 - Miscellaneous Income 881 2,021 Interest Charges 146,607 132,658 Income Before Income Taxes 236,890 218,018 Income Tax Expense 89,153 82,233 Net Income $ 147,737 $ 135,785 Net Income Per Share: Basic $ 1.83 $ 1.73 Diluted $ 1.82 $ 1.72 Average Shares Outstanding: Basic 80,731 78,508 Diluted 81,390 79,012 46
  47. 47. Consolidated Income Statements – Fiscal 2006 4Q Three Months Ended September 30 (000s except EPS) 2006 2005 Operating Revenues: Utility Segment $ 395,917 $ 452,347 Natural Gas Marketing Segment 673,603 632,751 Pipeline and Storage Segment 39,510 30,604 Other Nonutility Segment 1,398 1,244 Intersegment Eliminations (138,974) (115,659) 971,454 1,001,287 Purchased Gas Cost: Utility Segment 236,628 300,593 Natural Gas Marketing Segment 612,386 619,177 Pipeline and Storage Segment 248 (2,084) Other Nonutility Segment - - Intersegment Eliminations (137,885) (114,765) 711,377 802,921 Gross Profit 260,077 198,366 Operation and Maintenance Expense 108,123 110,641 Depreciation and Amortization 48,422 45,234 Taxes, other than income 33,302 34,159 Impairment of Long-lived Assets 22,947 - Miscellaneous Income (Expense) 1,909 (846) Interest Charges 38,982 33,354 Income (Loss) Before Income Taxes 10,210 (25,868) Income Tax Expense (Benefit) 4,151 (9,066) Net Income (Loss) $ 6,059 $ (16,802) Net Income (Loss) Per Share: Basic $ 0.07 $ (0.21) Diluted $ 0.07 $ (0.21) Average Shares Outstanding: Basic 81,073 80,030 Diluted 81,762 80,030 47
  48. 48. Utility Operating Income – By Division Fiscal 2006 Year Ended September 30 2006 2005 Utility Operating Income Colorado-Kansas Division $ 22,524 $ 25,157 Kentucky Division 14,338 18,657 Louisiana Division 27,772 24,819 Mid-States Division 35,555 35,687 Mid-Tex Division 71,703 84,965 Mississippi Division 23,276 19,045 West Texas Division 2,215 27,520 Other 4,511 515 $ 201,894 $ 236,365 Total Utility Operating Income 48
  49. 49. Utility Operating Income (Loss) – By Division Fiscal 2006 4Q Three Months Ended September 30 2006 2005 Utility Operating Income (Loss) Colorado-Kansas Division $ (899) $ (1,777) Kentucky Division (538) 794 Louisiana Division 2,570 (2,122) Mid-States Division (904) (1,756) Mid-Tex Division 4,280 2,963 Mississippi Division (2,204) (5,616) West Texas Division (21,838) 1,440 Other 324 (887) $ (19,209) $ (6,961) Total Utility Operating Income (Loss) 49
  50. 50. Utility Volumes - Fiscal 2006 Year Ended September 30 2006 2005 Change % Change Sales Volumes (MMcf) Residential 144,780 162,016 (17,236) (11%) Commercial 87,006 92,401 (5,395) (6%) Public authority and other 8,457 9,084 (627) (7%) Industrial 26,161 29,434 (3,273) (11%) Irrigation 5,629 3,348 2,281 68% Total 272,033 296,283 (24,250) (8%) 121,962 114,851 7,111 6% Transportation (MMcf) Total Consolidated 393,995 411,134 (17,139) (4%) Utility Volumes (MMcf) 50
  51. 51. Utility Volumes - Fiscal 2006 4Q Three Months Ended September 30 2006 2005 Change % Change Sales Volumes (MMcf) Residential 12,026 12,242 (216) (2%) Commercial 12,315 12,342 (27) - Public authority and other 679 639 40 6% Industrial 4,937 5,548 (611) (11%) Irrigation 2,514 2,435 79 3% Total 32,471 33,206 (735) (2%) 30,578 26,216 4,362 17% Transportation (MMcf) Total Consolidated 63,049 59,422 3,627 6% Utility Volumes (MMcf) 51
  52. 52. Cash Flow Statements - Fiscal 2006 Year Ended September 30 2006 2005 (000s) $ 147,737 $ 135,785 Net income Impairment of long-lived assets 22,947 - Depreciation and amortization 185,967 178,796 Deferred income taxes 86,128 12,669 Other 18,530 11,522 Net change in operating assets and liabilities (149,860) 48,172 311,449 386,944 Operating cash flow Acquisitions - (1,916,696) Capital expenditures - growth (138,242) (90,194) Capital expenditures - non-growth (287,082) (242,989) Other, net (5,767) (2,131) (119,642) (1,865,066) Operating cash flow after investing activities Repayment of long-term debt (3,264) (103,425) Settlement of Treasury lock agreements - (43,770) Dividends paid (102,275) (98,978) Cash flow after acquisitions $ (225,181) $ (2,111,239) and growth capital 52
  53. 53. Capitalization - Fiscal 2006 As of September 30 2006 2005 (000s) Short-term debt $ 382,416 9.1% $ 144,809 3.7% Long-term debt 2,183,548 51.8% 2,186,368 55.6% Shareholders' equity 1,648,098 39.1% 1,602,422 40.7% Total capitalization $ 4,214,062 100.0% $ 3,933,599 100.0% 53
  54. 54. As a Reminder… The audio and slide presentation of this conference call will be available on Atmos Energy’s Web site by 8:00 a.m. Eastern Standard Time on November 8, 2006, through midnight on February 6, 2007. Atmos Energy’s Web site address is: www.atmosenergy.com. To listen to the live conference call, dial 800-257-1836 by 8:00 a.m. Eastern Standard Time on November 8, 2006. 54
  55. 55. Appendix 55
  56. 56. Atmos Energy Marketing Economic Value vs. GAAP Reported Results We commercially manage our storage assets by capturing arbitrage value through optimization strategies that create embedded (forward) value in the portfolio. We report the transactions for external reporting purposes in accordance with GAAP. GAAP Reported Value is the period to period net change in fair value of the portfolio reported in the income statement that results from the process of marking to market the physical storage volumes and corresponding financial instruments in an interim period. Economic Value is the period to period forward margin of our storage portfolio that results from the process of calculating our weighted average cost of inventory (WACOG), and our weighted average sales price of our forward financials (WASP), then multiplying the difference times inventory volumes. This margin will be realized in cash when the hedged transaction is settled. Economic Value represents the “forward” economic margin of the transactions, while GAAP reported results reflect that portion of our “forward” margin that has been recorded in the income statement. Volatility in earnings includes the impact of the accounting treatment of our storage portfolio and is reflective of relatively high price volatility of the prompt month and the relatively low volatility of the offsetting forward months. 56
  57. 57. 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 $60.0 MM ($16.0 MM) ($16.0 MM) Market Spread Embedded margin difference *Realizing Economic Value $76.0 MM is dependent on ability to execute – deliver physical gas & close financial hedges Supporting data appears on the following slide At September 30, 2006 57
  58. 58. Atmos Energy Marketing Economic Value vs. GAAP Reported Results Physical Economic Value (EV) GAAP Reported Value - MTM Market Spread ($ per Bcf) Period Volume Total Total Total WASP WACOG EV ($ in millions) ($ per Bcf) ($ in millions) ($ per Bcf) ($ in millions) Ending (Bcf) 14.1 7.7606 6.5967 1.1639 (0.5559) 1.7198 6/30/2005 16.4 (7.8) 24.2 6.9 6.3466 4.4435 1.9031 (2.1502) 4.0533 9/30/2005 13.1 (14.8) 27.9 19.0 10.2353 8.7417 1.4936 (3.0297) 4.5233 6/30/2006 28.4 (57.7) 86.1 14.5 11.9716 7.8329 4.1387 (1.1076) 5.2463 9/30/2006 60.0 (16.0) 76.0 (4.5) $ 1.7363 $ (0.9088) $ 2.6451 1.9221 $ 0.7230 Variance $ 31.6 $ 41.7 $ (10.1) 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 58
  59. 59. Atmos Pipeline and Storage Straight Creek Gathering System Interstate transmission lines continue on to major Construction of approximately 60 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 Received exemption from regulatory oversight by the Federal Energy Regulatory Commission but pending other regulatory approvals Anticipate construction to begin in first half of fiscal 2007 with operations beginning in fiscal 2008 59
  60. 60. Atmos Pipeline - Texas 60
  61. 61. Atmos Pipeline - Texas Project Update CAPEX* GRIP Filings ** Project 2005 2006 2005 2006 Northside Loop JV with Energy $1.6 million $54.6 million $15.2 million $41.0 million Transfer Enbridge --- Line/Corridor $4.0 million $16.1 million $20.1 million Compression Devon Line/ Corridor ---- ---- ---- ---- Compression Katy Capacity ---- Expansion/ $1.3 million $13.0 million $14.3 million Compression Total: $6.9 million $83.7 million $15.2 million $75.4 million Estimated total annual revenues are $15.0 million. All projects were placed in-service in June 2006. * CAPEX is calculated on a fiscal year basis ** Capital expenditures are included in GRIP filings on a calendar year basis and when the asset is operational 61
  62. 62. Atmos Pipeline - Texas Project Map North Side Loop Enbridge Compression 62

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