EXHIBIT 99
| National Fuel Gas Company Berenson & Company and Wall Street Access Northeast Seminar, Boston Feb 28-29, 2008 |
| Grow shareholder value through timely investment in the energy industry. National Fuel Gas Company Corporate Objective |
| 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008E $3.1 B At Fiscal Year End Net Plant by Segment (in Billions) |
| National Fuel Gas Company Net Plant by Segment $2.9 Billion At December 31, 2007 P&S Utility All Other E&P Net plant 0.7 1.1 0.112 0.988 |
| $214.4 Million 12 Months Ended December 31, 2007 P&S Utility Timber Energy Mkt. * Corp. & Other E&P NI 50.7 53.9 3.9 5.8 8.1 92 National Fuel Gas Company Net Income |
| Shareholder Returns National Fuel versus the S&P 500 & S&P 400 Utilities Index 2Q FY03 3Q FY03 4Q FY03 1Q FY04 2Q FY04 3Q FY04 4Q FY04 1Q FY05 2Q FY05 3Q FY05 4Q FY05 1Q FY06 2Q FY06 3Q FY06 4Q FY06 1Q FY07 2Q FY07 3Q FY07 4Q FY07 1Q FY08 National Fuel 6.75 28.48 14.02 23.31 25.48 28.94 47.56 49.07 51.86 55.1 85.04 70.32 80.26 95.25 103.64 117.59 145.93 147.97 169.79 170.83 S&P 500 -3.15 11.74 14.7 28.63 30.81 33.05 30.55 42.58 39.52 41.43 46.52 49.57 55.85 53.61 62.29 73.14 74.24 85.18 88.91 82.63 S&P 400 Utilities -3.28 12.68 15.44 26.06 30.51 30.35 36.81 49.71 51.72 67.24 77.03 64.64 69.73 75.77 84.07 100.92 113.95 106.26 105.99 113.87 Total Return calculated by Bloomberg on a quarterly basis over last five-years (12/31/02-12/31/07) |
| 70 0.19 71 0.2 72 0.205 73 0.215 74 0.225 75 0.235 76 0.245 77 0.255 78 0.27 79 0.2875 80 0.3075 81 0.33 82 0.36 83 0.39 84 0.47 85 0.52 86 0.57 87 0.6 88 0.63 89 0.67 90 0.71 91 0.73 92 0.75 93 0.77 94 0.79 95 0.81 96 0.84 97 0.87 98 0.9 99 0.93 '00 0.96 '01 1.01 '02 1.04 '03 1.08 '04 1.12 '05 1.16 '06 1.2 '07 1.24 National Fuel Gas Company Dividend Growth $0.19 '07 $1.24 Annual Rate At Fiscal Year End |
| Earnings * Dividends Paid 85 0.95 0.48 86 0.88 0.53 87 0.88 0.58 88 0.83 0.61 89 0.97 0.64 90 0.92 0.68 91 0.82 0.72 92 0.97 0.74 93 1.08 0.76 94 1.16 0.78 95 1.02 0.8 96 1.39 0.82 97 1.49 0.85 98 1.44 0.88 99 1.47 0.91 '00 1.61 0.94 '01 2.11 0.97 '02 1.58 1.02 '03 1.89 1.05 '04 1.98 1.09 '05 2.15 1.13 '06 2.25 1.17 '07 2.26 1.21 * Excludes special items Dividends Paid Fiscal Year National Fuel Gas Company Earnings vs. Dividends Paid Earnings per Diluted Share |
| National Fuel Gas Company Major Business Segments |
| National Fuel Gas Supply Corporation Empire State Pipeline Pipeline & Storage Segment |
| 2,495 Miles of System Pipeline 15 Compressor Stations Totaling 39,929 Horsepower Transportation Volume for Fiscal 2007: 356.1 Bcf $122.9 MM in Revenues for Fiscal 2007 Pipeline & Storage Pipeline Operating Statistics |
| 32 Underground Natural Gas Storage Fields (4 Co-owned with Nonaffiliated Companies) 15 Compressor Stations Totaling 35,475 Horsepower 78.3 Bcf of Working Storage Capacity $67.1 MM in Revenues for Fiscal 2007 Pipeline & Storage Storage Operating Statistics |
| Fiscal Year 2002 2003 2004 2005 2006 2007 1Q FY08 Earnings 0.49 0.56 0.599 0.63 0.65 0.583 0.15 1Q FY07 0.14 a Excludes SFAS 88 settlement loss of -$0.02 b Excludes base gas sale of $0.03 and gain associated with insurance proceeds of $0.05 c Excludes reversal of reserve for preliminary project costs of $0.06, and Discontinuance of Hedge Accounting of $0.02. d Excludes Discontinuance of Hedge Accounting of $0.02. a Fiscal Year Pipeline & Storage Diluted Earnings per Share b c d |
| Construction Started September 2007 >18 miles Completed; Construction to Resume as Weather Permits Initial Capacity 250,000 Dth/day - KeySpan 150,750 Dth/day Target In-Service Date November 1, 2008 78 Miles of 24" Pipe - 1,440 psig 20,620 HP of Compression Receipts from TransCanada Pipeline @ Chippawa, Ontario; Deliveries to Millennium @ Corning, New York Capital Cost Approximately $177 Million $45 Million spent as of December 31, 2007 Pipeline & Storage Empire Connector |
| DAWN Hub: Canadian, Gulf & Mid-Continent FUTURE: Alaska Rockies Express Pipeline - REX East Gulf & Appalachian Production FUTURE: Cove Point Expansion & Gulf LNG 21 |
| ROCKIES EXPRESS (REX) MILLENNIUM (NOV 2008) 525 MDth/day EMPIRE CONNECTOR (NOV 2008) 250 MDth/day CANADA Lake Ontario Lake Erie Leidy Ellisburg NY PA Chippawa Corning Independence Tuscarora Storage TransCanada Pendleton Niagara PA OH National Fuel Supply Corp. Empire Pipeline Bristoria Clarington Lamont TGP, DTI NFG West to East Project = Existing NFG Right of Way (New Pipeline) = New Right of Way (New Pipeline) = Existing Pipeline = Existing NFGSC Storage Field = Proposed Expansion of Existing Storage Gulf & Appalachian Production, Cove Point LNG, & Future Gulf LNG DAWN Hub: Canadian, Gulf & Mid-Continent; Future Alaska Our Prime Location 22 |
| Open Season Conducted May 2007 Initial Interest Strong 324-mile pipeline from Rockies Express (REX) terminus at Clarington, OH to Millennium Pipeline in Corning, NY Receipts from REX (~555,000 to 750,000 dth/d), Local Production, Cove Point Gas at Leidy and Corning Deliveries to Millennium and Empire at Corning Pipeline & Storage West to East Project |
| Phase I Pipeline Capacity 130,000 Dth/day Estimated In-Service Date Late Calendar 2009/Early Calendar 2010 23 Miles of 24" Pipe 800 HP of Compression Receipts from NFGSC and Other Storages and Upstream Pipelines Deliveries to Millennium and Empire Capital Cost Approximately $39 Million Development Activities Contingent on Market Pipeline & Storage Tuscarora Extension |
| Incremental storage capacity of ~ 7 Bcf No additional base gas required East Branch and Galbraith Storage Fields in western Pennsylvania Assessment ongoing Pipeline & Storage Storage Expansion Project |
| National Fuel Gas Distribution Corporation Utility Segment |
| Fiscal Year 2002 2003 2004 2005 2006 2007 1Q FY08 Earnings 0.62 0.7 0.59 0.46 0.55 0.597 0.24 1Q FY08 0.2 a Excludes SFAS 88 settlement loss of -$0.03 b Excludes out-of-period adjustment to symmetrical sharing of $0.03 a Fiscal Year Utility Diluted Earnings per Share b |
| At 12/31/04 At 12/31/05 At 12/31/06 At 12/31/07 30-59 days 11.9 16.6 11.9 11.4 60-89 days 5.5 6.4 6 5.4 90-119 days 3.7 4 4.4 3.9 120 days & over 46.2 52.6 64.3 56.7 Reserve for Bad Debt 15.1 31.5 34.2 32.7 Utility Accounts Receivable - Customer |
| New York Merchant Function Charge Varies with Cost of Gas Rates from the 2007 Adjudicated Case Continues Allowance Attributable to Uncollectible Expense Residential Non-Residential 2.832% .402% Multiplied by Gas Supply Cost Rate Utility Bad Debt Tracking |
| Fiscal Year TME Utility Average Use Per Residential Customer Normalized Mcf Per Account '73 '74 '75 '76 '77 '78 '79 '80 '81 '82 '83 '84 '85 '86 '87 '88 '89 '90 '91 '92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07 180.205 173.305 173.431 170.237 164.955 156.044 156.898 152.605 153.207 145.597 132.388 134.153 131.672 132.194 131.12 135.531 132.77 130.829 133.551 128.393 127.036 128.857 123.223 124.975 124.137 119.631 116.131 118.369 116.198 114.23 115.603 113.854 107.928 105.861 108.195 108.195 Mcf (New York) |
| Utility Rate Cases * Represents the approximate range of rate base filed for in this case. ** Black-box settlement in Pennsylvania. Pennsylvania New York Settled Adjudicated Approximate Rate Base $280-$290 MM* $699 MM Approximate Base Rate Revenue Increase $14.3 MM $1.8 MM Effective Date 1/1/2007 12/28/2007 Approximate Utility Capital Structure**: Approximate Utility Capital Structure**: Long-term Debt Cost Component Short-term Debt Cost Component Equity Component Return on Equity 45.0% 6.65% 5.0% 5.0 - 6.0% 50.0% 10.0 - 11.0% 45.54% 6.57% 9.32% 5.98% 44.35% 9.10% |
| Utility Rate Case Activity 11/30/06: The Pennsylvania PUC Approved the Settlement Agreement Reached in the Delivery Service Charge Rate Case Effective Date: 1/1/07 Revenue Increase: $14.3 MM Revenue Decoupling: Initially Proposed by The Utility in This Case. Will Instead be Pursued Via Active Participation in The Statewide Generic Proceeding Announced by The Pennsylvania PUC on September 28, 2006 Pennsylvania Effective Date: 12/28/07 Awarded $1.8 MM base rate increase & $10.8 MM rate component (for expenses associated with Conservation Incentive Program) Granted 9.1% ROE Approved Revenue Decoupling: Recovery of operating costs & margin is decoupled from customer usage Early Decision on Conservation Incentive Program; Became Effective 11/1/07 New York Case Concluded Case Concluded |
| Exploration & Production Segment |
| Fiscal Year 2002 2003 2004 2005 2006 2007 1Q FY08 Earnings 0.33 0.46 0.61 0.6 0.71 0.88 0.39 1Q FY07 0.2 a b a Excludes oil & gas impairment, loss on sale and cum. effect of change in acctg of - $0.85 b Excludes SFAS 88 settlement loss of -$0.01 and Adjustment of loss on sale of oil and gas assets of +$0.06 c Excludes loss from discontinued operations of -$0.54 and income tax adjustments of +$0.07 d Excludes gain on disposal of discontinued operations of +$1.41 and Earnings from discontinued operations of +$0.18. e Excludes earnings from discontinued operations of $0.04. Fiscal Year c d Seneca Resources Diluted Earnings per Share e |
| Fiscal 2007 Results: Increased U.S. Production to 39 BCFE Sold Canada operations for $232 million ($4.75/MCFE) Replaced over 500% of Appalachian production Fiscal 2008 Expectations: Continue U.S. Production Growth Appalachia up 15-20% Gulf up 5-10% California flat Accelerate drilling in Appalachia - 280 Well target Drill up to 10 horizontal wells in the Marcellus Shale Further Gulf exploration on trend to HI24L discovery Seneca Resources Positioned for Growth in 2008 |
| NY PA Gulf Coast - 7% 34 BCFE West - 71% 58 MMBOE (347 BCFE) Total: 491 BCFE Oil: 58% Gas: 42% East - 22% 110 BCFE At 09/30/2007 Seneca Resources Reserves by Region |
| NY PA Gulf Coast - 35% 41 MMCFED West - 45% 8,660 BOED (52 MMCFED) Total: 116 MMCFED 1Q FY 2008 East - 20% 23 MMCFED Seneca Resources Average Daily Production |
| 2006 2007 2008 Fcst East 5.5 6.3 7 West 19.4 18.3 18 Gulf 13.2 14.7 16.5 Canada 9.3 7.7 BCFE Fiscal Year 47.0 47.4 Approx. 38 - 44 Seneca Resources Annual Production by Division |
| 2006 2007 2008 East 27 39.1 58.6 West 36 41.4 45.7 Gulf 103 66.2 50.1 Canada 42 29.1 0 $176 Fiscal Year $US Millions Approx. $151-$159 $208 13% 22% 38% 50% 38% 32% 30% 24% 17% 20% 16% Seneca Resources Capital Expenditures by Division |
| 940,000 Total Net Acres Seneca Resources Appalachian Position |
| Upper Devonian/Silurian Drilled 233 Wells (53% increase over '06), while also improving EUR per well Replaced 530% of 2007 Appalachian production Increased Proved Developed reserves by ~20% Increased total Proved reserves by ~32% 2007 drilling program had an estimated IRR of over 30%* Increased daily production from 16.6 MMCFED (Sep '06) to 20 MMCFED (Sep '07), a 20% increase * Economics based on NYMEX pricing of $7/MCF and $70/BBL Seneca Resources Fiscal '07 Drilling Results |
| Fiscal Year Shallow Gas Program 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 Development 31 38 49 48 78 144 215 250 Exploration 5 2 6 10 2 2 3 4 8 18 30 Gas Price 2.36 2.13 3.21 4.98 2.84 5.2 5.51 7.15 8.83 6.758 Wells Drilled per Year 5 2 6 10 2 2 3 4 8 18 30 Seneca Resources Development & Exploration Drilling Target Average Gas Price $5.00 * Average Monthly NYMEX Closing Prices for each Fiscal Year |
| 2004 2005 2006 2007 BCFE 3.7 5.6 11.2 20.8 Wells 42 83 146 220 Fiscal Year Reserves Added by Drilling Wells Drilled per Year (Reserves Added by Drilling - excludes PUDS) Seneca Resources Appalachian Reserve Statistics |
| SRC minerals in yellow (860,000 Acres contributed to AMI) EOG minerals in blue (145,000 Acres contributed to AMI) Seneca Resources Marcellus Shale Activity |
| Cratonic Basin Stratigraphic Cross-section Ohio Pennsylvania Transgressive Black Shales Regressive Shales Clastic Sediments (Sands & Silts) Marcellus Geneseo Middlesex Rhinestreet Dunkirk Huron Ohio Shale Sunbury Foreland Basin West East * Modified Cross Section from "The Atlas of Major Appalachian Gas Plays", West Virginia Geological & Economic Survey, Mont Chateau Research Center, Morgantown, WV 26507-0879. Seneca Resources Appalachian Basin Black Shales |
| Marcellus Shale: Basin edge Marcellus Shale: > 100' thick Range Resources Marcellus Activity Seneca/EOG Marcellus Activity * Marcellus Isopach from "The Atlas of Major Appalachian Gas Plays", West Virginia Geological & Economic Survey, Mont Chateau Research Center, Morgantown, WV 26507-0879. Seneca Resources Marcellus Shale Activity |
| 1,000 BOEPD 230 BOEPD 640 BOEPD 4,700 BOEPD 2,200 BOEPD Seneca Resources California Properties |
| FY 2008 Forecast Operating Cash Flow: $132 MM FY 2008 Forecast CAPEX: $44-47 MM Net Cash Flow: $86 MM FY 2008 average hedge price at MWSS $65.72/BOE Seneca is a low-cost producer ~ $8/boe Long-lived reserves (R/P > 19 years) Efficient, profitable, and well-run operation Seneca Resources California |
| Why the Gulf of Mexico? Historic IRR for GOM program: 19% Cumulative $1.3 billion cash flow on $960 million investment Very large 3D seismic data base HI24L discovery in 2006/2007 Subsequently built a core acreage position along trend with similar opportunities New program is focused and selective Seneca Resources Gulf of Mexico |
| Fiscal Year 2008 Performance Targets F&D costs of no more than $5.75 per mcfe Program IRR of no less than 15% Seneca Resources Gulf of Mexico |
| Achieved our goals in 2007: Increased U.S. Production Sold Canada for $232 million Focused Gulf of Mexico program Continued to accelerate Appalachian drilling program Expect Growth in 2008: Forecast 5% production increase Further accelerate Appalachia drilling Drill up to 10 horizontal wells in the Marcellus Shale Seneca Resources Summary |
| Well-positioned for continued success: Major competitive advantage in Appalachia First rate E&P Team Proprietary database and knowledge Outstanding acreage position Long-lived production and positive cash flow from California Focused and successful program in the Gulf Seneca Resources Summary (cont'd.) |
| National Fuel Gas Company Share Buyback Date Authorized: December 8, 2005 Authorized Amount: Up to 8 Million Shares As of 12/31/07: 3,834,878 Shares Repurchased |
| National Fuel Gas Company Earnings Guidance FY 2008 (Sept 30 fiscal year end) Earnings Guidance $2.60-$2.80 per share. Includes: Exploration & Production Production between 38 and 44 Bcfe Pricing based on 7/24/07 NYMEX futures pricing strip for unhedged production No new 2008 production from announced venture with EOG Resources Utility New York rate determination in effect as of January 1, 2008 ROE 9.1% Weather Normalization and Revenue Decoupling |
| National Fuel Gas Company As a Value Company Financially Strong Diversified Asset Base Prime Location: Proximity to Canada Undeveloped Storage Pipeline Corridor to East Coast Appalachian Acreage Potential Strong Dividend Record |
| Energy Marketing Customers & Marketing Area Customers @ FYE 2004 2005 2006 2007 Residential 15,983 14,902 14,963 15,357 Commercial/Industrial 4,345 4,265 4,605 5,219 |
| Energy Marketing Diluted Earnings per Share Fiscal Year 2002 2003 2004 2005 2006 2007 1Q FY08 Earnings 0.11 0.07 0.07 0.06 0.07 0.062 0.01 1Q FY07 0.01 Fiscal Year * * Excludes resolution of a purchased gas contingency of +$.03. |
| Fiscal Year 2002 2003 2004 2005 2006 2007 Earnings 0.12 0.12 0.07 0.06 0.07 0.044 a Excludes gain from timber sale of +$1.26 b Excludes adj. of gain on timber sale of -$0.01 a b Fiscal Year Timber Diluted Earnings per Share |
| National Fuel Gas Company New York Stock Exchange NFG Fiscal Year End September Shares Outstanding (As of 01/31/08) ~83.5 Million Average Daily Trading Volume (12 Mo Ended 01/31/08) ~590,545 Market Capitalization (As of 02/22/08) $4.0 Billion Annual Dividend Rate (As of 12/31/07) $1.24 Years in Business 106 |
| 1/1/1992 2/1/1992 3/1/1992 4/1/1992 5/1/1992 6/1/1992 7/1/1992 8/1/1992 9/1/1992 10/1/1992 11/1/1992 12/1/1992 1/1/1993 2/1/1993 3/1/1993 4/1/1993 5/1/1993 6/1/1993 7/1/1993 8/1/1993 9/1/1993 10/1/1993 11/1/1993 12/1/1993 1/1/1994 2/1/1994 3/1/1994 4/1/1994 5/1/1994 6/1/1994 7/1/1994 8/1/1994 9/1/1994 10/1/1994 11/1/1994 12/1/1994 1/1/1995 2/1/1995 3/1/1995 4/1/1995 5/1/1995 6/1/1995 7/1/1995 8/1/1995 9/1/1995 10/1/1995 11/1/1995 12/1/1995 1/1/1996 2/1/1996 3/1/1996 4/1/1996 5/1/1996 6/1/1996 7/1/1996 8/1/1996 9/1/1996 10/1/1996 11/1/1996 12/1/1996 1/1/1997 2/1/1997 3/1/1997 4/1/1997 5/1/1997 6/1/1997 7/1/1997 8/1/1997 9/1/1997 10/1/1997 11/1/1997 12/1/1997 1/1/1998 2/1/1998 3/1/1998 4/1/1998 5/1/1998 6/1/1998 7/1/1998 8/1/1998 9/1/1998 10/1/1998 11/1/1998 12/1/1998 1/1/1999 2/1/1999 3/1/1999 4/1/1999 5/1/1999 6/1/1999 7/1/1999 8/1/1999 9/1/1999 10/1/1999 11/1/1999 12/1/1999 1/1/2000 2/1/2000 3/1/2000 12.1875 12.75 12.1875 12.5 12.6875 12.75 13.1875 14.125 13.0625 13.125 14.0625 14.75 14.8125 15.75 16 15.875 14.9375 16.6875 17.375 17.9375 18.1875 17.75 16.6875 17 17.4375 15.375 15 15 15.1875 14.6875 15 15.5625 14.9375 14.875 13 12.75 13.25 13.625 14 14.4375 14.4375 14.3125 14 14.0625 14.375 14.875 16.0625 16.8125 16.75 16.0625 17.3125 17.5625 17.1875 18 16.875 18.5 18.375 18.625 21.3125 20.625 21.125 21.5 21.375 20.8125 20.6875 20.96875 21.25 22.21875 22 22.0625 23.34375 24.34375 23 23.3125 23.5 23 21.1875 21.78125 20.65625 20.5625 23.5 23.625 22.96875 22.59375 21.15625 20.21875 19.625 21.875 23.75 24.25 23.46875 23.53125 23.59375 24.4375 25.03125 23.25 22.28125 20.46875 22.28125 National Fuel Gas Company Stock Price 2/22/2008 $47.86 NFG LISTED NYSE |
| Standard & Poor's Moody's Fitch, Inc. Long-Term Debt BBB+ Baa1 A- Outlook Stable Stable Stable Commercial Paper A-2 P-2 F2 NFG Debt Ratings at December 31, 2007 |
| National Fuel Gas Company Capital Resources Commercial Paper Program And Bilateral Credit Facilities - Aggregate Of $755 MM $0 borrowed at December 31, 2007 $300.0 MM Committed Credit Facility Through September 2010 $0 borrowed at December 31, 2007 Universal Shelf Registration on File - Additional $550 MM Can Be Issued As Debt Or Equity Securities Any offer and sale of such securities would be made only by means of a prospectus meeting requirements of securities laws |
| * Long-term Debt includes Current Portion of Long-term Debt. ** Includes Discontinued Operations. National Fuel Gas Company Capitalization $2.62 Billion at December 31, 2006 ** Long-Term Debt Short-Term Debt Shareholder Equity Capitalization 1096 72 1455 Short-Term Debt 3% Shareholder Equity 55% Long-Term* Debt 42% $2.69 Billion at December 31, 2007 Long-Term Debt Short-Term Debt Shareholder Equity Capitalization 999 0 1691 Short-Term Debt 0% Shareholder Equity 63% Long-Term* Debt 37% |
| 2002 2003 2004 2005 2006 2007 1Q FY08 CFPS 1.18 2.52 1.82 2.29 0.36 2.49 1.04 1Q FY07 0.29 Fiscal Year National Fuel Gas Company Free Cash Flow per Diluted Share |
| 2001 2002 2003 2004 2005 2006 2007 1Q FY08 2008E Utility 42.4 51.5 49.9 55.5 50.1 54.4 54.2 12.7 59 P & S 26 30.3 199.4 23.2 21.1 26 43.2 25.4 146 E & P 296.4 114.6 75.8 77.7 122.45 208.3 146.7 30.7 154 Energy Mkt. 0.116 0.1 0.2 0.0102 0.06 $- 0.08 0.009 0 Timber 3.7 25.6 3.5 2.8 18.9 2.3 3.657 0.98 0 Corp & Others 0.937 6.6 50.1 5.7 1.1 3.2 3.1 0.007 1 International 15.6 4.2 2.5 7.5 5.9 0 0 0 0 E&P Discont'd Ops 0 0 0 0 0 0 29.1 0 $ Millions $172.3 $219.5 Fiscal Year National Fuel Gas Company Expenditures for Long-Lived Assets $294.2 Approx. $357- $365 $280.0 $69.7 $381.4 |
| 2002 2003 2004 2005 2006 2007 1Q FY08 Utility 169 179 191 211 204 203 51 * Excludes SFAS 88 settlement loss of -$3.4 million Fiscal Year $ Millions * Utility O & M Expense |
| 2002 2003 2004 2005 2006 2007 1Q FY08 61.3 60.7 65.1 65.4 66.3 61.2 16 * Excludes SFAS 88 settlement loss of -$3.0 million * Pipeline & Storage O & M Expense $ Millions Fiscal Year |
| Production: 39.3 BCFE Operating Revenue $324.0 MM Net Income $ 74.9 MM Expenses/Mcfe 4th Quarter Fiscal Year DD&A $2.19 $1.99 LOE $1.28 $1.23 G&A $0.63 $0.51 * Excludes discontinued operations of Canada. Seneca Resources 2007 Year End Results * |
| Appalachia Stratigraphic Column national fuel 71 Exploration & Production Devonian Shales (EOG JointVenture) Depth: 4,500' - 8,000' (PA) Bass Island, Lockport, Medina, Whirlpool Depth: 2,000' - 6,000' (NY Target zones) Upper Devonian Sandstones (Primary Drilling Target) Depth: 800' - 4,500' (PA) Onondaga Lime (Seneca Discovery) Depth: 2,500' - 6,000' (Southern NY / PA) Trenton, Black River Depth: 1,800' - 2,500' (Central NY) 8,000' - 15,000' (Southern NY / PA) Theresa Depth: 5,000' - 7,000' (Southern NY) AGA FINANCIAL FORUM Apr 30, 2007 |
| Production: 38 - 44 BCFE Number of Wells to be Drilled: 309 - 368 Expenses/Mcfe Estimated Range DD&A $2.20 - $2.30 LOE $1.10 - $1.25 Other Taxes (% of Revenue) $0.20 - $0.25 Other Operating Expenses $ 6 MM - $ 7 MM General and Administrative $20 MM - $22 MM Seneca Resources Forecast Data for Fiscal 2008 |
| Volume Highest Ceiling Price $17.81 / MCF 9 Months Remaining Fiscal 2008 $ 8.48 / MCF 0.7 BCF Gas Lowest Floor Price No-cost Collars $ 8.45 / MCF 8.9 BCF Gas $65.72 / BBL 1.2 MMBBL Oil Average Hedge Price Volume Swaps Fiscal 2009 $68.35 / BBL 0.7 MMBBL Oil Average Hedge Price Volume Swaps $ 8.95 / MCF 5.7 BCF Gas Seneca Resources Hedging Summary |
| Certain statements contained herein, including those regarding future earnings, developments and operational results, and those which use words such as "anticipates," "estimates," "expects," "intends," "plans," "predicts," "projects," and similar expressions, are "forward-looking statements" as defined by the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company's expectations, beliefs and projections contained herein are expressed in good faith and are believed to have a reasonable basis, but there can be no assurance that such expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: changes in laws and regulations to which the Company is subject, including changes in tax, environmental, safety and employment laws and regulations; changes in economic conditions, including economic disruptions caused by terrorist activities, acts of war or major accidents; changes in demographic patterns and weather conditions, including the occurrence of severe weather, such as hurricanes; changes in the availability and/or price of natural gas or oil and the effect of such changes on the accounting treatment of derivative financial instruments or the valuation of the Company's natural gas and oil reserves; impairments under the Securities and Exchange Commission's full cost ceiling test for natural gas and oil reserves; changes in the availability and/or price of derivative financial instruments; changes in the price differentials between various types of oil; inability to obtain new customers or retain existing ones; significant changes in competitive factors affecting the Company; governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; unanticipated impacts of restructuring initiatives in the natural gas and electric industries; significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs or plans, including changes in the plans of the sponsors of the proposed Millennium Pipeline with respect to that project; the nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits; occurrences affecting the Company's ability to obtain funds from operations or from issuances of short-term notes or debt or equity securities to finance needed capital expenditures and other investments, including any downgrades in the Company's credit ratings; uncertainty of oil and gas reserve estimates; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; ability to successfully identify, drill for and produce economically viable natural gas and oil reserves; significant changes from expectations in the Company's actual production levels for natural gas or oil; regarding foreign operations, changes in trade and monetary policies, inflation and exchange rates, taxes, operating conditions, laws and regulations related to foreign operations, and political and governmental changes; significant changes in tax rates or policies or in rates of inflation or interest; significant changes in the Company's relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur; changes in accounting principles or the application of such principles to the Company; the cost and effects of legal and administrative claims against the Company; changes in actuarial assumptions and the return on assets with respect to the Company's retirement plan and post-retirement benefit plans; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide post-retirement benefits; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events. Safe Harbor For Forward Looking Statements |
| This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company's operating results in a manner that is focused on the performance of the Company's ongoing operations. The Company's management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP. Comparable GAAP Financial Measure Slides and Reconciliations |
| P&S Utility Timber Energy Mkt. Corp. & Other E&P NI 55.5 53.9 3.9 8.1 8.1 224 National Fuel Gas Company Net Income $353.5 Million 12 Months Ended December 31, 2007 |
| Earnings Dividends Paid 85 0.95 0.48 86 0.88 0.53 87 0.88 0.58 88 0.83 0.61 89 0.97 0.64 90 0.92 0.68 91 0.82 0.72 92 0.97 0.74 93 1.08 0.76 94 1.16 0.78 95 1.02 0.8 96 1.39 0.82 97 1.49 0.85 98 0.3 0.88 99 1.47 0.91 '00 1.61 0.94 '01 0.82 0.97 '02 1.46 1.02 '03 2.2 1.04 '04 2.01 1.09 '05 2.23 1.13 '06 1.61 1.17 '07 3.96 1.21 National Fuel Gas Company Earnings vs. Dividends Paid Fiscal Year Dividends Paid Earnings per Diluted Share $3.96 |
| 2002 2003 2004 2005 2006 2007 1Q FY08 Pipeline & Storage 0.37 0.56 0.58 0.71 0.65 0.66 0.15 All Other Segments 1.09 1.64 1.43 1.52 0.96 3.3 0.67 $2.20 $2.01 $2.23 Fiscal Year Pipeline & Storage vs. Consolidated NFG Diluted Earnings per Share $1.61 $3.96 $0.82 |
| 2002 2003 2004 2005 2006 2007 1Q FY08 Utility 0.62 0.7 0.56 0.46 0.58 0.6 0.24 All Other Segments 0.84 1.5 1.45 1.77 1.03 3.36 0.58 $2.20 $2.01 $2.23 Fiscal Year Utility vs. Consolidated NFG Diluted Earnings per Share $1.61 $3.96 $0.82 |
| 2002 2003 2004 2005 2006 2007 1Q FY08 Exploration & Production 0.33 -0.39 0.66 0.6 0.24 2.47 0.39 All Other Segments 1.13 2.59 1.35 1.63 1.37 1.49 0.43 $2.20 $2.01 $2.23 Fiscal Year Exploration & Production vs. Consolidated NFG Diluted Earnings per Share $1.61 $3.96 $0.82 |
| 2002 2003 2004 2005 2006 2007 1Q FY08 Energy Marketing 0.11 0.07 0.07 0.06 0.07 0.09 0.01 All Other Segments 1.35 2.13 1.94 2.17 1.54 3.87 0.81 Fiscal Year Energy Marketing vs. Consolidated NFG Diluted Earnings per Share $2.20 $2.01 $2.23 $1.61 $3.96 $0.82 |
| 2002 2003 2004 2005 2006 2007 1Q FY08 Timber 0.12 1.38 0.06 0.06 0.07 0.04 0 All Other Segments 1.34 0.82 1.95 2.17 1.54 3.92 0.82 $2.20 $2.01 $2.23 Fiscal Year Timber vs. Consolidated NFG Diluted Earnings per Share $1.61 $3.96 $0.82 |
| 2002 2003 2004 2005 2006 2007 1Q FY08 4.29 4 5.27 3.73 5.48 4.62 0.88 Fiscal Year National Fuel Gas Company Net Cash Provided by Operating Activities per Diluted Share |
| 2001 2002 2003 2004 2005 2006 2007 1Q FY08 387.9 205.8 104.8 163.2 103.3 297.4 101.8 10.6 Fiscal Year National Fuel Gas Company Consolidated Net Cash Used in Investing Activities $ Millions |
| 2002 2003 2004 2005 2006 2007 1Q FY08 Utility 169 179 194 211 204 203 51 All Other Segments 225 151 180 177 191 193 51.5 Fiscal Year $ Millions Utility vs. Consolidated NFG O & M Expense from Continuing Operations $330 $374 $388 $395 $396 $102.5 |
| 2002 2003 2004 2005 2006 2007 1Q FY08 Pipeline & Storage 61 61 68 65 66 61 16 All Other Segments 333 269 306 323 329 335 86.5 Fiscal Year $ Millions Pipeline & Storage vs. Consolidated NFG O & M Expense from Continuing Operations $330 $374 $388 $395 $396 $102.5 |
Reconciliation of Segment Net Income to
Consolidated Net Income
(‘000)
| | | | | | | | | |
| | | 12 Mos Ended 12/31/07 | |
| Utility | | | | | | $ | 53,929 | |
| | | | | | | | | |
| Pipeline & Storage | | $ | 50,689 | | | | | |
| Plus: Reversal of reserve for preliminary project costs | | | 4,787 | | | | 55,476 | |
| | | | | | | | |
| | | | | | | | | |
| Exploration & Production | | $ | 92,020 | | | | | |
| Plus: Gain on disposal of discontinued operations. | | | 120,301 | | | | | |
| Earnings from discontinued operations | | | 11,647 | | | | 223,968 | |
| | | | | | | | |
| | | | | | | | | |
| Energy Marketing | | | | | | | 8,125 | |
| | | | | | | | | |
| Timber | | | | | | | 3,908 | |
| | | | | | | | | |
| Corporate & Other | | | | | | | 8,133 | |
| | | | | | | | |
| | | | | | | | | |
| Consolidated Net Income | | | | | | $ | 353,539 | |
| | | | | | | | |
NATIONAL FUEL GAS COMPANY
AND SUBSIDIARIES
RECONCILIATION TO REPORTED EARNINGS
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Fiscal Year | | | Fiscal Year | | | Fiscal Year | | | Fiscal Year | | | Fiscal Year | | | 3 Months | |
| (Diluted Earnings Per Share) | | Ended | | | Ended | | | Ended | | | Ended | | | Ended | | | Ended | |
| | | September 30, 2003 | | | September 30, 2004 | | | September 30, 2005 | | | September 30, 2006 | | | September 30, 2007 | | | December 31, 2007 | |
| | | |
Utility | | | | | | | | | | | | | | | | | | | | | | | | |
| Reported earnings | | $ | 0.70 | | | $ | 0.56 | | | $ | 0.46 | | | $ | 0.58 | | | $ | 0.60 | | | $ | 0.24 | |
| Out-of-period adjustment to symmetical sharing | | | — | | | | — | | | | — | | | | (0.03 | ) | | | — | | | | — | |
| Pension settlement loss | | | — | | | | 0.03 | | | | — | | | | — | | | | — | | | | — | |
| | | |
| Earnings before non-recurring items | | | 0.70 | | | | 0.59 | | | | 0.46 | | | | 0.55 | | | | 0.60 | | | | 0.24 | |
| | | |
Pipeline and Storage | | | | | | | | | | | | | | | | | | | | | | | | |
| Reported earnings | | | 0.56 | | | | 0.58 | | | | 0.71 | | | | 0.65 | | | | 0.66 | | | | 0.15 | |
| Reversal of reserve for preliminary project costs | | | — | | | | — | | | | — | | | | — | | | | (0.06 | ) | | | — | |
| Discontinuance of hedge accounting | | | — | | | | — | | | | — | | | | — | | | | (0.02 | ) | | | — | |
| Pension settlement loss | | | — | | | | 0.02 | | | | — | | | | — | | | | — | | | | — | |
| Gain associated with insurance proceeds | | | — | | | | — | | | | (0.05 | ) | | | — | | | | — | | | | — | |
| Base gas sale | | | | | | | | | | | (0.03 | ) | | | — | | | | — | | | | — | |
| | | |
| Earnings before non-recurring items | | | 0.56 | | | | 0.60 | | | | 0.63 | | | | 0.65 | | | | 0.58 | | | | 0.15 | |
| | | |
Exploration and Production | | | | | | | | | | | | | | | | | | | | | | | | |
| Reported earnings | | | (0.39 | ) | | | 0.66 | | | | 0.60 | | | | 0.24 | | | | 2.47 | | | | 0.39 | |
| Gain on disposal of discontinued operations | | | — | | | | — | | | | — | | | | — | | | | (1.41 | ) | | | — | |
| Earnings from discontinued operations | | | — | | | | — | | | | — | | | | — | | | | (0.18 | ) | | | — | |
| Income tax adjustments | | | — | | | | — | | | | — | | | | (0.07 | ) | | | — | | | | — | |
| Loss on sale of oil and gas assets | | | 0.48 | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Impairment of oil and gas producing properties | | | 0.36 | | | | — | | | | — | | | | 0.54 | | | | — | | | | — | |
| Cumulative Effect of Change in Accounting | | | 0.01 | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Adjustment of loss on sale of oil and gas assets | | | — | | | | (0.06 | ) | | | — | | | | — | | | | — | | | | — | |
| Pension settlement loss | | | — | | | | 0.01 | | | | — | | | | — | | | | — | | | | — | |
| | | |
| Earnings before non-recurring items | | | 0.46 | | | | 0.61 | | | | 0.60 | | | | 0.71 | | | | 0.88 | | | | 0.39 | |
| | | |
International | | | | | | | | | | | | | | | | | | | | | | | | |
| Reported earnings | | | (0.12 | ) | | | 0.07 | | | | | | | | | | | | | | | | | |
| Cumulative Effect of Change in Accounting | | | 0.10 | | | | — | | | see | | | | | | | | | | | | |
| Pension settlement loss | | | — | | | | — | | | "Discontinued | | | | | | | | | | | | |
| Tax rate change | | | — | | | | (0.06 | ) | | Operations" | | | | | | | | �� | | | | |
| | | | | | | | | | | | | | | | | | | |
| Repatriation tax | | | | | | | | | | below | | | | | | | | | | | | |
| Earnings before non-recurring items | | | (0.02 | ) | | | 0.01 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Energy Marketing | | | | | | | | | | | | | | | | | | | | | | | | |
| Reported earnings | | | 0.07 | | | | 0.07 | | | | 0.06 | | | | 0.07 | | | | 0.09 | | | | 0.01 | |
| Resolution of a purchased gas contingency | | | — | | | | — | | | | — | | | | — | | | | (0.03 | ) | | | — | |
| Pension settlement loss | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | |
| Earnings before non-recurring items | | | 0.07 | | | | 0.07 | | | | 0.06 | | | | 0.07 | | | | 0.06 | | | | 0.01 | |
| | | |
Timber | | | | | | | | | | | | | | | | | | | | | | | | |
| Reported earnings | | | 1.38 | | | | 0.06 | | | | 0.06 | | | | 0.07 | | | | 0.04 | | | | — | |
| Gain on sale of timber assets | | | (1.26 | ) | | | — | | | | — | | | | — | | | | — | | | | — | |
| Pension settlement loss | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Adjustment of gain on sale of timber properties | | | — | | | | 0.01 | | | | — | | | | — | | | | — | | | | — | |
| | | |
| Earnings before non-recurring items | | | 0.12 | | | | 0.07 | | | | 0.06 | | | | 0.07 | | | | 0.04 | | | | — | |
| | | |
Corporate and All Other | | | | | | | | | | | | | | | | | | | | | | | | |
| Reported earnings | | | — | | | | 0.01 | | | | (0.08 | ) | | | — | | | | 0.10 | | | | 0.03 | |
| Pension settlement loss | | | — | | | | 0.02 | | | | — | | | | — | | | | — | | | | — | |
| | | |
| Earnings before non-recurring items | | | — | | | | 0.03 | | | | (0.08 | ) | | | — | | | | 0.10 | | | | 0.03 | |
| | | |
Consolidated | | | | | | | | | | | | | | | | | | | | | | | | |
| Reported earnings | | | 2.20 | | | | 2.01 | | | | | | | | | | | | | | | | | |
| Total non-recurring items from above | | | (0.31 | ) | | | (0.03 | ) | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Earnings before non-recurring items | | $ | 1.89 | | | $ | 1.98 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Consolidated Earnings from Continuing Operations | | | | | | | | | | | | | | | | | | | | | | | | |
| Reported earnings from continuing operations | | | | | | | | | | | 1.81 | | | | 1.61 | | | | 3.96 | | | | 0.82 | |
| Total non-recurring items from above | | | | | | | | | | | (0.08 | ) | | | 0.44 | | | | (1.70 | ) | | | — | |
| | | | | | | | | | | |
| Earnings from continuing operations before non-recurring items | | | | | | | | | | $ | 1.73 | | | $ | 2.05 | | | $ | 2.26 | | | $ | 0.82 | |
| | | | | | | | | | | |
Discontinued Operations | | | | | | | | | | | | | | | | | | | | | | | | |
| Reported earnings from discontinued operations | | | | | | | | | | | 0.42 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
Consolidated | | | | | | | | | | | | | | | | | | | | | | | | |
| Reported earnings | | | | | | | | | | $ | 2.23 | | | $ | 1.61 | | | $ | 3.96 | | | $ | 0.82 | |
| | | | | | | | | | | |
Reconciliation of Pipeline & Storage Operating Revenues to
Consolidated Operating Revenues Fiscal 2007
($Millions)
| | | | | |
| Pipeline Revenues | | $ | 122.9 | |
| Storage Revenues | | $ | 67.1 | |
| Other Revenues | | $ | 21.9 | |
| | | | |
| Total Pipeline & Storage Revenues | | $ | 211.9 | |
| All Other Segments | | $ | 1,827.7 | |
| | | | |
| Total Corporation | | $ | 2,039.6 | |
| | | | |
Reconciliation of Pipeline & Storage O&M Expense to
Consolidated O&M Expense (From Continuing Operations)
($000s)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2003 | | | 2004 | | | 2005 | | | 2006 | | | 2007 | | | 1Q FY2008 | |
| | | |
| Pipeline & Storage | | $ | 61,286 | | | $ | 65,071 | | | $ | 65,397 | | | $ | 66,340 | | | $ | 61,230 | | | $ | 15,999 | |
| SFAS 88 Pension Settlement | | | — | | | | 3,026 | | | | — | | | | — | | | | — | | | | — | |
| All Other Segments | | | 269,030 | | | | 305,913 | | | | 322,697 | | | | 328,949 | | | | 335,178 | | | | 86,456 | |
| | | |
| Total Corporation | | $ | 330,316 | | | $ | 374,010 | | | $ | 388,094 | | | $ | 395,289 | | | $ | 396,408 | | | $ | 102,455 | |
| | | |
Reconciliation of Utility Segment O&M Expense to
Consolidated O&M Expense (From Continuing Operations)
($000s)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2003 | | | 2004 | | | 2005 | | | 2006 | | | 2007 | | | 1Q FY2008 | |
| | | |
| Utility Segment | | $ | 179,052 | | | $ | 190,669 | | | $ | 211,019 | | | $ | 204,330 | | | $ | 202,965 | | | $ | 50,981 | |
| SFAS 88 Pension Settlement | | | — | | | | 3,374 | | | | — | | | | — | | | | — | | | | — | |
| All Other Segments | | | 151,264 | | | | 179,967 | | | | 177,075 | | | | 190,959 | | | | 193,443 | | | | 51,474 | |
| | | |
| Total Corporation | | $ | 330,316 | | | $ | 374,010 | | | $ | 388,094 | | | $ | 395,289 | | | $ | 396,408 | | | $ | 102,455 | |
| | | |
Reconciliation of Utility Segment Aged Accounts Receivable to
Consolidated Accounts Receivable — Net
($Millions)
| | | | | | | | | | | | | | | | | |
| | | at 12/31/04 | | | at 12/31/05 | | | at 12/31/06 | | | at 12/31/07 | |
| | | |
| Utility Aged Accounts Receivable | | $ | 67.7 | | | $ | 71.8 | | | $ | 87.9 | | | $ | 103.8 | |
| Utility Current/Other Accounts Receivable | | $ | 78.3 | | | $ | 135.1 | | | $ | 60.9 | | | $ | 79.7 | |
| | | |
| Utility Gross Accounts Receivable | | $ | 146.0 | | | $ | 206.9 | | | $ | 148.8 | | | $ | 183.5 | |
| Utility Reserve for Bad Debt | | $ | (15.1 | ) | | $ | (31.5 | ) | | $ | (34.2 | ) | | $ | (32.7 | ) |
| | | |
| Utility Net Accounts Receivable | | $ | 130.9 | | | $ | 175.4 | | | $ | 114.6 | | | $ | 150.8 | |
| | | |
| All Other Segments Gross Accounts Receivable | | $ | 68.3 | | | $ | 115.2 | | | $ | 79.4 | | | $ | 93.0 | |
| All Other Segments Reserve for Bad Debts | | $ | (4.7 | ) | | $ | (1.8 | ) | | $ | (1.5 | ) | | $ | (1.4 | ) |
| | | |
| All Other Segments Net Accounts Receivable | | $ | 66.9 | | | $ | 113.8 | | | $ | 78.0 | | | $ | 91.6 | |
| | | |
| Total Corporation Accounts Receivable — Net | | $ | 197.8 | | | $ | 289.2 | | | $ | 192.6 | | | $ | 242.4 | |
| | | |
Reconciliation of National Fuel Gas Expenditures for Long-lived Assets to
Consolidated Net Cash Used in Investing Activities
(‘000)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2003 | | | 2004 | | | 2005 | | | 2006 | | | 2007 | | | 1Q FY08 | |
| | | |
| Capital Expenditures | | $ | (152,251 | ) | | $ | (172,341 | ) | | $ | (219,530 | ) | | $ | (294,159 | ) | | $ | (276,728 | ) | | $ | (69,744 | ) |
| Investment in Subsidiaries, Net of Cash | | | (228,814 | ) | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Investment in Partnerships | | $ | (375 | ) | | $ | — | | | $ | — | | | $ | — | | | $ | (3,300 | ) | | $ | — | |
| | | |
| Expenditures for Long Lived Assets | | $ | (381,440 | ) | | $ | (172,341 | ) | | $ | (219,530 | ) | | $ | (294,159 | ) | | $ | (280,028 | ) | | $ | (69,744 | ) |
| Expenditures for Long Lived Assets | | $ | (381,440 | ) | | $ | (172,341 | ) | | $ | (219,530 | ) | | $ | (294,159 | ) | | $ | (280,028 | ) | | $ | (69,744 | ) |
| Net Proceeds from Sale of Foreign Subsidiary | | $ | — | | | $ | — | | | $ | 111,619 | | | $ | — | | | $ | 232,092 | | | $ | — | |
| Cash Held in Escrow | | | | | | | | | | | | | | | | | | $ | (58,248 | ) | | | 58,397 | |
| Net Proceeds from Sale of Timber Properties | | $ | 186,014 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Net Proceeds from Sale of Oil and Gas Producing Properties | | $ | 78,531 | | | $ | 7,162 | | | $ | 1,349 | | | $ | 13 | | | $ | 5,137 | | | $ | 1,500 | |
| Other | | $ | 12,065 | | | $ | 1,974 | | | $ | 3,238 | | | $ | (3,230 | ) | | $ | (725 | ) | | $ | (761 | ) |
| | | |
| Net Cash Used in Investing Activities | | $ | (104,830 | ) | | $ | (163,205 | ) | | $ | (103,324 | ) | | $ | (297,376 | ) | | $ | (101,772 | ) | | $ | (10,608 | ) |
| | | |
Reconciliation of Exploration & Production Segment Capital Expenditures to
Consolidated Capital Expenditures
($000s)
| | | | | | | | | | | | | |
| | | 2006 | | | 2007 | | | 2008E | |
| | | |
| Exploration & Production Capital Expenditures | | $ | 208,303 | | | $ | 146,687 | | | $ | 151,000-$159,000 | |
| Expenditures from Discontinued Operations | | | | | | | 29,129 | | | | | |
| | | |
| Total Exploration & Production Capital Expenditures | | $ | 208,303 | | | $ | 175,816 | | | $ | 151,000-$159,000 | |
| All Other | | | 85,856 | | | $ | 100,912 | | | $ | 206,000 | |
| | | |
| Total Corporation | | $ | 294,159 | | | $ | 276,728 | | | $ | 357,000-$365,000 | |
| | | |
Reconciliation of Exploration & Production Operating Revenue to
Consolidated Operating Revenue
($000s)
| | | | | |
| | | 2007 | |
| Exploration & Production | | $ | 324,037 | |
| All Other Segments | | | 1,715,529 | |
| | | | |
| Consolidated Operating Revenue | | $ | 2,039,566 | |
| | | | |
Reconciliation of Exploration & Production Net Income to
Consolidated Net Income
($000s)
| | | | | |
| | | 2007 | |
| Exploration & Production (Income from Continuing Operations) | | $ | 74,889 | |
| Income from Discontinued Operations, Net of Tax | | | 15,479 | |
| Gain on Disposal of Discontinued Operations, Net of Tax | | | 120,301 | |
| | | | |
| Total Exploration & Production | | $ | 210,669 | |
| All Other Segments | | | 126,786 | |
| | | | |
| Consolidated Net Income | | $ | 337,455 | |
| | | | |
Reconciliation of Exploration & Production Lease Operating Expense (LOE) to
Consolidated O&M
($000s)
| | | | | |
| | | 2007 | |
Exploration & Production LOE | | $ | 43,916 | |
Exploration & Production Property, Franchise and Other Taxes | | | 4,493 | |
| | | | |
| Exploration & Production Total LOE * | | $ | 48,409 | |
| | | | |
Exploration & Production LOE | | $ | 43,916 | |
| Exploration & Production Other O&M | | | 28,324 | |
| | | | |
| Exploration & Production Total O&M | | $ | 72,240 | |
| All Other Segments O&M | | | 324,168 | |
| | | | |
| Total Consolidated O&M | | $ | 396,408 | |
| | | | |
Exploration & Production Property, Franchise and Other Taxes | | $ | 4,493 | |
| All Other Segments Property, Franchise and Other Taxes | | | 66,167 | |
| | | | |
| Total Consolidated Property Franchise and Other Taxes | | $ | 70,660 | |
| | | | |
Reconciliation of Exploration & Production Depreciation, Depletion and Amortization to
Consolidated Depreciation, Depletion and Amortization (DD&A)
($000s)
| | | | | |
| | | 2007 | |
| Exploration & Production DD&A * | | $ | 78,174 | |
| All Other Segments DD&A | | | 79,745 | |
| | | | |
| Consolidated DD&A | | $ | 157,919 | |
| | | | |
* DD&A and Total LOE cost per Mcf equivalent equals Exploration & Production DD&A and Total LOE costs, respectively, for the referenced fiscal period, divided by the Total Gas & Oil Production (Mmcfe) in that same fiscal period.
Reconciliation of Exploration & Production General & Administrative Costs to
Consolidated O&M
($000s)
| | | | | |
| | | 2007 | |
| Exploration & Production General & Administrative * | | $ | 19,946 | |
| Exploration & Production All Other O&M | | | 52,294 | |
| | | | |
| Exporation & Production Total O&M | | $ | 72,240 | |
| All Other Segments O&M | | | 324,168 | |
| | | | |
| Total Consolidated O&M | | $ | 396,408 | |
| | | | |
* General and Administrative cost per Mcf equivalent equals Exploration & Production General and Administrative cost, for the referenced fiscal period, divided by the Total Gas & Oil Production (Mmcfe) in that same fiscal period.
Free Cash Flow Per Diluted Share Calculation
and Reconciliation to Net Cash Provided by Operating Activities
($000s)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Fiscal Year Ended | | | Fiscal Year Ended | | | Fiscal Year Ended | | | Fiscal Year Ended | | | 3 Mos Ending | | | Fiscal Year Ended | | | 3 Mos Ending | |
| | | September 30, 2003 | | | September 30, 2004 | | | September 30, 2005 | | | September 30, 2006 | | | 31-Dec-06 | | | September 30, 2007 | | | 31-Dec-07 | |
| Net Income | | $ | 178,944 | | | $ | 166,586 | | | $ | 189,488 | | | $ | 138,091 | | | $ | 54,520 | | | $ | 337,455 | | | $ | 70,604 | |
| DD&A | | | 195,226 | | | | 189,538 | | | | 193,144 | | | | 179,615 | | | | 42,825 | | | | 170,803 | | | | 44,121 | |
| Impairment of Oil and Gas Producing Properties | | | 42,774 | | | | — | | | | — | | | | 104,739 | | | | — | | | | — | | | | — | |
| Impairment of Investment in Partnership | | | — | | | | — | | | | 4,158 | | | | — | | | | — | | | | — | | | | — | |
| (Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions | | | 703 | | | | (19 | ) | | | (1,372 | ) | | | 1,067 | | | | (18 | ) | | | (3,366 | ) | | | 431 | |
| Gain on Sale of Discontinued Operations | | | — | | | | — | | | | (27,386 | ) | | | — | | | | — | | | | (159,873 | ) | | | — | |
| Loss (Gain) on Sale of Oil and Gas Properties | | | 58,472 | | | | (4,645 | ) | | | — | | | | — | | | | — | | | | — | | | | — | |
| (Gain) Loss on Sale of Timber Properties | | | (168,787 | ) | | | 1,252 | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Deferred Income Taxes | | | 78,369 | | | | 40,329 | | | | 40,388 | | | | (5,230 | ) | | | 11,198 | | | | 52,847 | | | | 5,296 | |
| Minority Interest in Foreign Subsidiaries | | | 785 | | | | 1,933 | | | | 2,645 | | | | — | | | | — | | | | — | | | | — | |
| Cumulative Effect of Changes in Accounting | | | 8,892 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Other | | | 11,289 | | | | 9,839 | | | | 7,390 | | | | 4,829 | | | | 5,728 | | | | 16,399 | | | | 4,916 | |
| | | |
| | | | 406,667 | | | | 404,813 | | | | 408,455 | | | | 423,111 | | | | 114,253 | | | | 414,265 | | | | 125,368 | |
| Less: Dividends Paid on Common Stock (Including Dividends to Minority Interests) | | | (84,530 | ) | | | (89,092 | ) | | | (106,835 | ) | | | (98,266 | ) | | | (25,026 | ) | | | (100,632 | ) | | | (25,873 | ) |
| Plus: Net Proceeds from Sale of Oil and Gas Producing Properties | | | 78,531 | | | | 7,162 | | | | 1,349 | | | | 13 | | | | 2,141 | | | | 5,137 | | | | 1,500 | |
| Plus: Net Proceeds from Sale of Timber Properties | | | 186,014 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Plus: Net Proceeds from Sale of Foreign Subsidiary | | | — | | | | — | | | | 111,619 | | | | — | | | | — | | | | 232,092 | | | | — | |
| Plus: Investment in Partnership | | | — | | | | — | | | | — | | | | — | | | | — | | | | (3,300 | ) | | | — | |
| Plus: Cash Held in Escrow | | | — | | | | — | | | | — | | | | — | | | | — | | | | (58,248 | ) | | | 58,397 | |
| Less: Expenditures for Long-Lived Assets | | | (381,440 | ) | | | (172,341 | ) | | | (219,530 | ) | | | (294,159 | ) | | | (66,952 | ) | | | (276,728 | ) | | | (69,744 | ) |
| | | |
| Free Cash Flow | | $ | 205,242 | | | $ | 150,542 | | | $ | 195,058 | | | $ | 30,699 | | | $ | 24,416 | | | $ | 212,586 | | | $ | 89,648 | |
| | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Weighted Average Diluted Shares | | | 81,358 | | | | 82,900 | | | | 85,029 | | | | 86,028 | | | | 84,731 | | | | 85,301 | | | | 85,819 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Free Cash Flow Per Share | | $ | 2.52 | | | $ | 1.82 | | | $ | 2.29 | | | $ | 0.36 | | | $ | 0.29 | | | $ | 2.49 | | | $ | 1.04 | |
| | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Reconciliation to Net Cash Provided by Operating Activities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Free Cash Flow | | $ | 205,242 | | | $ | 150,542 | | | $ | 195,058 | | | $ | 30,699 | | | $ | 24,416 | | | $ | 212,586 | | | $ | 89,648 | |
| Add Back: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expenditures for Long-Lived Assets | | | 381,440 | | | | 172,341 | | | | 219,530 | | | | 294,159 | | | | 66,952 | | | | 276,728 | | | | 69,744 | |
| Dividends Paid on Common Stock (Inc. Dividends to Minority Interests) | | | 84,530 | | | | 89,092 | | | | 106,835 | | | | 98,266 | | | | 25,026 | | | | 100,632 | | | | 25,873 | |
| Investment in Partnership | | | — | | | | — | | | | — | | | | — | | | | — | | | | 3,300 | | | | — | |
| Cash Held in Escrow | | | — | | | | — | | | | — | | | | — | | | | — | | | | 58,248 | | | | (58,397 | ) |
| Deduct: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Excess Tax Benefits Associated with Stock-Based Compensation Awards | | | 0 | | | | 0 | | | | 0 | | | | (6,515 | ) | | | (13,717 | ) | | | (13,689 | ) | | | (16,275 | ) |
| Net Proceeds from Sale of Oil and Gas Producing Properties | | | (78,531 | ) | | | (7,162 | ) | | | (1,349 | ) | | | (13 | ) | | | (2,141 | ) | | | (5,137 | ) | | | (1,500 | ) |
| Net Proceeds from Sale of Timber Properties | | | (186,014 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Net Proceeds from Sale of Foreign Subsidiary | | | — | | | | — | | | | (111,619 | ) | | | — | | | | — | | | | (232,092 | ) | | | — | |
| Change in: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Hedging Collateral Deposits | | | (1,109 | ) | | | (7,151 | ) | | | (69,172 | ) | | | 58,108 | | | | 9,916 | | | | 15,610 | | | | 2,070 | |
| Receivables and Unbilled Utility Revenue | | | (28,382 | ) | | | 4,840 | | | | (31,246 | ) | | | (12,343 | ) | | | (91,875 | ) | | | 5,669 | | | | (127,894 | ) |
| Gas Stored Underground & Materials and Supplies | | | (13,826 | ) | | | 13,662 | | | | 1,934 | | | | 1,679 | | | | 5,324 | | | | (5,714 | ) | | | (186 | ) |
| Unrecovered Purchased Gas Costs | | | (16,261 | ) | | | 21,160 | | | | (7,285 | ) | | | 1,847 | | | | (11,021 | ) | | | (1,799 | ) | | | 2,583 | |
| Prepayments and Other Current Assets | | | (12,628 | ) | | | 37,390 | | | | (30,390 | ) | | | (39,572 | ) | | | 20,398 | | | | 18,800 | | | | 10,422 | |
| Accounts Payable | | | 13,699 | | | | (5,134 | ) | | | 48,089 | | | | (23,144 | ) | | | 11,736 | | | | (26,002 | ) | | | 42,398 | |
| Amounts Payable to Customers | | | 692 | | | | 2,462 | | | | (1,996 | ) | | | 22,777 | | | | 3,166 | | | | (13,526 | ) | | | (1,228 | ) |
| Customer Advances | | | — | | | | — | | | | — | | | | 4,946 | | | | 534 | | | | (6,554 | ) | | | 635 | |
| Other Accruals and Current Liabilities | | | 9,343 | | | | 2,082 | | | | 16,085 | | | | (17,754 | ) | | | (756 | ) | | | 8,950 | | | | 25,400 | |
| Other Assets | | | (9,343 | ) | | | (2,525 | ) | | | (13,461 | ) | | | (22,700 | ) | | | 1,883 | | | | 4,109 | | | | 10,163 | |
| Other Liabilities | | | (23,124 | ) | | | (34,450 | ) | | | (3,667 | ) | | | 80,960 | | | | (6,810 | ) | | | (5,922 | ) | | | 1,889 | |
| | | |
| Net Cash Provided by Operating Activities | | $ | 325,728 | | | $ | 437,149 | | | $ | 317,346 | | | $ | 471,400 | | | $ | 43,031 | | | $ | 394,197 | | | $ | 75,345 | |
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