| Fiscal Year 2009 ReviewNovember 2009 Exhibit 99 |
| Safe Harbor For Forward Looking Statements This presentation may contain "forward-looking statements" as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects, plans, performance and capital structure, anticipated capital expenditures and completion of construction projects, as well as statements that are identified by the use of the words "anticipates," "estimates," "expects," "forecasts," "intends," "plans," "predicts," "projects," "believes," "seeks," "will," "may," and similar expressions. 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 results referred to in the forward-looking statements: financial and economic conditions, including the availability of credit, and their effect on the Company's ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments; occurrences affecting the Company's ability to obtain financing under credit lines or other credit facilities or through the issuance of commercial paper, other short-term notes or debt or equity securities, including any downgrades in the Company's credit ratings and changes in interest rates and other capital market conditions; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers' ability to pay for, the Company's products and services; the creditworthiness or performance of the Company's key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from terrorist activities, acts of war, major accidents, fires, hurricanes, other severe weather, pest infestation or other natural disasters; changes in actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company's pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; changes in demographic patterns and weather conditions; 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 SEC's full cost ceiling test for natural gas and oil reserves; uncertainty of oil and gas reserve estimates; factors affecting the Company's ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, and the need to obtain governmental approvals and permits and comply with environmental laws and regulations; significant differences between the Company's projected and actual production levels for natural gas or oil; changes in the availability and/or price of derivative financial instruments; changes in the price differentials between oil having different quality and/or different geographic locations, or changes in the price differentials between natural gas having different heating values and/or different geographic locations; inability to obtain new customers or retain existing ones; significant changes in competitive factors affecting the Company; changes in laws and regulations to which the Company is subject, including tax, environmental, safety and employment laws and regulations; 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 natural gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; unanticipated impacts of restructuring initiatives in the natural gas and electric industries; significant differences between the Company's projected and actual capital expenditures and operating expenses, and unanticipated project delays or changes in project costs or plans; the nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; 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 or activist shareholder campaigns to effect changes at the Company; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or increasing costs of insurance, changes in coverage and the ability to obtain insurance.For a discussion of these risks and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see "Risk Factors" in the Company's Form 10-K for the fiscal year ended September 30, 2008 and the Company's Forms 10-Q for the quarters ended December 31, 2008, March 31, 2009 and June 30, 2009. 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. The Securities and Exchange Commission (the "SEC") currently permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The Company uses the terms "probable," "possible," "resource potential" and other descriptions of volumes of reserves or resources potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines would prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and, accordingly, are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K and Forms 10-Q, available at www.nationalfuelgas.com. You can also obtain these forms on the SEC's website at www.sec.gov. |
| National Fuel Gas Company Business Segment Reporting Publicly Traded Holding CompanyNYSE symbol - NFG Reporting Segments Corporate Subsidiaries |
| Our Businesses UtilityPipeline & StorageExploration & ProductionAppalachia, California, Gulf of MexicoEnergy MarketingMidstreamTimberLandfill GasGas-Fired Generation National Fuel Gas Company |
| Net Plant by Segment (CHART) National Fuel Gas Company 33% 27% 37% 35% 25% 36% |
| National Fuel Gas Company Capital Expenditures(1) by Segment(CHART) Capital Expenditures exclude all expenditures associated with Discontinued Operations. Fiscal Year 2010 and 2011 estimates are as of November 5, 2009.2009 Excludes $16.8 MM of Capital Expenditures related to the Empire Connector Project, accrued in fiscal 2008 and paid in fiscal 2009.2009 Includes $9.1 MM of Accrued Capital Expenditures, the majority of which were in the Appalachian region. (2) 60 58 (3) |
| (CHART) National Fuel Gas Company An Appalachian Focus Defined as spending related to efforts to drill for, gather, or transport Appalachian sources of natural gas.Any other maintenance spending in the Appalachian region, plus spending in areas outside of the Appalachian region.2010E and 2011E percentage based on midpoint. (1) (2) 9.2% 14.1% 16.5% 44.4% 69.0% 78.7% Percentage of CapEx Devoted to Appalachian Natural Gas (3) $402-450 $689-749 |
| Net Income from Continuing Operations Excluding Items Impacting Comparability (1) National Fuel Gas Company A reconciliation to GAAP Net Income is included at the end of this presentation. (CHART) 46.5% 22.5% 27.9% |
| National Fuel Gas Company Independent Directors - A Wealth of Industry Experience Former Director, President & CEO of Northwest Natural Gas Co.Former Director of Northwest Natural Gas Co.Vice Chairman of DTE EnergyDirector of Northern Border Pipeline Co.Former Chairman and CEO of Questar CorporationFormer Vice Chairman, COO and Director of Keyspan CorporationIndividual Responsible for DTE's Barnett & Antrim Shale PlaysFormer Advisor to the COO of Duke EnergyFormer Vice Chairman of PanEnergy Corporation (now part of Spectra)Founder of Kidder Exploration, an Appalachian E&P Co.Director of Hess CorporationFormer Chairman & COO of MCN EnergyFormer CEO of Michigan Consolidated Gas Co.Former President, CEO & Director of NUI CorporationFormer Director of the Independent Oil & Gas Assoc. of NY & PACEO and Chairman of Moog Inc. for 20+ Years (Major Company in NFG's Service Territory)Former Vice-Chairman and CFO of Verizon Inc., a Regulated IndustryDirector of CMS Energy CorporationDirector of Dynegy, Inc. |
| Utility Segment National Fuel Gas Distribution Corporation |
| 11 |
| Operate Safe System Provide Excellent Customer Service Control Costs Provide Stable Earnings Utility |
| (CHART) Utility O&M Expense |
| (CHART) Capital Spending Utility |
| Utility (1) Excludes out-of-period adjustment to symmetrical sharing of $0.03. Diluted Earnings per Share(Before Items Impacting Comparability) (CHART) |
| Utility Rate Mechanisms Low Income Rates Conservation Incentive Program Revenue Decoupling 90/10 Sharing (Revenue Decoupling for Industrial Load) Merchant Function Charge Weather Normalization |
| (1) Calculated using Average Total Comprehensive Shareholder Equity. (CHART) Utility Return on Equity (1) |
| Utility Challenges |
| Utility Average Use per Residential Customer (CHART) Fiscal Year TME |
| Accounts Receivable - Customer (CHART) Utility |
| Utility HEAP/LIHEAP (CHART) |
| Exploration & Production Seneca Resources Corporation |
| Exploration & Production Marcellus ShaleAccelerate development; convert resource potential to reserves Appalachian Upper Devonian RegionDrill 150-200 wells per year Proved Reserves CaliforniaContinue to operate as a low-cost producer Gulf of MexicoDevelop and produce existing reserves 721 Bcfe 4 - 8 Tcfe 35 Bcfe 342 Bcfe Probable Reserves, Possible Reserves, and Resource Potential 130 Bcfe 21 Bcfe 272 Bcfe 21 Bcfe |
| Exploration & Production Proved Reserves (CHART) Proved Reserves @9/30 491 Bcfe 503 Bcfe 528 Bcfe West - CaliforniaReserves: 342 Bcfe (64%) (57 Mmboe)FY '09 Production: 20.1 Bcfe (47%) Gulf of MexicoReserves: 35 Bcfe (7%)FY '09 Production: 13.7 Bcfe (32%) East - AppalachiaReserves: 151 Bcfe (29%)FY '09 Production: 8.7 Bcfe (21%) 58% 55% 53% |
| Exploration & Production Capital Expenditures (CHART) Does not include the $34.9MM acquisition of Ivanhoe's US-based assets in California, as this will be accounted for as an investment in Subsidiaries on the Statement of Cash Flows, and will not be included in Capital Expenditures. |
| Exploration & Production Annual Production by Region (CHART) |
| Exploration & Production California |
| Seneca's California Properties South Lost Hills2036 BOEPDMonterey ShalePrimary221 Active Wells Sespe1084 BOEPDSespe FormationPrimary192 Active Wells North Lost Hills1171 BOEPDTulare & Etchegoin FormationPrimary & Steamflood202 Active Wells North Midway Sunset4551 BOEPDPotter & Tulare FormationSteamflood694 Active Wells South Midway Sunset563 BOEPDAntelope FormationSteamflood59 Active Wells 28 |
| California Average Daily Production 2009 Average Daily Production Up ~ 550 BOEPD vs. 2008Production Increases:Monterey shale drilling @ Lost HillsMarvic drilling @ MWSSSespe property exchangeImproved steaming efficiencyIvanhoe Acquisition (CHART) Ivanhoe Acquisition BOE/day |
| Acquisition of Ivanhoe Energy US-based Operations US oil and gas assets acquired in July 2009Total acquisition cost of $34.9 MM after closing adjustments for 2.2 MMBbl of reserves ($15.86/Bbl proved)Current Production ? 645 gross boepd in California & TexasIncrease production through steaming techniques currently used on Seneca's propertiesAdditional 8-10 MMBbl of risked potential resource California |
| Lifting Cost - Peer Comparison (CHART) Seneca is a low-cost operator in California, with Lifting Costs consistently outperforming peers Source: IHS Herold, Inc. and Seneca Financial Reports California $/BOE |
| Gulf of Mexico Exploration & Production |
| Gulf of Mexico Average Daily Production 3rd Quarter Production highest since 20054th Quarter curtailments on non- operated properties due to pricingProduction Increase from 2007- 2008 discoveriesMinimal Capital spending in 2009 and 2010(CHART) |
| Upper Devonian Exploration & Production |
| Appalachian Basin Upper Devonian - Development Drilling (CHART) |
| Quarterly Production Growth Seneca East (CHART) Since 2006, Seneca Eastproduction has grown at a 12% CAGR |
| Marcellus Shale Exploration & Production |
| Marcellus Shale Company Net Acres Shares Outstanding (MM) Acres/1K Shares Seneca Resources 720,000 79.5 9.05 Atlas Energy Resources LLC 546,000 63.4 8.61 Range Resources 900,000 157.3 5.72 EQT Corporation 400,000 130.9 3.06 Chesapeake Energy 1,300,000 626.2 2.08 EXCO Resources Inc. 360,000 211.1 1.71 Anadarko Petroleum Corp. * 600,000 499.2 1.20 Dominion Resources ** 585,000 590.0 0.99 EOG Resources Inc. 240,000 250.3 0.96 Talisman Energy 793,000 1,018.9 0.78 XTO Energy Inc. 280,000 579.7 0.48 Seneca is 4th Largest Marcellus Acreage Holder Taken from Wells Fargo research report, dated July 14, 2009; top 11 acreage holders sorted by acres/1,000 shares outstanding. * Gross Acreage Estimate, ** Midpoint of estimate The most Marcellus acreage per share outstanding (1) |
| Marcellus Shale Seneca Acreage Position Cabot SRC Fee/Lease Range Resources Chesapeake EOG/Seneca Seneca |
| SRC Fee/LeaseEOG Marcellus Shale EOG Joint Venture Approx. Outline of JV Acreage200,000 Gross AcresSeneca 50% W.I. (Avg. 58% NRI)EOG 50% W.I. (40% NRI) EOG Acreage Contributed~120,000 Gross AcresSeneca 50% W.I. (40% NRI) Calendar Year Wells per Year (1) 2009 10 2010 20 2011 30 2012 40 2013 50 2014 60 Minimum Drilling Requirement |
| Marcellus Shale Seneca-operated Vertical Drilling Program Fiscal 2009 Marcellus Vertical ProgramDrilled 11 Wells; cored 7 SRC Fee/LeaseEOG |
| Increasing Gas In Place ? Additional Factors: Reservoir Pressure Natural Fractures Silica Content (Brittleness) Marcellus Shale Core and Log Data from Vertical Wells |
| SRC Fee/LeaseEOG Seneca Horizontal Development Drilling Program 1st Seneca Rig arrived July 2009 2nd Seneca horizontal rig to arrive November '09 EOG JV (CHART) Marcellus Shale |
| SRC Fee/LeaseEOG Marcellus Shale Horizontal Drilling Results EOG Operated8 Horizontals Drilled4 Frac'dTypical IP: 3.0 MMCFD Seneca Operated4 Horizontals Drilled2 Frac'dTypical IP: 5.5 MMCFD EOG Operated4 Horizontals Drilled4 Frac'dTypical IP: 3.0 MMCFD EOG Operated2 Horizontals Drilled2 Frac'dTypical IP: 1.5 MMCFD Total18 Horizontals Drilled12 Frac'd and completed |
| Fiscal 2010 Marcellus Shale Drilling Plan Develop JV focus area (EOG Operated)25-35 wellsSeptember 2010 net production 15-25 MmcfdDevelop Tioga focus area (Seneca Operated)15-20 wellsSeptember 2010 net production 15-25 MmcfdDe-risk and prioritize additional areas:15-20 wells (includes some verticals)Minimal production in Fiscal Year 20102-3 new focus areas by Sept '10 Marcellus Shale |
| Wells Drilled per Year (CHART) Marcellus Shale |
| Marcellus Shale Decline Curve - 3.0 BCF Estimated Ultimate Recovery (EUR) (CHART) Category Type Curve Parameters Initial Rate 3,550 MCF/D Average first year decline 68% Final decline 6% Hyperbolic Coefficient 1.6 Abandonment rate 10 MCF/D Average first month rate 3,090 MCF/D Average first year rate 1,580 MCF/D EUR 3.0 BCF |
| Marcellus Shale Pre-tax IRR: 3.0 BCF EUR; $4.0 MM Well Cost (CHART) JV Wells on Seneca Mineral Fee 100% Wells on Seneca Fee Typical 15% Royalty Rate |
| Seneca Full-Cycle Economics Superior to Most Competitors Minimal Acreage CostMostly Fee (Seneca owns minerals)Average cost < $100/acreLow RoyaltyMostly Fee (0% royalty)Acres contributed to EOG JV have 50% WI/ 58% NRIRode the Learning Curve at minimal costEarly EOG JV wells at no cost to SenecaExperienced PA Operator - Top Notch TeamLong history of PA operationsFirst Horizontal drilled in 17 daysFirst well 6-day IP: 5.8 MMCFD Marcellus Shale |
| Marcellus Shale Resource Potential Net resource potential of 4 to 8 trillion cubic feet Assumptions:Average EUR of 2 to 3 Bcfe/wellAverage Risk Factor of 30% to 40%Anticipated well costs of $3.5 to $4.0 MM per horizontal in a development program100 acre well spacing |
| Seneca Resources Summary Redeploy excess cash flow from CaliforniaMaintain productionLow-cost leadershipProduce-out Gulf of MexicoMinimal CapexExpect fairly robust production in fiscal 2010Focus on the Marcellus7-day IPs averaging 5.3 MMCFD on Seneca operated wellsPlan 40-60 horizontal wells in Fiscal 2010$180-200 Million (70% of Fiscal 2010 E&P Capex)Expect net 20-30 30-50 MMCFD by September 2010Expect net 30-50 60-100 MMCFD by September 2011 |
| National Fuel Gas Supply CorporationEmpire Pipeline, Inc. Pipeline & Storage |
| (CHART) Pipeline & Storage Diluted Earnings per Share(Before Items Impacting Comparability) Excludes base gas sale of $0.03 and gain associated with insurance proceeds of $0.05Excludes reversal of reserve for preliminary project costs of $0.06, and discontinuance of Hedge Accounting for interest rate collar of $0.02 |
| WEST TO EAST PHASE 1 &PHASE 2 APPALACHIANLATERAL LAMONTCOMPRESSORSTATION COVINGTONGATHERINGSYSTEM TIOGACOUNTYEXTENSION LINE "N"EXPANSION TUSCARORA STORAGE GALBRAITH STORAGE EAST BRANCH STORAGE PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES 54 WEST TO EAST EXPANSION HORIZONTAL DRILLING ACTIVITY VERTICAL DRILLING ACTIVITY |
| 55 Appalachian Lateral / West to East Expansion - Key Statistics Appalachian Lateral / West to East Expansion - Key Statistics Planned Capacity & Compression 860 Mmcf/d40,000 HP Anticipated In-Service Date PHASED Estimated CAPEX Investment $750 MM - $1 B ~340 Miles of Pipe to Connect the Rockies Express to Millennium ~340 Miles of Pipe to Connect the Rockies Express to Millennium |
| West to East Expansion Phase I - Key Statistics West to East Expansion Phase I - Key Statistics Planned Capacity 200,000 dth/d Anticipated In-Service Date November 2011 Estimated CAPEX Investment $108 MM Open Season Closed 10/8/2009Negotiating Precedent Agreements Open Season Closed 10/8/2009Negotiating Precedent Agreements 56 |
| West to East Expansion Phase II - Key Statistics West to East Expansion Phase II - Key Statistics Planned Capacity (Compression Confidential) 300,000 dth/d Anticipated In-Service Date November 2012 Estimated CAPEX Investment $149 MM Open Season Closed 10/8/2009Negotiating Precedent Agreements Open Season Closed 10/8/2009Negotiating Precedent Agreements 57 |
| Lamont Compressor Station - Key Statistics Lamont Compressor Station - Key Statistics Planned Capacity & Compression 40,000 dth/d1,200 HP Anticipated In-Service Date May 2010 Estimated CAPEX Investment $6 MM Installation Under Blanket Certificate Authority Installation Under Blanket Certificate Authority 58 |
| Tioga County Extension - Key Statistics Tioga County Extension - Key Statistics Planned Capacity > 200,000 Dth/d Anticipated In-Service Date September 2011 Estimated CAPEX Investment $43 MM Open Season Closed 10/23/2009Negotiating Precedent Agreements Open Season Closed 10/23/2009Negotiating Precedent Agreements 59 |
| Line "N" Expansion - Key Statistics Line "N" Expansion - Key Statistics Planned Capacity & Compression 150,000 dth/d4,700 HP Anticipated In-Service Date Fall 2011 Estimated CAPEX Investment $23 MM Preparing FERC Application Preparing FERC Application WV PA 60 |
| Storage Expansion - Key Statistics Storage Expansion - Key Statistics Planned Capacity & Compression 8.5 Bcf13,615 HP Anticipated In-Service Date 2013 Estimated CAPEX Investment $78.4 MM 38 New Wells & 12.6 Miles of PipeRequires West to East Phase I & II 38 New Wells & 12.6 Miles of PipeRequires West to East Phase I & II 61 |
| Covington Gathering Phase I - Key Statistics Covington Gathering Phase I - Key Statistics Planned Capacity 100,000 dth/d Anticipated In-Service Date November 2009 Estimated CAPEX Investment ~ $16 MM Currently Marketing Capacity to Producers Currently Marketing Capacity to Producers 62 |
| National Fuel Gas Company Capitalization The Company may issue debt or equity securities in a public offering or a private placement from time to time, depending on market conditions, indenture requirements, regulatory authorizations and the Company's capital requirements.At the end of FY 2009, Total Capitalization was $2.838 Billion, of which $1.249 B was long-term debt and $1.589 B was Comprehensive Shareholder's Equity. (CHART) $2.84 Billion(2)at September 30, 2009 Long-Term Debt 44% Shareholder's Equity 56% Capital Resources(1)$300.0 MM Commercial Paper Program and Uncommitted Credit Facilities - Aggregate of $720.0 MM$300.0 MM Committed Credit Facility through September 2010 - backs Commercial Paper Program RATING AGENCY RATING FITCH A- MOODY'S Baa1 STANDARD & POOR'S BBB CURRENT CREDIT RATINGS |
| (CHART) National Fuel Gas Company Capitalization |
| National Fuel Gas Company 2010 EPS Guidance & Sensitivity Fiscal 2010Preliminary Earnings per Share (Diluted) Guidance(1)Consolidated Earnings $2.30 - $2.65(2)Earnings per Share Sensitivity to Changes from $5.00/ MMBtu for natural gas and $75.00/Bbl for crude oil(1)$1 change per $5 change per MMBtu Gas Bbl Oil Increase Decrease Increase Decrease +$0.06 -$0.06 +$0.07 -$0.07 Range NFG & Subsidiaries The earnings guidance and sensitivity table are current as of November 5, 2009. The sensitivity table only considers revenue from the Exploration and Production segment's crude oil and natural gas sales. The sensitivities will become obsolete with the passage of time, changes in Seneca's production forecast, changes in basis differentials, as additional hedging contracts are entered into, and with the settling of NYMEX hedge contracts at their maturity. For its fiscal 2010 earnings forecast, the Company is using flat commodity pricing of $5.00 per MMBtu for natural gas and $75.00 per Bbl for crude oil, and adjusting for basis differential. As of November 5, 2009, for its fiscal 2010 earnings guidance, the Company is utilizing flat commodity pricing of $5.00 per MMBtu for natural gas and $75.00 per Bbl for crude oil, and adjusting for basis differential Seneca Resources Production Guidance:42 to 50 Bcfe |
| (CHART) (CHART) National Fuel Gas Company Share Price Appreciation 13% Return Including Dividend Reinvestment 13% Annualized Return Including Dividend Reinvestment |
| National Fuel Gas Company Dividend Growth (CHART) $1.34 $0.19 Compound Annual Growth Rate5.2% National Fuel has had 107 uninterrupted years of dividend payments and has increased its dividend for 39 consecutive years |
| National Fuel Gas Company 1-Year Return Comparison (1)(2) (1) Diversified Peers: D, EGN, EP, EQT, GAS, MDU, OKE, SE, STR, SUG, UGI, and WMB; Utility Co.'s: AGL, ATO, CNP, CPK, NI, NJR, NWN, PNY, SWX, and WGL; E&P Co.'s: ATLS, BBEP, CHK, CNX, COG, DVN, EOG, PXP, REXX, RRC, VQ, XCO, and XTO (companies excluded without full 1-year history).(2) All returns for the period ending September 2009 are adjusted for dividend payments. (CHART) Peer Group 1-Yr Return NFG 13% E&P Companies 0% Utility Companies -6% Diversified Peers -11% One-Year ReturnNational Fuel's Diversified model has been successful during the last fiscal year, outperforming the return of peers in our business segments 1-Year Total Return from 9/30/08 - 9/30/09 SEP 2008 DEC 2008 MAR 2009 JUN 2009 SEP 2009 |
| National Fuel Gas Company 3-Year Return Comparison (1)(2) (1) Diversified Peers: D, EGN, EP, EQT, GAS, MDU, OKE, SE, STR, SUG, UGI, and WMB; Utility Co.'s: AGL, ATO, CNP, CPK, NI, NJR, NWN, PNY, SWX, and WGL; E&P Co.'s: ATLS, BBEP, CHK, CNX, COG, DVN, EOG, PXP, REXX, RRC, VQ, XCO, and XTO (companies excluded without full 3-year history).(2) All returns for the period ending September 2009 are adjusted for dividend payments. (CHART) Peer Group 3-Yr Return NFG 38% E&P Companies 7% Diversified Peers 3% Utility Companies -2% Three-Year ReturnNational Fuel's Diversified model has been successful in all economic cycles, consistently outperforming the return of peers in our business segments over this period 3-Year Total Return from 9/30/06 - 9/30/09 SEP SEP SEP SEP |
| National Fuel Gas Company 5-Year Return Comparison (1)(2) (CHART) Peer Group 5-Yr Return NFG 91% E&P Companies 83% Diversified Peers 45% Utility Companies 37% Five-Year ReturnNational Fuel's Diversified model has been successful in all economic cycles, consistently outperforming the return of peers in our business segments over this period 5-Year Total Return from 9/30/04 - 9/30/09 (1) Diversified Peers: D, EGN, EP, EQT, GAS, MDU, OKE, SE, STR, SUG, UGI, and WMB; Utility Co.'s: AGL, ATO, CNP, CPK, NI, NJR, NWN, PNY, SWX, and WGL; E&P Co.'s: ATLS, BBEP, CHK, CNX, COG, DVN, EOG, PXP, REXX, RRC, VQ, XCO, and XTO (companies excluded without full 5-year history).(2) All returns for the period ending September 2009 are adjusted for dividend payments. SEP SEP SEP SEP SEP SEP |
| Diversified Business Model Stock Performance National Fuel Gas Company AS OF SEPTEMBER 30, 2009(Adjusted for Dividends & Splits) 1-YEAR RETURN 3-YEAR RETURN 5-YEAR RETURN NATIONAL FUEL GAS COMPANY 12.8% 38.2% 90.9% E&P PEER GROUP (1) -11.0% 3.0% 82.7% DIVERSIFIED PEER GROUP (2) -5.9% -1.6% 45.0% UTILITY PEER GROUP (3) 0.1% 7.0% 37.1% In a decreasing natural gas price scenario, our Utility provides downside protection in comparison to our E&P peers In an increasing natural gas and oil price scenario, our E&P business helps us outperform our utility peers Our unique structure has helped shareholder returns outperform in the long-run Peer group consists of ATLS, BBEP, CHK, CNX, COG, DVN, EOG, PXP, REXX, RRC, VQ, XCO, and XTO.Peer group consists of D, EGN, EP, EQT, GAS, MDU, OKE, SE, STR, SUG, UGI, and WMB.Peer group consists of AGL, ATO, CNP, CPK, NI, NJR, NWN, PNY, SWX, and WGL. |
| Ranked the 4th best energy company in 2009 Report Based on the 4-year averages of:Profit MarginDividend YieldFCF, ROE, ROASustainable GrowthConsistently in the Top 10 best energy companies (2006-2009 Reports)"National Fuel Gas ... strongly positioned in gas markets from the well to the burner tip." Public Utilities Fortnightly National Fuel Gas Company |
| Questions |
| Appendix |
| Corporate Overview Key Information & Statistics Key Information & Statistics New York Stock Exchange NFG Fiscal Year End September Shares Outstanding (Approx.)(As of 9/30/09) 80.5 Million Average Daily Trading Volume(12 Months Ended 9/30/09) 551,327 Market Capitalization (Approx.)(As of 9/30/09) $3.69 Billion Annual Dividend Rate (Effective 06/30/09) $1.34 National Fuel Gas Company |
| National Fuel Gas Company Net Plant by Segment (CHART) FY 2010E$3.4 B |
| National Fuel Gas Company Debt Maturity Schedule (CHART) ($ Millions) Fiscal Year Total Long-Term Debt Outstanding At September 30, 2009: $1.249 B |
| Pipeline & Storage Pipeline Overview Key Statistics Key Statistics Transportation Volume (2009) 360.8 Bcf Pipeline Revenue (2009) $142.2 MM Total Compressor Stations 16 Total Horsepower 60,399 HP |
| Pipeline & Storage Storage Overview Key Statistics Key Statistics Underground Nat. Gas Storage Fields 31(1) Total Compressor Stations 14 Total Horsepower 35,550 HP Working Storage Capacity 78.3 Bcf Storage Revenue (2009) $66.7 MM (1) Includes 4 storage fields co-owned with non-affiliated companies. |
| Utility Segment Overview Key Statistics Key Statistics Average Number of Customers 727,325 Total Utility Volumes (2009) 129,165 MMcf Utility Revenue (2009) $1,113 MM Diluted EPS (2009) $0.73 Average Annual Residential Bill (2009) $1,440 |
| (CHART) (1) Excludes resolution of a purchased gas contingency of $0.03. Diluted Earnings per Share(Before Items Impacting Comparability) Energy Marketing |
Reconciliation of Income from Continuing Operations by Segment
to Consolidated GAAP Net Income
($000s)
to Consolidated GAAP Net Income
($000s)
| FY05 | FY06 | FY07 | FY08 | FY09 | ||||||||||||||||
| GAAP Net Income | ||||||||||||||||||||
| Utility Segment GAAP Net Income | $ | 39,197 | $ | 49,815 | $ | 50,886 | $ | 61,472 | $ | 58,664 | ||||||||||
| P&S Segment GAAP Net Income | 60,454 | 55,633 | 56,386 | 54,148 | 47,358 | |||||||||||||||
| E&P Segment GAAP Net Income | 50,659 | 20,971 | 210,669 | 146,612 | (10,238 | ) | ||||||||||||||
| Marketing Segment GAAP Net Income | 5,077 | 5,798 | 7,663 | 5,889 | 7,166 | |||||||||||||||
| Corp & All Other GAAP Net Income | 34,101 | 5,874 | 11,851 | 607 | (2,242 | ) | ||||||||||||||
| Total GAAP Net Income | $ | 189,488 | $ | 138,091 | $ | 337,455 | $ | 268,728 | $ | 100,708 | ||||||||||
| Discontinued Operations | ||||||||||||||||||||
| Income (Loss) From Operations, Net of Tax | $ | 25,277 | $ | (46,523 | ) | $ | 15,479 | $ | — | $ | — | |||||||||
| Gain on Disposal, Net of Tax | 25,774 | — | 120,301 | — | — | |||||||||||||||
| Income (Loss) From Discontinued Operations, Net of Tax | $ | 51,051 | $ | (46,523 | ) | $ | 135,780 | $ | — | $ | — | |||||||||
| Income from Continuing Operations | ||||||||||||||||||||
| Utility Segment Income from Continuing Operation | $ | 39,197 | $ | 49,815 | $ | 50,886 | $ | 61,472 | $ | 58,664 | ||||||||||
| P&S Segment Income from Continuing Operation | 60,454 | 55,633 | 56,386 | 54,148 | 47,358 | |||||||||||||||
| E&P Segment Income from Continuing Operation | 35,581 | 67,494 | 74,889 | 146,612 | (10,238 | ) | ||||||||||||||
| Marketing Segment Income from Continuing Operation | 5,077 | 5,798 | 7,663 | 5,889 | 7,166 | |||||||||||||||
| Corp & All Other Income from Continuing Operation | (1,872 | ) | 5,874 | 11,851 | 607 | (2,242 | ) | |||||||||||||
| Total Income from Continuing Operations | $ | 138,437 | $ | 184,614 | $ | 201,675 | $ | 268,728 | $ | 100,708 | ||||||||||
| Items Impacting Comparability | ||||||||||||||||||||
| Out-of-period adjustment to symmetrical sharing (Utility) | $ | — | $ | (2,551 | ) | $ | — | $ | — | $ | — | |||||||||
| Income tax adjustments (E&P) | — | (6,122 | ) | — | — | — | ||||||||||||||
| Reversal of reserve for preliminary project costs (P&S) | — | — | (4,787 | ) | — | — | ||||||||||||||
| Resolution of a purchased gas contingency (Marketing) | — | — | (2,344 | ) | — | — | ||||||||||||||
| Discontinuance of hedge accounting (P&S) | — | — | (1,888 | ) | — | — | ||||||||||||||
| Gain on sale of turbine (Corp. & All Other) | — | — | — | (586 | ) | — | ||||||||||||||
| Gain on life insurance policies (Corp. & ALL Other) | — | — | — | — | (2,312 | ) | ||||||||||||||
| Impairment of investment in partnership (Corp & All Other) | — | — | — | — | 1,085 | |||||||||||||||
| Impairment of landfill gas assets (Corp & All Other) | — | — | — | — | 2,786 | |||||||||||||||
| Impairment of oil and gas properties (E&P) | — | — | — | — | 108,207 | |||||||||||||||
| Gain associated with insurance proceeds (P&S) | (3,885 | ) | — | — | — | — | ||||||||||||||
| Gain on sale of base gas (P&S) | (2,636 | ) | — | — | — | — | ||||||||||||||
| Total Items Impacting Comparability | $ | (6,521 | ) | $ | (8,673 | ) | $ | (9,019 | ) | $ | (586 | ) | $ | 109,766 | ||||||
| Income from Continuing Operations after Items Impacting Comparability | ||||||||||||||||||||
| Utility Segment Operating Income | $ | 39,197 | $ | 47,264 | $ | 50,886 | $ | 61,472 | $ | 58,664 | ||||||||||
| P&S Segment Operating Income | 53,933 | 55,633 | 49,711 | 54,148 | 47,358 | |||||||||||||||
| E&P Segment Operating Income | 35,581 | 61,372 | 74,889 | 146,612 | 97,969 | |||||||||||||||
| Marketing Segment Operating Income | 5,077 | 5,798 | 5,319 | 5,889 | 7,166 | |||||||||||||||
| Corp & All Operating Income | (1,872 | ) | 5,874 | 11,851 | 21 | (683 | ) | |||||||||||||
| Total Income from Continuing Operations after Items Impacting Comparability | $ | 131,916 | $ | 175,941 | $ | 192,656 | $ | 268,142 | $ | 210,474 | ||||||||||
Reconciliation of Net Property, Plant & Equipment by Segment to
Consolidated Net Plant
($Millions)
Consolidated Net Plant
($Millions)
| 2009 | ||||
| Exploration & Production | $ | 1,041.8 | ||
| Pipeline & Storage | 839.4 | |||
| Utility | 1,144.0 | |||
| Marketing | 0.1 | |||
| Corporate & All Other (1) | 106.7 | |||
| Total Net Plant | $ | 3,132.0 | ||
| (1) | Timber is included in Corporate & All Other |
Reconciliation of Segment Revenue to Consolidated Revenue
($Millions)
($Millions)
| 2009 | ||||
| Exploration & Production | $ | 382.8 | ||
| Pipeline & Storage | 219.3 | |||
| Utility | 1,113.0 | |||
| Marketing | 398.3 | |||
| All Other Segments and Eliminations | (55.5 | ) | ||
| Total Revenue | $ | 2,057.9 | ||
NATIONAL FUEL GAS COMPANY
AND SUBSIDIARIES
RECONCILIATION TO REPORTED EARNINGS
AND SUBSIDIARIES
RECONCILIATION TO REPORTED EARNINGS
| Fiscal Year | Fiscal Year | Fiscal Year | Fiscal Year | Fiscal Year | ||||||||||||||||
| Ended | Ended | Ended | Ended | Ended | ||||||||||||||||
| (Diluted Earnings Per Share) | September 30, 2005 | September 30, 2006 | September 30, 2007 | September 30, 2008 | September 30, 2009 | |||||||||||||||
Utility | — | — | — | |||||||||||||||||
| Reported earnings | $ | 0.46 | $ | 0.58 | $ | 0.60 | $ | 0.73 | $ | 0.73 | ||||||||||
| Out-of-period adjustment to symmetrical sharing | — | (0.03 | ) | — | — | — | ||||||||||||||
| Pension settlement loss | — | — | — | — | — | |||||||||||||||
| Earnings before items impacting comparability | 0.46 | 0.55 | 0.60 | 0.73 | 0.73 | |||||||||||||||
Pipeline and Storage | ||||||||||||||||||||
| Reported earnings | 0.71 | 0.65 | 0.66 | 0.64 | 0.59 | |||||||||||||||
| Reversal of reserve for preliminary project costs | — | — | (0.06 | ) | — | — | ||||||||||||||
| Discontinuance of hedge accounting | — | — | (0.02 | ) | — | — | ||||||||||||||
| Pension settlement loss | — | — | — | — | — | |||||||||||||||
| Gain associated with insurance proceeds | (0.05 | ) | — | — | — | — | ||||||||||||||
| Base gas sale | (0.03 | ) | — | — | — | — | ||||||||||||||
| Earnings before items impacting comparability | 0.63 | 0.65 | 0.58 | 0.64 | 0.59 | |||||||||||||||
Exploration and Production | ||||||||||||||||||||
| Reported earnings | 0.60 | 0.24 | 2.47 | 1.73 | (0.13 | ) | ||||||||||||||
| 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 | — | — | — | — | — | |||||||||||||||
| Impairment of oil and gas producing properties | — | 0.54 | — | — | 1.34 | |||||||||||||||
| Cumulative Effect of Change in Accounting | — | — | — | — | — | |||||||||||||||
| Adjustment of loss on sale of oil and gas assets | — | — | — | — | — | |||||||||||||||
| Pension settlement loss | — | — | — | — | — | |||||||||||||||
| Earnings before items impacting comparability | 0.60 | 0.71 | 0.88 | 1.73 | 1.21 | |||||||||||||||
International | ||||||||||||||||||||
| Reported earnings | ||||||||||||||||||||
| Cumulative Effect of Change in Accounting | see | |||||||||||||||||||
| Pension settlement loss | "Discontinued | |||||||||||||||||||
| Tax rate change | Operations" | |||||||||||||||||||
| Repatriation tax | below | |||||||||||||||||||
| Earnings before items impacting comparability | ||||||||||||||||||||
Energy Marketing | ||||||||||||||||||||
| Reported earnings | 0.06 | 0.07 | 0.09 | 0.07 | 0.09 | |||||||||||||||
| Resolution of a purchased gas contingency | — | — | (0.03 | ) | — | — | ||||||||||||||
| Pension settlement loss | — | — | — | — | — | |||||||||||||||
| Earnings before items impacting comparability | 0.06 | 0.07 | 0.06 | 0.07 | 0.09 | |||||||||||||||
Corporate and All Other | ||||||||||||||||||||
| Reported earnings | (0.02 | ) | 0.07 | 0.14 | 0.01 | (0.03 | ) | |||||||||||||
| Pension settlement loss | — | — | — | — | — | |||||||||||||||
| Adjustment of gain on sale of timber properties | — | — | — | — | — | |||||||||||||||
| Gain on sale of turbine | — | — | — | (0.01 | ) | — | ||||||||||||||
| Gain on life insurance policies | — | — | — | — | (0.03 | ) | ||||||||||||||
| Impairment of investment in partnership | — | — | — | — | 0.01 | |||||||||||||||
| Impairment of landfill gas assets | — | — | — | — | 0.03 | |||||||||||||||
| Earnings before items impacting comparability | (0.02 | ) | 0.07 | 0.14 | 0.01 | (0.02 | ) | |||||||||||||
Consolidated | ||||||||||||||||||||
| Reported earnings | ||||||||||||||||||||
| Total items impacting comparability from above | ||||||||||||||||||||
| Earnings before items impacting comparability | ||||||||||||||||||||
Consolidated Earnings from Continuing Operations | ||||||||||||||||||||
| Reported earnings from continuing operations | 1.81 | 1.61 | 3.96 | 3.18 | 1.25 | |||||||||||||||
| Total items impacting comparability from above | (0.08 | ) | 0.44 | (1.70 | ) | (0.01 | ) | 1.35 | ||||||||||||
| Earnings from continuing operations before items impacting comparability | $ | 1.73 | $ | 2.05 | $ | 2.26 | $ | 3.17 | $ | 2.60 | ||||||||||
Discontinued Operations | ||||||||||||||||||||
| Reported earnings from discontinued operations | 0.42 | |||||||||||||||||||
Consolidated | ||||||||||||||||||||
| Reported earnings | $ | 2.23 | $ | 1.61 | $ | 3.96 | $ | 3.18 | $ | 1.25 | ||||||||||
Reconciliation of Utility Segment Aged Accounts Receivable to
Consolidated Accounts Receivable — Net
($Millions)
Consolidated Accounts Receivable — Net
($Millions)
| at 09/30/05 | at 09/30/06 | at 09/30/07 | at 09/30/08 | at 09/30/09 | ||||||||||||||||
| Utility Aged Accounts Receivable | $ | 76.2 | $ | 91.4 | $ | 86.6 | $ | 102.4 | $ | 99.7 | ||||||||||
| Utility Current/Other Accounts Receivable | 16.5 | 10.1 | 42.7 | 43.8 | 29.9 | |||||||||||||||
| Utility Gross Accounts Receivable | $ | 92.7 | $ | 101.5 | $ | 129.3 | $ | 146.2 | $ | 129.6 | ||||||||||
| Utility Reserve for Bad Debt | (25.1 | ) | (29.7 | ) | (27.2 | ) | (30.5 | ) | (32.3 | ) | ||||||||||
| Utility Net Accounts Receivable | $ | 67.6 | $ | 71.8 | $ | 102.1 | $ | 115.7 | $ | 97.3 | ||||||||||
| All Other Segments Gross Accounts Receivable | $ | 75.6 | $ | 74.2 | $ | 71.8 | $ | 72.3 | $ | 53.2 | ||||||||||
| All Other Segments Reserve for Bad Debts | (1.8 | ) | (1.7 | ) | (1.5 | ) | (2.6 | ) | (6.0 | ) | ||||||||||
| All Other Segments Net Accounts Receivable | $ | 73.8 | $ | 72.5 | $ | 70.3 | $ | 69.7 | $ | 47.2 | ||||||||||
| Total Corporation Accounts Receivable — Net | $ | 141.4 | $ | 144.3 | $ | 172.4 | $ | 185.4 | $ | 144.5 | ||||||||||
Reconciliation of Pipeline & Storage Operating Revenues to
Consolidated Operating Revenues Fiscal 2009
($Millions)
Consolidated Operating Revenues Fiscal 2009
($Millions)
| Pipeline Revenues | $ | 142.2 | ||
| Storage Revenues | 66.7 | |||
| Other Revenues | 10.4 | |||
| Total Pipeline & Storage Revenues | $ | 219.3 | ||
| All Other Segments | 1,838.6 | |||
| Total Corporation | $ | 2,057.9 | ||
Reconciliation of Exploration & Production Segment Capital Expenditures to
Consolidated Capital Expenditures
($000s)
Consolidated Capital Expenditures
($000s)
| 2010 | 2011 | |||||||||||||||||||||||||||
| 2005 | 2006 | 2007 | 2008 | 2009 | Forecast | Forecast | ||||||||||||||||||||||
| Exploration & Production Capital Expenditures (Continuing Operations) | $ | 83,973 | $ | 166,535 | $ | 146,687 | $ | 192,187 | $ | 188,290 | $ | 245,000-293,000 | $ | 390,000-450,000 | ||||||||||||||
| Exploration & Production Capital Expenditures (Discontinued Operations) | 38,477 | 41,768 | 29,129 | — | — | — | ||||||||||||||||||||||
| Less Exploration & Production Accrued Capital Expenditures | — | — | — | — | (9,093 | ) | ||||||||||||||||||||||
| Pipeline & Storage Capital Expenditures | 21,099 | 26,023 | 43,226 | 165,520 | 50,118 | 51,000 | 220,000 | |||||||||||||||||||||
| Add (Subtract) Pipeline & Storage Accrued Capital Expenditures | — | — | — | (16,768 | ) | 16,768 | ||||||||||||||||||||||
| Utility Capital Expenditures | 50,071 | 54,414 | 54,185 | 57,457 | 56,178 | 60,000 | 58,000 | |||||||||||||||||||||
| Energy Marketing Capital Expenditures | — | — | — | 39 | 25 | — | ||||||||||||||||||||||
| Corporate, All Other Capital Expenditures (Continuing Operations) | 20,033 | 5,419 | 3,501 | 1,706 | 8,703 | 46,000 | 21,000 | |||||||||||||||||||||
| Corporate & All Other Capital Expenditures (Discontinued Operations) | 5,877 | — | — | — | — | — | ||||||||||||||||||||||
| Less All Other Accrued Capital Expenditures | — | — | — | (715 | ) | |||||||||||||||||||||||
| Eliminations | — | — | — | (2,407 | ) | (344 | ) | |||||||||||||||||||||
| Total Capital Expenditures Per Statement of Cash Flows | $ | 219,530 | $ | 294,159 | $ | 276,728 | $ | 397,734 | $ | 309,930 | $ | 402,000-450,000 | $ | 689,000-749,000 | ||||||||||||||
| Note: The capital expenditures amounts by segment include accrued capital expenditures that are subtracted out for statement of cash flow purposes in the year they are accrued. They are added back to the statement of cash flows in the following year when they are paid. | ||
Consolidated Net Income
($000s)
($000s)
| 2005 | 2006 | 2007 | 2008 | 2009 | ||||||||||||||||
| Exploration & Production (Income from Continuing Operations) | $ | 35,581 | $ | 67,494 | $ | 74,889 | $ | 146,612 | $ | (10,238 | ) | |||||||||
| Income from Discontinued Operations, Net of Tax | 25,277 | (46,523 | ) | 15,479 | — | — | ||||||||||||||
| Gain on Disposal of Discontinued Operations, Net of Tax | 25,774 | — | 120,301 | — | — | |||||||||||||||
| Total Exploration & Production | $ | 86,632 | $ | 20,971 | $ | 210,669 | $ | 146,612 | $ | (10,238 | ) | |||||||||
| All Other Segments | 102,856 | 117,120 | 126,786 | 122,116 | 110,946 | |||||||||||||||
| Consolidated Net Income | $ | 189,488 | $ | 138,091 | $ | 337,455 | $ | 268,728 | $ | 100,708 | ||||||||||