EXHIBIT 99
| Fiscal Year 2009, 1st Quarter Review March 2009 |
| 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; economic disruptions caused by terrorist activities, acts of war or major accidents; changes in actuarial assumptions, the interest rate environment and the return on assets for the Company's retirement plan and post-retirement benefit plans, which can affect future funding obligations and costs and plan liabilities; 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; uncertainty of oil and natural gas reserve estimates; ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including shortages, delays or unavailability of equipment and services required in drilling operations; significant changes from expectations in the Company's 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 various types of oil; 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 changes from expectations in 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; impairments under the SEC's full cost ceiling test for natural gas and oil reserves; 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 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-Q for the quarter ended December 31, 2008. 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. |
| National Fuel Gas Company Business Segment Reporting |
| National Fuel Gas Company Net Income from Continuing Operations(1) (CHART) (CHART) Energy Mkt. $5.5 MM 2.1% $261.8 Million (1) 12 Months Ended 12/31/08 Excludes non-cash impairment charge of $108.2 MM to write down the book value of oil and natural gas producing properties as a result of significantly lower commodity prices at December 31, 2008, $1.1 MM impairment of investment in partnership, $0.6 MM gain on the sale of a turbine, and $2.3 MM gain on life insurance policy. A reconciliation to GAAP Net Income is provided at the end of this presentation. Corp. & All Other ($2.8) MM |
| National Fuel Gas Company Net Plant by Segment (CHART) $3,044 Million At December 31, 2008 All Other $104 MM 4% |
| National Fuel Gas Company Expenditures for Long-Lived Assets(1) (1) Capital Expenditures exclude all Discontinued Operations (2) Amount for quarter and year ended September 30, 2008 includes $16.8 MM of accrued capital expenditures related to the Empire Connector project. This amount has been excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represents a non-cash investing activity at that date (CHART) |
| National Fuel Gas Company Capital Expenditures(1) by Segment Utility Pipeline & Storage Exploration & Production (1) Capital Expenditures exclude all expenditures associated with Discontinued Operations |
| National Fuel Gas Company Capitalization (CHART) Short-Term Debt 2% $2.76 Billion At December 31, 2008 Long-Term Debt (1) 40% Shareholder Equity 58% (1) Includes $100 MM current portion of long-term debt |
| National Fuel Gas Company Dividend Growth Compound Annual Growth Rate 5.2% $1.30 $0.19 |
| National Fuel Gas Company Public Utilities Fortnightly Ranked the 3rd best energy company in 2008 Based on the 3-year averages of: Profit Margin Dividend Yield FCF, ROE, ROA Sustainable Growth Consistently in the Top 10 best energy companies (2006-2008) "National Fuel Gas ... strongly positioned in gas markets from the well to the burner tip." |
| Exploration & Production Seneca Resources Corporation |
| Exploration & Production Seneca Resources |
| Exploration & Production Balanced Portfolio 57 MMBOE (339 Bcfe) - Proved Reserves 51.5 Mmcfe/d - Daily Production Balanced Portfolio East Region West Region Gulf of Mexico 131 Bcfe - Proved Reserves 234 Bcfe - 3P Reserves (Prvd + Prob + Poss) 670 Bcfe - Upper Devonian prospective resources 725,000 Acres - Prospective Marcellus Shale 21.6 Mmcfe/d - Daily Production Growth Cash Flow Opportunistic 33 Bcfe - Proved Reserves 38.5 Mmcfe/d - Daily Production 5 - Recent Discoveries |
| Exploration & Production Proved Reserves @9/30 491 Bcfe 503 Bcfe West - California Reserves: 339 Bcfe (67%) Prod: 52 Mmcfed (8,600 Boepd) (46%) Gulf of Mexico Reserves: 33 Bcfe (7%) Production: 38.5 Mmcfed (34%) East - Appalachia Reserves: 131 Bcfe (26%) Production: 22 Mmcfed (20%) |
| Exploration & Production Capital Expenditures Major shift in capital allocation from higher-risk exploration to lower-risk development will lead to improved Finding & Development costs East 2006 2007 2008 2009E 13% 22% 34% 78% West 2006 2007 2008 2009E 17% 24% 33% 14% Gulf of Mexico 2006 2007 2008 2009E 50% 38% 33% 8% Increased Focus Stable Spending Reduced Focus $208.3 $175.8 $192.2 $244 |
| Exploration & Production Annual Production by Division |
| Exploration & Production Appalachian Basin |
| Appalachian Basin Upper Devonian - Development Drilling |
| Appalachian Basin 19 Upper Devonian Drilling Program Detailed Geologic work has improved per well reserves and success rates Accelerating Reserve additions each year (excludes PUDs): 2005 - 5.8 Bcfe 2006 - 11.8 Bcfe 2007 - 20.8 Bcfe 2008 - 24.2 Bcfe |
| Marcellus Shale Recent Daily Production Rates Cabot 6.4 MMCFD All production figures from individual company disclosures Marcellus Outcrop Seneca Fee Acreage Seneca Lease Acreage EOG/Seneca Resources 1.4 MMCFD (25 days) Atlas Energy Multiple Verticals: 1-3 MMCFD Chesapeake 2 Well Avg.: 4.5 MMCFD Range Resources Multiple Wells: 1-5 MMCFD Marcellus Fairway |
| Marcellus Shale 3rd Largest Acreage Holder Company Acres Chesapeake 1,200,000 Range 900,000 Seneca 725,000 Atlas 580,000 ("under control") Equitable 400,000 Chief 350,000 XTO 280,000 Exco 276,000 EOG 220,000 All acreage positions taken from most recent individual company disclosures, available from company websites as of January 6, 2009 |
| Marcellus Shale EOG JV Drilling Update Well # IP Rate Details 1 350 Mcf/d Ineffective Frac Job 2 400 Mcf/d Short lateral - 1,500' 3 1,400 Mcf/d 3,500' lateral 4-6 TBD 3,800' - 5,700' laterals 7 TBD Drilling Horizontal Well Summary Drilling Summary(1) Well Type # of Wells Vertical 5 Horizontal 7 2009: Anticipated 10 Horizontal Wells (1) Excludes one junked" horizontal well |
| Marcellus Shale Seneca Resources-EOG Joint Venture Joint Venture Terms JV Agreement Originated November, 2006, 10 Year Term tied to a Continuous Drilling commitment. Total Acreage EOG can earn 50% WI in 200,000 Seneca acres.Seneca can earn 50% WI in ~120,000 EOG acres. Prospect Selection EOG prospect selection to be completed by March 2009 (Originally - December 2011). Drilling Requirements EOG must ramp up to 60 development wells per year by 2014. Beginning in March 2009, Seneca will have complete control of ~525,000 acres |
| Marcellus Shale Log and Core Evaluation Depth TVD: 5,000' - 8,000' Thickness 50' - 200' Total Organic Content (TOC) 2% - ^ 10% Thermal Maturity 1% - 3% Effective Porosity 3% - 12% Pressure (psi/foot) 0.43 - 0.65 Water Saturation 12% - 35% Gas-in-Place (Bcfe/Section) 30 - 150 Anticipated EUR/Horizontal Well (Bcfe) 1.0 - 3.0 |
| Marcellus Shale PA State (DCNR) Lease Sale - 9/3/08 Company Total Acreage Seneca Resources 23,988 ExxonMobil 19,439 Anadarko E&P 17,189 Fortuna Energy 9,339 Hunt Oil 4,068 Seneca was the high bidder on 4 of 6 tracts Total of the 4 high bids - $74 million 10-year lease terms Lycoming & Tioga Counties Marcellus Shale impact 150-200 potential horizontal well locations Acreage is relatively contiguous in the core area of the play where the shale is thick |
| Marcellus Shale Seneca Operations New DCNR Leases Adjusted EOG JV Terms Seneca as a major Marcellus Operator ~525,000 net acres to evaluate as operator Plan to drill 6-8 vertical "test" wells this fiscal year Begin horizontal program in July '09 Marcellus acreage prioritized by: Geology Lease Terms Permitting Issues Pipeline infrastructure May partner in some areas, remain 100% in others |
| Marcellus Summary Seneca is the third largest acreage holder in the Marcellus Shale play EOG Joint Venture Initial exploration at minimal cost Gained experience of an industry leader 2009 is a big year Development drilling on Joint Venture acreage Independent Seneca drilling operations commence |
| Exploration & Production California |
| California Lifting Cost - Peer Comparison Seneca is a low-cost operator in California, with Lifting Costs consistently outperforming its peers Source: HIS Herold, Inc. and Seneca Financial Reports |
| California 2008 Highlights Monterey Shale Drilling at Lost Hills Drilled 4 wells Added 300 Boepd Marvic Sand Development at MWSS Drilled 11 wells in 2008 3.3 Bcfe @ $1.58 F&D Cost Additional wells planned in 2009 Increased Production 500 Boepd |
| Exploration & Production Long-Term Outlook |
| Pipeline & Storage National Fuel Gas Supply Corporation Empire State Pipeline |
| Pipeline & Storage (1) Excludes SFAS 88 settlement loss of -$0.02 (2) Excludes base gas sale of $0.03 and gain associated with insurance proceeds of $0.05 (3) Excludes reversal of reserve for preliminary project costs of $0.06, and discontinuance of Hedge Accounting of $0.02 (CHART) Diluted Earnings per Share (Before Items Impacting Comparability) |
| 34 Empire Connector In-service as of December 2008 Storage Expansion Increase Storage Capacity by 8.5 Bcf West to East / Appalachian Lateral Proposed pipeline project Millennium Pipeline |
| Pipeline & Storage Empire Connector Key Highlights & Statistics Key Highlights & Statistics Design Capacity 250,000 Dth/day KeySpan Capacity 150,750 Dth/day In-Service Date December 2008 Length of 24" Pipe (1,440 psig) 77 Miles Total Compression 20,620 HP Capital Expenditures(As of 12/31/08) $181.7 Million Total Estimated Capital Cost $187 Million Upstream Receipts on Empire Pipeline with Deliveries to Millennium @ Corning, New York |
| Utility Segment National Fuel Gas Distribution Corporation |
| Utility (1) Excludes SFAS 88 settlement loss of -$0.03 (2) Excludes out-of-period adjustment to symmetrical sharing of $0.03 Diluted Earnings per Share (Before Items Impacting Comparability) (CHART) |
| 38 |
| Utility Average Use per Residential Customer |
| Utility Accounts Receivable - Customer Average Annual Residential Bill |
| Utility Keys to Continued Success Conservation Incentive Program |
| Appendix |
| National Fuel Gas Company Corporate Overview Key Information & Statistics Key Information & Statistics New York Stock Exchange NFG Fiscal Year End September Shares Outstanding (Approx.)(As of 12/31/08) 79.1 Million Average Daily Trading Volume(12 Months Ended 12/31/08) 712,355 Market Capitalization (Approx.)(As of 12/31/08) $2.48 Billion Annual Dividend Rate (Effective 06/30/08) $1.30 |
| National Fuel Gas Company 2009 EPS Guidance & Sensitivity Fiscal 2009 Earnings per Share (Diluted) Guidance(1) Consolidated Earnings $1.10 - $1.30(2) Earnings per Share Sensitivity to Changes from $5.50/ MMBtu for natural gas and $45/Bbl for crude oil(1) $1 change per $5 change per MMBtu Gas Bbl Oil Increase Decrease Increase Decrease +$0.07 -$0.07 +$0.05 -$0.05 Range NFG & Subsidiaries The earnings guidance and sensitivity table are current as of February 6, 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. Includes $1.35 impairment charge related to the write down in the book value of oil & natural gas producing properties as a result of significantly lower commodity prices at December 31, 2008. As of February 6, 2009, for its fiscal 2009 earnings guidance, the Company is utilizing flat commodity pricing, exclusive of basis differential, of $5.50 per MMBtu for natural gas and $45 per Bbl for crude oil Seneca Resources Production Guidance: 38 to 44 Bcfe |
| National Fuel Gas Company Net Plant by Segment $3.0 B |
| National Fuel Gas Company Capital Resources $300.0 MM Commercial Paper Program And Uncommitted Credit Facilities - Aggregate Of $720.0 MM $66 MM borrowed at December 31, 2008 $300.0 MM Committed Credit Facility Through September 2010 - backs commercial paper program $0 borrowed at December 31, 2008 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. |
| National Fuel Gas Company Debt Ratings - As of March 2, 2009 Standard & Poor's Moody's Fitch, Inc. Long-Term Debt BBB Baa1 A- Outlook Stable Stable Stable Commercial Paper A-2 P-2 F2 |
| Exploration & Production Fiscal 2008 Highlights |
| Appalachian Basin Continued Upper Devonian Success 2008 Shallow Drilling Program |
| Exploration & Production Gulf of Mexico |
| Gulf of Mexico Discoveries since April 1st, 2007 Recent Discovery HI 24L North Disc. (Q3 '07) Producing: 35 Mmcf/d WI: 35% HI 23L Prospect (Q2 '08) 60' Pay WI: 55% ; Paid 35% Producing: 14 Mmcf/d ; 1,800 BCPD WC 96 Disc. (Q4 '07) Producing: 9 Mmcf/d WI: 11% Cyclops (Q2 '08) 1st Well: 106' Pay 2nd Well: 200'+ Pay First Production: Q2 '09 WI: 29% EI383 (Q3 '08) 70' Pay ; WI: 30% First Production: Q3 '09 |
| Gulf of Mexico Fiscal 2008 Exploration Program 3 Discoveries, 1 Dry Hole 5 discoveries in 18 months since implementing new strategy Fiscal '08 Net 2P Reserves Added: 23.7 Bcfe (13.9 Proved) 2P Program F&D Cost: $2.61/Mcfe ($4.44 Proved) |
| Pipeline & Storage Pipeline Overview Key Statistics Key Statistics System Pipeline Mileage 2,877 Miles Transportation Volume (2008) 358.4 Bcf Pipeline Revenue (2008) $126.7 MM Total Compressor Stations 15 Total Horsepower 39,779 HP |
| Pipeline & Storage Storage Overview Key Statistics Key Statistics Underground Nat. Gas Storage Fields 31(1) Total Compressor Stations 15 Total Horsepower 35,475 HP Working Storage Capacity 78.3 Bcf Storage Revenue (2008) $67.0 MM (1) Includes 4 storage fields co-owned with non-affiliated companies |
| Pipeline & Storage Upcoming Projects West to East & Appalachian Lateral Project Pipeline Length: 324 Miles Starting Location: Rockies Express (REX) - Clarington, OH Ending Location: Millennium Pipeline - Corning, NY Receipts From: REX (~555,000 to 750,000 Dth/d) Local Production Cove Point Gas at Leidy and Corning Deliveries To: Millennium & Empire at Corning Project Status: Open Seasons Conducted May 2007/October 2008 Strong Initial Interest Storage Expansion Incremental Storage Capacity: Approximately 8.5 Bcf No additional base gas required Storage Fields: East Branch - Pennsylvania Galbraith - Pennsylvania Tuscarora - Central New York Project Status: Open Season Conducted October 2008 |
| Utility Segment Overview Key Statistics Key Statistics Average Number of Customers 726,863 Total Utility Volumes 135,271 MMcf Utility Revenue (2008) $1,121 MM Utility Pipeline Mileage (2008) 14,819 Miles Diluted EPS (2008) $0.73 Average Annual Residential Bill (2008) $1,479 |
| 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 28th, 2006 Pennsylvania Effective Date: 12/28/07 Awarded $1.8 MM base rate increase and $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 NY Revenue Stabilization Features: WNC, RDM, MFC, Symmetrical Sharing New York Case Concluded Case Concluded |
| Utility Rate Cases Pennsylvania New York Rate Case Result Rate Case Result Settled Adjudicated Approximate Rate Base Approximate Rate Base $280 - 290 MM(1) $699 MM Approximate Base Rate Revenue Increase Approximate Base Rate Revenue Increase $14.3 MM $1.8 MM Conservation Incentive Program Conservation Incentive Program N/A $10.8 MM Effective Date Effective Date 1/1/2007 12/28/2007 Approximate Utility Capital Structure(2): Approximate Utility Capital Structure(2): Long-Term Debt 45.0% 45.54% Cost Component 6.65% 6.57% Short-Term Debt 5.0% 9.32% Cost Component 5.0 - 6.0% 5.98% Equity Component 50.0% 44.35% Return on Equity 10.0 - 11.0% 9.10% (1) Represents the approximate range of rate base filed for in this case (2) Black-box settlement in Pennsylvania |
| Marketing (CHART) (1) Excludes resolution of a purchased gas contingency of +$0.03 Diluted Earnings per Share (Before Items Impacting Comparability) |
| National Fuel Gas Company Comparable GAAP Financial Measure Slides and Reconciliations 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. |
Reconciliation of Segment Net Income to
Consolidated Net Income
(‘000)
Consolidated Net Income
(‘000)
| 12 Mos Ended 12/31/08 | ||||||||||||
| Earning Before | ||||||||||||
| Items Impacting | Items Impacting | |||||||||||
| GAAP Earnings | Comparability | Comparability | ||||||||||
| Utility | $ | 63,344 | ||||||||||
| $ | 63,344 | |||||||||||
| Pipeline & Storage | $ | 58,546 | ||||||||||
| $ | 58,546 | |||||||||||
| Exploration & Production | $ | 29,033 | ||||||||||
| Less: Non-cash impairment charge | $ | 108,207 | ||||||||||
| $ | 137,240 | |||||||||||
| Energy Marketing | $ | 5,533 | ||||||||||
| $ | 5,533 | |||||||||||
| Corporate & Other | $ | (1,010 | ) | |||||||||
| Less: Impairment of Investment in Partnership | $ | 1,085 | ||||||||||
| Plus: Gain on life insurance proceeds | $ | (2,312 | ) | |||||||||
| Plus: Gain on sale of turbine | $ | (586 | ) | |||||||||
| $ | (2,823 | ) | ||||||||||
| GAAP Consolidated Net Income | $ | 155,446 | ||||||||||
| Total Items Impacting Comparability | $ | 106,394 | ||||||||||
| Net Income Before Items Impacting Comparability | $ | 261,840 | ||||||||||
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 | Three Months | |||||||||||||||||||
| Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||
| (Diluted Earnings Per Share) | September 30, 2004 | September 30, 2005 | September 30, 2006 | September 30, 2007 | September 30, 2008 | December 31, 2008 | ||||||||||||||||||
Utility | ||||||||||||||||||||||||
| Reported earnings | $ | 0.56 | $ | 0.46 | $ | 0.58 | $ | 0.60 | $ | 0.73 | $ | 0.28 | ||||||||||||
| Out-of-period adjustment to symmetical sharing | — | — | (0.03 | ) | — | — | — | |||||||||||||||||
| Pension settlement loss | 0.03 | — | — | — | — | — | ||||||||||||||||||
| Earnings before items impacting comparability | 0.59 | 0.46 | 0.55 | 0.60 | 0.73 | 0.28 | ||||||||||||||||||
Pipeline and Storage | ||||||||||||||||||||||||
| Reported earnings | 0.58 | 0.71 | 0.65 | 0.66 | 0.64 | 0.21 | ||||||||||||||||||
| 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 items impacting comparability | 0.60 | 0.63 | 0.65 | 0.58 | 0.64 | 0.21 | ||||||||||||||||||
Exploration and Production | ||||||||||||||||||||||||
| Reported earnings | 0.66 | 0.60 | 0.24 | 2.47 | 1.73 | (1.04 | ) | |||||||||||||||||
| 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 | — | — | 1.35 | ||||||||||||||||||
| Cumulative Effect of Change in Accounting | — | — | — | — | — | — | ||||||||||||||||||
| Adjustment of loss on sale of oil and gas assets | (0.06 | ) | — | — | — | — | — | |||||||||||||||||
| Pension settlement loss | 0.01 | — | — | — | — | — | ||||||||||||||||||
| Earnings before items impacting comparability | 0.61 | 0.60 | 0.71 | 0.88 | 1.73 | 0.31 | ||||||||||||||||||
International | ||||||||||||||||||||||||
| Reported earnings | 0.07 | |||||||||||||||||||||||
| Cumulative Effect of Change in Accounting | — | see | ||||||||||||||||||||||
| Pension settlement loss | — | “Discontinued | ||||||||||||||||||||||
| Tax rate change | (0.06 | ) | Operations” | |||||||||||||||||||||
| Repatriation tax | below | |||||||||||||||||||||||
| Earnings before items impacting comparability | 0.01 | |||||||||||||||||||||||
Energy Marketing | ||||||||||||||||||||||||
| Reported earnings | 0.07 | 0.06 | 0.07 | 0.09 | 0.07 | 0.01 | ||||||||||||||||||
| Resolution of a purchased gas contingency | — | — | — | (0.03 | ) | — | — | |||||||||||||||||
| Pension settlement loss | — | — | — | — | — | — | ||||||||||||||||||
| Earnings before items impacting comparability | 0.07 | 0.06 | 0.07 | 0.06 | 0.07 | 0.01 | ||||||||||||||||||
Corporate and All Other | ||||||||||||||||||||||||
| Reported earnings | 0.07 | (0.02 | ) | 0.07 | 0.14 | 0.01 | 0.01 | |||||||||||||||||
| Pension settlement loss | 0.02 | — | — | — | — | — | ||||||||||||||||||
| Adjustment of gain on sale of timber properties | 0.01 | |||||||||||||||||||||||
| Gain on sale of turbine | (0.01 | ) | — | |||||||||||||||||||||
| Gain on life insurance policies | (0.03 | ) | ||||||||||||||||||||||
| Impairment of investment in partnership | 0.01 | |||||||||||||||||||||||
| Earnings before items impacting comparability | 0.10 | (0.02 | ) | 0.07 | 0.14 | 0.01 | (0.01 | ) | ||||||||||||||||
Consolidated | ||||||||||||||||||||||||
| Reported earnings | 2.01 | |||||||||||||||||||||||
| Total items impacting comparability from above | (0.03 | ) | ||||||||||||||||||||||
| Earnings before items impacting comparability | $ | 1.98 | ||||||||||||||||||||||
Consolidated Earnings from Continuing Operations | ||||||||||||||||||||||||
| Reported earnings from continuing operations | 1.81 | 1.61 | 3.96 | 3.18 | (0.53 | ) | ||||||||||||||||||
| Total items impacting comparability from above | (0.08 | ) | 0.44 | (1.70 | ) | (0.01 | ) | 1.33 | ||||||||||||||||
| Earnings from continuing operations before items impacting comparability | $ | 1.73 | $ | 2.05 | $ | 2.26 | $ | 3.17 | $ | 0.80 | ||||||||||||||
Discontinued Operations | ||||||||||||||||||||||||
| Reported earnings from discontinued operations | 0.42 | |||||||||||||||||||||||
Consolidated | ||||||||||||||||||||||||
| Reported earnings | $ | 2.23 | $ | 1.61 | $ | 3.96 | $ | 3.18 | $ | (0.53 | ) | |||||||||||||
Reconciliation of Pipeline & Storage Operating Revenues to
Consolidated Operating Revenues Fiscal 2008
($Millions)
Consolidated Operating Revenues Fiscal 2008
($Millions)
| Pipeline Revenues | $ | 126.7 | ||
| Storage Revenues | $ | 67.0 | ||
| Other Revenues | $ | 22.9 | ||
| Total Pipeline & Storage Revenues | $ | 216.6 | ||
| All Other Segments | $ | 2,183.8 | ||
| Total Corporation | $ | 2,400.4 | ||
Reconciliation of Pipeline & Storage O&M Expense to
Consolidated O&M Expense (From Continuing Operations)
($000s)
Consolidated O&M Expense (From Continuing Operations)
($000s)
| 3 Mos. End | ||||||||||||||||||||||||
| 2004 | 2005 | 2006 | 2007 | 2008 | 12/31/2008 | |||||||||||||||||||
| Pipeline & Storage | $ | 65,071 | $ | 65,397 | $ | 66,340 | $ | 61,230 | $ | 70,632 | $ | 16,147 | ||||||||||||
| SFAS 88 Pension Settlement | 3,026 | — | — | — | — | — | ||||||||||||||||||
| All Other Segments | 305,913 | 322,697 | 328,949 | 335,178 | 362,239 | 85,187 | ||||||||||||||||||
| Total Corporation | $ | 374,010 | $ | 388,094 | $ | 395,289 | $ | 396,408 | $ | 432,871 | $ | 101,334 | ||||||||||||
Reconciliation of Utility Segment O&M Expense to
Consolidated O&M Expense (From Continuing Operations)
($000s)
Consolidated O&M Expense (From Continuing Operations)
($000s)
| 3 Mos. End | ||||||||||||||||||||||||
| 2004 | 2005 | 2006 | 2007 | 2008 | 12/31/2008 | |||||||||||||||||||
| Utility Segment | $ | 190,669 | $ | 211,019 | $ | 204,330 | $ | 202,965 | $ | 202,745 | $ | 49,614 | ||||||||||||
| SFAS 88 Pension Settlement | 3,374 | — | — | — | — | — | ||||||||||||||||||
| All Other Segments | 179,967 | 177,075 | 190,959 | 193,443 | 230,126 | 51,720 | ||||||||||||||||||
| Total Corporation | $ | 374,010 | $ | 388,094 | $ | 395,289 | $ | 396,408 | $ | 432,871 | $ | 101,334 | ||||||||||||
Reconciliation of Utility Segment Aged Accounts Receivable to
Consolidated Accounts Receivable — Net
Consolidated Accounts Receivable — Net
| at 12/31/04 | at 12/31/05 | at 12/31/06 | at 12/31/07 | at 12/31/08 | ||||||||||||||||
| Utility Aged Accounts Receivable | $ | 67.3 | $ | 79.6 | $ | 86.6 | $ | 77.4 | $ | 86.7 | ||||||||||
| Utility Current/Other Accounts Receivable | $ | 78.7 | $ | 135.3 | $ | 62.2 | $ | 79.7 | $ | 108.0 | ||||||||||
| Utility Gross Accounts Receivable | $ | 146.0 | $ | 214.9 | $ | 148.8 | $ | 183.6 | $ | 194.7 | ||||||||||
| Utility Reserve for Bad Debt | $ | (15.1 | ) | $ | (31.5 | ) | $ | (34.2 | ) | $ | (32.7 | ) | $ | (37.5 | ) | |||||
| Utility Net Accounts Receivable | $ | 130.9 | $ | 183.4 | $ | 114.6 | $ | 150.9 | $ | 157.2 | ||||||||||
| All Other Segments Gross Accounts Receivable | $ | 71.5 | $ | 107.6 | $ | 79.5 | $ | 92.9 | $ | 75.9 | ||||||||||
| All Other Segments Reserve for Bad Debts | $ | (4.7 | ) | $ | (1.8 | ) | $ | (1.5 | ) | $ | (1.4 | ) | $ | (3.9 | ) | |||||
| All Other Segments Net Accounts Receivable | $ | 66.8 | $ | 105.8 | $ | 78.0 | $ | 91.5 | $ | 72.0 | ||||||||||
| Total Corporation Accounts Receivable — Net | $ | 197.7 | $ | 289.2 | $ | 192.6 | $ | 242.4 | $ | 229.2 | ||||||||||
Reconciliation of National Fuel Gas Expenditures for Long-lived Assets to
Consolidated Net Cash Used in Investing Activities
(‘000)
Consolidated Net Cash Used in Investing Activities
(‘000)
| 3 Mos. End | ||||||||||||||||||||||||
| 2004 | 2005 | 2006 | 2007 | 2008 | 12/31/2008 | |||||||||||||||||||
| Capital Expenditures | $ | (172,341 | ) | $ | (219,530 | ) | $ | (294,159 | ) | $ | (276,728 | ) | $ | (414,502 | ) | $ | (84,268 | ) | ||||||
| Investment in Subsidiaries, Net of Cash — Empire Connector | $ | — | $ | — | $ | — | $ | — | $ | (16,768 | ) | $ | 16,768 | |||||||||||
| Investment in Subsidiaries, Net of Cash — Lease Acquisition Costs (primarily PA DCNR) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (51,741 | ) | |||||||||||
| Investment in Partnerships | $ | — | $ | — | $ | — | $ | (3,300 | ) | $ | — | $ | — | |||||||||||
| Expenditures for Long Lived Assets | $ | (172,341 | ) | $ | (219,530 | ) | $ | (294,159 | ) | $ | (280,028 | ) | $ | (397,734 | ) | $ | (119,241 | ) | ||||||
| Cash Expenditures for Long Lived Assets | $ | (172,341 | ) | $ | (219,530 | ) | $ | (294,159 | ) | $ | (280,028 | ) | $ | (397,734 | ) | $ | (119,241 | ) | ||||||
| Net Proceeds from Sale of Foreign Subsidiary | $ | — | $ | 111,619 | $ | — | $ | 232,092 | $ | — | $ | — | ||||||||||||
| Cash Held in Escrow | $ | (58,248 | ) | $ | 58,397 | $ | — | |||||||||||||||||
| Net Proceeds from Sale of Oil and Gas Producing Properties | $ | 7,162 | $ | 1,349 | $ | 13 | $ | 5,137 | $ | 5,969 | $ | — | ||||||||||||
| Investment in Subsidiaries, Net of Cash — Empire Connector | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (16,768 | ) | |||||||||||
| Investment in Subsidiaries, Net of Cash — Lease Acquisition Costs (primarily PA DCNR) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 51,741 | ||||||||||||
| Other | $ | 1,974 | $ | 3,238 | $ | (3,230 | ) | $ | (725 | ) | $ | 4,376 | $ | (632 | ) | |||||||||
| Net Cash Used in Investing Activities | $ | (163,205 | ) | $ | (103,324 | ) | $ | (297,376 | ) | $ | (101,772 | ) | $ | (328,992 | ) | $ | (84,900 | ) | ||||||
Reconciliation of Exploration & Production Segment Capital Expenditures to
Consolidated Capital Expenditures
($000s)
Consolidated Capital Expenditures
($000s)
| 2006 | 2007 | 2008 | 2009 Forecast | 2010 Forecast | ||||||||||||||||
| Exploration & Production Capital Expenditures | $ | 166,535 | $ | 146,687 | $ | 192,187 | $ | 244,000 | $ | 227,000 | ||||||||||
| All Other | $ | 127,624 | $ | 130,041 | $ | 222,315 | $ | 132,000 | $ | 137,000 | ||||||||||
| Total Corporation | $ | 294,159 | $ | 276,728 | $ | 414,502 | $ | 376,000 | $ | 364,000 | ||||||||||
Reconciliation of Exploration & Production Operating Revenue to
Consolidated Operating Revenue
($000s)
Consolidated Operating Revenue
($000s)
| 2008 | ||||
| Exploration & Production | $ | 466,760 | ||
| All Other Segments | 1,933,601 | |||
| Consolidated Operating Revenue | $ | 2,400,361 | ||
Reconciliation of Exploration & Production Net Income to
Consolidated Net Income
($000s)
Consolidated Net Income
($000s)
| 2005 | 2006 | 2007 | 2008 | |||||||||||||
| Exploration & Production (Income from Continuing Operations) | $ | 35,581 | $ | 67,494 | $ | 74,889 | $ | 146,612 | ||||||||
| Income from Discontinued Operations, Net of Tax | 15,078 | (46,523 | ) | 15,479 | — | |||||||||||
| Gain on Disposal of Discontinued Operations, Net of Tax | — | — | 120,301 | — | ||||||||||||
| Total Exploration & Production | $ | 50,659 | $ | 20,971 | $ | 210,669 | $ | 146,612 | ||||||||
| All Other Segments | 138,829 | 117,120 | 126,786 | 122,116 | ||||||||||||
| Consolidated Net Income | $ | 189,488 | $ | 138,091 | $ | 337,455 | $ | 268,728 | ||||||||