National Fuel Gas Company 8-K - SEC.gov | HOME Fuel Gas Company (the “Company”) plans to hold...

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0000950152-07-003250.txt : 200704160000950152-07-003250.hdr.sgml : 2007041620070416120951ACCESSION NUMBER:0000950152-07-003250CONFORMED SUBMISSION TYPE:8-KPUBLIC DOCUMENT COUNT:64CONFORMED PERIOD OF REPORT:20070416ITEM INFORMATION:Regulation FD DisclosureITEM INFORMATION:Financial Statements and ExhibitsFILED AS OF DATE:20070416DATE AS OF CHANGE:20070416

FILER:

COMPANY DATA:COMPANY CONFORMED NAME:NATIONAL FUEL GAS COCENTRAL INDEX KEY:0000070145STANDARD INDUSTRIAL CLASSIFICATION:NATURAL GAS DISTRIBUTION [4924]IRS NUMBER:131086010STATE OF INCORPORATION:NJFISCAL YEAR END:0930

FILING VALUES:FORM TYPE:8-KSEC ACT:1934 ActSEC FILE NUMBER:001-03880FILM NUMBER:07767560

BUSINESS ADDRESS:STREET 1:6363 MAIN STREETCITY:WILLIAMSVILLESTATE:NYZIP:14221-5887BUSINESS PHONE:716-857-7000

MAIL ADDRESS:STREET 1:6363 MAIN STREETSTREET 2:6363 MAIN STREETCITY:WILLIAMSVILLESTATE:NYZIP:14221-5887

8-K1l25612ae8vk.htmNATIONAL FUEL GAS COMPANY 8-K

National Fuel Gas Company 8-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section13 or 15(d) of the
Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): April16, 2007

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

New Jersey

1-3880

13-1086010

(State or other jurisdiction

(Commission File Number)

(IRS Employer

of incorporation)

Identification No.)

6363 Main Street, Williamsville, New York
14221

(Address of principal executive offices)
(Zip Code)

Registrants telephone number, including area code: (716)857-7000

Former name or former address, if changed since last report: Not Applicable

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfythe filing obligation of the registrant under any of the following provisions (see GeneralInstruction A.2. below):

o Written communications pursuant to Rule425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuantto Rule14d-2(b) under the Exchange Act(17 CFR 240.14d-2(b))

o Pre-commencement communications pursuantto Rule13e-4(c) under the Exchange Act(17 CFR 240.13e-4(c))

Item7.01 RegulationFD Disclosure

National Fuel Gas Company (the Company) plans to hold meetings with certain industry analysts, money managers, and other members of the financial community on Monday, April16, 2007, Tuesday, April17, 2007 and Wednesday, April18, 2007. A copy of presentation materials to be provided to participants in the meetings is herebyincorporated by reference into this Item7.01 and furnished as part of this Current Report asExhibit99.

Neither the furnishing of the presentation as an exhibit to this Current Report nor the inclusionin such presentation of any reference to the Companys internet address shall, under anycircumstances, be deemed to incorporate the information available at such internet address intothis Current Report. The information available at the Companys internet address is not part ofthis Current Report or any other report filed or furnished by the Company with the Securities andExchange Commission.

In addition to financial measures calculated in accordance with generally accepted accountingprinciples (GAAP), the slide presentation furnished as part of this Current Report as Exhibit99contains certain non-GAAP financial measures. The Company believes that such non-GAAP financialmeasures are useful to investors because they provide an alternative method for assessing theCompanys operating results in a manner that is focused on the performance of the Companys ongoingoperations. The Companys 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 notmeant to be a substitute for financial measures prepared in accordance with GAAP.

Certain statements contained herein or incorporated by reference from the presentation, includingstatements regarding earnings projections, statements designated with an asterisk (*) andstatements identified by the use of the words anticipates, estimates, expects, intends,plans, predicts, projects, and similar expressions, are forward-looking statements asdefined by the Private Securities Litigation Reform Act of 1995. There is no assurance that theCompanys projections will in fact be achieved nor do these projections reflect any acquisitions ordivestitures that may occur in the future. While the Companys expectations, beliefs andprojections are expressed in good faith and are believed to have a reasonable basis, actual resultsmay differ materially from those in the forward-looking statement. Furthermore, eachforward-looking statement speaks only as of the date on which it is made. In addition to otherfactors, the following are important factors that could cause actual results to differ materiallyfrom those discussed in the forward-looking statements: changes in laws and regulations to whichthe Company is subject, including changes in tax, environmental, safety and employment laws andregulations; changes in economic conditions, including economic disruptions caused by terroristactivities, 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/orprice of natural gas or oil and the effect of such changes on the accounting treatment or valuationof derivative financial instruments or the Companys natural gas and oil reserves; impairmentsunder the SECs full cost ceiling test for natural gas and oil reserves; changes in theavailability and/or price of derivative financial instruments; changes in the price differentialsbetween various types of oil; inability to obtain new customers or retain existing

ones; significant changes in competitive factors affecting the Company; governmental/regulatoryactions, initiatives and proceedings, including those involving acquisitions, financings, ratecases (which address, among other things, allowed rates of return, rate design and retained gas),affiliate relationships, industry structure, franchise renewal, and environmental/safetyrequirements; unanticipated impacts of restructuring initiatives in the natural gas and electricindustries; significant changes from expectations in actual capital expenditures and operatingexpenses and unanticipated project delays or changes in project costs or plans, including changesin the plans of the sponsors of the proposed Millennium Pipeline with respect to that project; thenature and projected profitability of pending and potential projects and other investments;occurrences affecting the Companys ability to obtain funds from operations or from issuances ofdebt or equity securities to finance needed capital expenditures and other investments, includingany downgrades in the Companys credit ratings; uncertainty of oil and gas reserve estimates;ability to successfully identify and finance acquisitions or other investments and ability tooperate and integrate existing and any subsequently acquired business or properties; ability tosuccessfully identify, drill for and produce economically viable natural gas and oil reserves;significant changes from expectations in the Companys actual production levels for natural gas oroil; regarding foreign operations, changes in trade and monetary policies, inflation and exchangerates, taxes, operating conditions, laws and regulations related to foreign operations, andpolitical and governmental changes; significant changes in tax rates or policies or in rates ofinflation or interest; significant changes in the Companys relationship with its employees orcontractors and the potential adverse effects if labor disputes, grievances or shortages were tooccur; changes in accounting principles or the application of such principles to the Company; thecost and effects of legal and administrative claims against the Company; changes in actuarialassumptions and the return on assets with respect to the Companys retirement plan andpost-retirement benefit plans; increasing health care costs and the resulting effect on healthinsurance premiums and on the obligation to provide post-retirement benefits; or increasing costsof insurance, changes in coverage and the ability to obtain insurance. The Company disclaims anyobligation to update any forward-looking statements to reflect events or circumstances after thedate hereof.

Item9.01 Financial Statements and Exhibits

(c)Exhibits

Exhibit99

Presentation materials for meetings to be held April16, 2007 through April18, 2007

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has dulycaused this report to be signed on its behalf by the undersigned hereunto duly authorized.

NATIONAL FUEL GAS COMPANY

By: /s/ James R. Peterson

James R. Peterson

Assistant Secretary

April16, 2007

EXHIBIT INDEX

Exhibit Number Description

99

Presentation materials for meetings to be heldApril16, 2007 through April18, 2007

EX-992l25612aexv99.htmEX-99

EX-99

Exhibit99

Safe Harbor

NOTE: This presentation contains certain forward-looking statements asdefined by the Private Securities Litigation Reform Act of 1995.Forward-looking statements include, but are not limited to, statementsconcerning plans, objectives, goals, projections, strategies and futureevents or performance, other statements that are not statements ofhistorical fact, and statements identified by words such as "anticipates,""believes," "estimates," "expects," "intends," "plans," "may," "should,""will" or words of similar meaning. While National Fuel's expectations,beliefs and projections are made in good faith and are believed to have areasonable basis, actual results may differ materially. Refer to NationalFuel's most recent Form 10-Q for a listing of important risk factors youshould consider. In addition, this presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financialmeasures, pages containing the most directly comparable GAAP financialmeasures and reconciliations are provided at the end of this presentation.

Grow shareholder value

through timely

investment in the

energy industry.

National Fuel Gas Company

Corporate Objective


Net Plant by Segment

$2.9 Billion

At December 31, 2006 P&S Utility All Other E&P Net plant 0.67 1.088 0.1166 1.021

$190.8 Million

12 Months Ended December 31, 2006 P&S Utility Timber Energy Mkt. Corp. & Other E&P NI 51.6 45.2 4.4 5.3 2.5 81.7


Net Income from Continuing Operations*

* Excludes oil and gas impairment of $68.6 million,income tax adjustments of $11.2 million, anddiscontinuance of hedge accounting of $1.9 million.

$2.5 Billion

At December 31, 2005 Long-Term Debt Short-Term Debt Shareholder Equity Off B/S Financing Capitalization 1126.3 74.8 1321.3 49.8


Capitalization Long-Term Debt Short-Term Debt Shareholder Equity Capitalization 1095.6 71.6 1454.8

Short-Term Debt2.7%

ShareholderEquity

55.5%

Long-Term*Debt

41.8%

$2.6 Billion

At December 31, 2006

Includes Current Portion of Long-Term Debt

6

Fiscal Year 2002 2003 2004 2005 2006 2007 1Q Earnings 0.62 0.7 0.56 0.46 0.58 0.2

Fiscal Year

Utility

Diluted Earnings per Share

2002 2003 2004 2005 2006 1Q 2007 Utility 169 179 191 211 204 50.7

Utility O & M Expense

* Excludes SFAS 88 settlement loss of -$3.4 million

Fiscal Year

$ Millions

*

Utility

Rate Case Activity

11/30/06: The Pennsylvania PUCApproved the Settlement AgreementReached in the Delivery ServiceCharge Rate Case

Effective Date: 1/1/07

Revenue Increase: $14.3 MM

Revenue Decoupling: InitiallyProposed by The Utility in This Case.Will Instead be Pursued Via ActiveParticipation in The Statewide GenericProceeding Announced by ThePennsylvania PUC on September 28,2006

Pennsylvania

01/29/07: Utility Submitted a Requestto Re-Design and Raise its DeliveryService Charges in 2008

Proposed Revenue Increase: $52 MM,or 6.4%

Revenue Decoupling: The Utility'sProposed Conservation IncentiveProgram Would Allocate $12 MM tothe Promotion of EnergyConservation and Provide CustomerConservation Incentives

The delivery rate would be adjusted,based upon throughput, to enable theUtility to recover its operating margin

New York

Case Concluded

Case Initiated

Utility

Rate Case Settlements

* Represents the approximate range of rate base filed for in this case.

** Black-box settlement in both states. Previous Settlements Previous Settlements Current Case New York Pennsylvania New York Approximate Rate Base $640-$650 MM $280-$290 MM* $711 MM Approximate Base Rate Revenue Increase $21 MM $14.3 MM $52 MM Effective Date 8/1/2005 1/1/2007 Late '07/Early '08 Approximate Utility Capital Structure**: Approximate Utility Capital Structure**: Long-term Debt Cost ComponentShort-term Debt Cost ComponentEquity Component Return on Equity 45.0%6.65%5.0%5.0 - 6.0%50.0%10.0 - 11.0% 39.4%6.57%9.5%5.3%51.1%11.65%

New York Merchant Function Charge Varies

with Cost of Gas

Rates Include Allowance Attributable to

Uncollectible Expense

Residential Non-Residential

2.742% .304%

Multiplied by Gas Supply Cost Rate

Utility Bad Debt Tracking

At 12/31/04 At 9/30/05 At 12/31/05* At 09/30/06 At 12/31/06 30-59 days 11.9 9 16.7 9.2 11.9 60-89 days 5.5 6.5 6.4 7.1 6.02 90-119 days 3.7 6.3 4 6.8 4.36 120 days & over 46.2 54.5 52.6 66.7 64.32 Reserve for Bad Debt 15.1 25.1 31.5 29.7 34.18

Utility

Accounts Receivable - Customer

$ Millions

* Includes receivables purchased pursuant to implementation of the Utility's New York rate case settlement.

13

2,966 Miles of System Pipeline

15 Compressor Stations Totaling 39,886

Horsepower

Transportation Volume for Fiscal 2006:

375.0 Bcf

$123.4 MM in Revenues for Fiscal 2006

Pipeline & Storage

Pipeline Operating Statistics

32 Underground Natural Gas Storage

Fields (4 Co-owned with Nonaffiliated

Companies)

15 Compressor Stations Totaling 35,475

Horsepower

73.4 Bcf of Working Storage Capacity

$66.8 MM in Revenues for Fiscal 2006

Pipeline & Storage

Storage Operating Statistics

Fiscal Year

Pipeline & Storage

Diluted Earnings per Share Fiscal Year 2002 2003 2004 2005 2006 2007 1Q Earnings 0.37 0.56 0.58 0.71 0.65 0.16

Pipeline & Storage

FERC Proceeding

2/9/07: The FERC approved the uncontested Stipulation & Agreementfiled as an offer of settlement in the FERC Proceeding brought byNYPSC, PaPUC and Pennsylvania OCA (FERC Docket No. RP06-298-000).

The economically effective date of the settlement is December 1, 2006.

Supply Corp.'s gas retention allowance will decrease from 2% to 1.4%, reducingannual excess "efficiency gas" volumes by ?1.5 Bcf

After a 5-year general rate case moratorium, Supply Corp. will make a rate casefiling to be effective December 1, 2011

Supply Corp.'s annual depreciation rates will decrease to 2.9% for transmissionplant and 2.23% for storage plant, decreasing its annual depreciation expense by?$5.63 million

Rate allowance for post-retirement medical expenses will increase from ?$4.7 MMper year to $11 MM per year, including a 5-year amortization of ?$12.43 MM for arelated regulatory asset

Supply Corp. will amend its tariff provisions on discounting gas retentionallowances to be consistent with FERC's current policy limiting "fuel discounts"

18

Empire Connector

FERC Approved the Empire Connector Project by Order issued 12/21/06

Initial Capacity 250,000 Dth/day - KeySpan 150,750

Dth/day

Target In-Service Date Fall 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

Leidy Hub

Our Prime Location

20

Energy Marketing

Customers & Marketing Area Customers at FYE Customers at FYE Customers at FYE Residential Commerical/Industrial 2006 14,963 4,605 2005 14,902 4,265 2004 15,983 4,345

Only Natural Gas Service Territory Is Shown

Energy Marketing

Diluted Earnings per Share Fiscal Year 2002 2003 2004 2005 2006 2007 1Q Earnings 0.11 0.07 0.07 0.06 0.07 0.01

Fiscal Year

Canada - 7%

43.3 BCFE

NY

PA

Gulf Coast - 8%

49.3 BCFE

CA - 72%

405.1 BCFE

Total: 580.7 BCFE /

96.8 MMBOE

Oil: 60% Gas: 40%

Reserves by Region

(at 09/30/06)

East -

13%

83.0BCFE

E&P First Quarter Results

Expenses/Mcfe FY 07 1Q FY 06 1Q DD&A $1.83 $1.93 LOE $1.21 $1.32 G&A $0.46 $0.56 Quarter Over Quarter Change DD&A -0.0518 LOE -0.0833 G&A -0.1786

ReducedExpenses

E&P First Quarter Results FY 07 1Q FY 06 1Q Production 12.0 BCFE 11.2 BCFE Operating Revenue $88.7 MM $82.1 MM Net Income $20.7 MM $17.4 MM Net Income Per Share $0.24 $0.20 Quarter Over Quarter Change Production 0.076455 Operating Revenue 0.080389768 Net Income 0.189655 Net Income Per Share 0.2

ImprovedResults

Fiscal Year 2002 2003 2004 2005 2006 20071Q Earnings 0.33 0.46 0.61 0.6 0.91 0.24

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 oil & gas impairment of -$0.80 and income tax adjustments of +$0.13

Fiscal Year

Exploration & Production


c

Fiscal Year


NFG Average Total Sale Price of Natural Gas* 2002 2003 2004 2005 2006 NFG Avg Appalachian 3.74 5.1 5.72 7.01 8.9 NFG Avg Total US 3.58 4.52 5.13 6.26 7.02

Per Mcf

* After Hedging

Fiscal Year


NFG Average Total Sale Price of Oil* 2002 2003 2004 2005 2006 NFG Avg Appalachian 23.76 28.77 31.3 48.28 65.28 NFG Avg Total US 21.01 25.11 26.06 26.59 40.26

Per Barrel

* After Hedging

$US Millions


Estimated Capital Expenditures 2007 Gulf West East Canada Exploration Drlg. 64.5 4 5.6 23.4 G&G 4.3 0 0.5 2.7 Development New 0 0 23 1.9 Development Proved 5.6 28.1 0.4 0 Facilities 17.6 8.6 3.5 2.3 Leasehold Acquisition 5.4 0 1.8 2.7 Other 2.3 1.8 0.3 1.4

$99.7

$42.5

$35.1

$34.4

2002 2003 2004 2005 2006 2007E 1Q 2007 East 8.4 9.4 9.5 12.5 27 35.5 4.4 West 34.4 11.4 17.4 29.6 36 42.5 11.8 Canada 27 30.8 31.4 38.5 42 34.5 9.3 Gulf 44.8 24.2 19.4 41.8 103 99.5 21.1

$114.6

$75.8

$77.7

$122.4

$208.0

Fiscal Year

$US Millions


Capital Expenditures by Division

$210-$214

$46.6

Includes

$8.4 MM

to DevelopProvedUndevelopedReserves

Seneca's Working Interest: 20%

Sukunka b-60-E Production Commenced on

December 13, 2004

Current Sales Rate up to 60 MMcf/d *

Sukunka d-93-D Well Successfully Completed

Production Tests at Rates up to 33 MMcf/d *

Sukunka 69-C Currently Evaluating

Expected Completion during 2nd Quarter FY 2007.


Sukunka Wells

* Third Party Processing Facilities Limit Production to 65 MMcf/d

0

15 miles

(2nd Well)

(3rd Well)

(5th Well)

(4th Well)

AREA OF MUTUAL INTEREST

Gas Wells

Drilling Wells

Working interest lands

Lands to be earned by drilling

66-E

79-J

50-C

93-D

(1st Well)

60-E

Sukunka Area Land Map

Monkman

P & A'd

(6th Well)

77-D

(7th Well)

69-C

939,000 Total Net Acres

788,000 in PA

151,000 in NY

National Fuel Mineral Interests

Devonian Shale Play

Northern Appalachian BasinDevonian Shale Play

national fuel

January 2007

67

E&P East Division

Stratigraphic Column

Devonian Shales

Depth: 4,500' - 8,000' (PA)

Bass Island, Lockport, Medina, Whirlpool

Depth: 2,000' - 6,000' (NY / PA)

Upper Devonian Sandstones

Depth: 800' - 4,500' (PA)

Onondaga Limestone

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)

national fuel

January 2007

69

JV with EOG Resources

Required Initial Activities

1Q07 - 2Q07

3Q07 - 1Q08

2Q08 - 1Q09

Acquire Data

Evaluate/ DetermineInitial DrillingLocations

Drill 5 ExploratoryWells

Acquire/ EvaluateAdditional Data

Design/TestCompletion Technique& Well Flow

Produce Wells ifPossible

Determine AdditionalDrilling Locations

Drill 5 AdditionalWells

Acquire/ EvaluateAdditional Data

Design/TestCompletion Technique& Well Flow

Produce Wells ifPossible

Evaluate Results toDate

Determine Strategyfor AdditionalExploration orDevelopment, asAppropriate

Fiscal Quarters

2002 2003 2004 2005 2006 East 30 61 41 48 144.46 West 47.99 30.97 49 116.97 92.98 Canada 33.9 22.16 63.35 24.64 15.1 Gulf 1.58 3.35 0.65 1.53 3.72

Fiscal Year

Drilling Activity by Division

Productive Net Wells

113

117

154

256

191

Net Wells Completed

Fiscal Year 2002 2003 2004 2005 2006 2007 1Q Earnings 0.12 0.12 0.07 0.06 0.07 0.003

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



Share Buyback

Date Authorized:

December 8, 2005

Authorized Amount:

Up to 8 Million Shares

As of 12/31/06:

3,710,478 Shares Repurchased

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


Dividend Growth

$0.19

$1.20

Annual Rate At Fiscal Year End

APPENDIX


New York Stock Exchange

NFG

Shares Outstanding (Approx.)

(As of 12/31/06)

82.6 Million

Average Daily Trading Volume

(12 Months Ended 3/30/07)

536,630

Market Capitalization (Approx.)

(As of 03/30/07)

$3.6 Billion

$1.20

Annual Dividend Rate

September

Fiscal Year End


Energy

Mktg.

Timber

E&P

P&S

Utility

National Fuel

Gas

Distribution

Corporation

National Fuel

Gas Supply

Corporation

and

Empire State

Pipeline

Seneca

Resources

Corporation

Highland Forest

Resources, Inc.

and NE Div. Of

Seneca Resources

Corporation

National Fuel

Resources,

Inc.


Major Business Segments

1/1/1970 2/1/1970 3/1/1970 4/1/1970 5/1/1970 6/1/1970 7/1/1970 8/1/1970 9/1/1970 10/1/1970 11/1/1970 12/1/1970 1/1/1971 2/1/1971 3/1/1971 4/1/1971 5/1/1971 6/1/1971 7/1/1971 8/1/1971 9/1/1971 10/1/1971 11/1/1971 12/1/1971 1/1/1972 2/1/1972 3/1/1972 4/1/1972 5/1/1972 6/1/1972 7/1/1972 8/1/1972 9/1/1972 10/1/1972 11/1/1972 12/1/1972 1/1/1973 2/1/1973 3/1/1973 4/1/1973 5/1/1973 6/1/1973 7/1/1973 8/1/1973 9/1/1973 10/1/1973 11/1/1973 12/1/1973 1/1/1974 2/1/1974 3/1/1974 4/1/1974 5/1/1974 6/1/1974 7/1/1974 8/1/1974 9/1/1974 10/1/1974 11/1/1974 12/1/1974 1/1/1975 2/1/1975 3/1/1975 4/1/1975 5/1/1975 6/1/1975 7/1/1975 8/1/1975 9/1/1975 10/1/1975 11/1/1975 12/1/1975 1/1/1976 2/1/1976 3/1/1976 4/1/1976 5/1/1976 6/1/1976 7/1/1976 8/1/1976 9/1/1976 10/1/1976 11/1/197612/1/1976 1/1/1977 2/1/1977 3/1/1977 4/1/1977 5/1/1977 6/1/1977 7/1/1977 8/1/1977 9/1/1977 10/1/1977 11/1/1977 12/1/1977 1/1/1978 2/1/1978 3/1/1978 2.727279545 2.798297727 2.840918182 2.698881818 2.514225 2.372140909 2.428984091 2.642038636 2.5284 2.500002273 2.599418182 2.5284 2.784075 2.911936364 2.684659091 2.982954545 2.840918182 2.784075 2.7699 2.840918182 2.713056818 2.755677273 2.741454545 2.840918182 3.03975 3.03975 2.982954545 2.897713636 2.883538636 2.840918182 2.798297727 2.869315909 2.982954545 3.025575 3.153388636 3.139213636 3.181834091 3.210231818 3.139213636 2.897713636 2.713056818 2.727279545 2.613640909 2.627863636 2.883538636 2.7699 2.500002273 2.400586364 2.670436364 2.698881818 2.514225 2.386363636 2.159086364 1.974429545 2.173309091 1.974429545 2.045447727 2.144863636 2.088068182 2.088068182 2.343743182 2.301122727 2.457381818 2.357965909 2.500002273 2.556797727 2.428984091 2.400586364 2.357965909 2.400586364 2.414761364 2.428984091 2.713056818 2.500002273 2.500002273 2.5284 2.514225 2.5284 2.741454545 2.826695455 2.840918182 2.869315909 2.869315909 3.181834091 3.238629545 3.011352273 2.954556818 3.053972727 3.025575 3.238629545 3.110815909 2.897713636 2.997177273 3.025575 2.997177273 3.03975 2.840918182 2.840918182 2.883538636


Stock Price (Jan 1970 - Mar 30, 2007)

03/30/2007$43.26

2001 2002 2003 2004 2005 2006 2007E 1Q 2007 Utility 42.4 51.5 49.9 55.5 50.1 54.4 58 12.9 P & S 26 30.3 199.4 23.2 21.1 26 65 4.9 E & P 296.4 114.6 75.8 77.7 121.2 208.3 212 46.6 Energy Mkt. 0.116 0.1 0.2 0.0102 0 $- 0 0 Timber 3.7 25.6 3.5 2.8 18.9 2.3 2 0.8 Corp & Others 0.937 6.6 50.1 5.7 1.1 3.2 2 1.8 International 15.6 4.2 2.5 7.5 5.9 0 0

$ Millions

$232.9

$381.4

$172.3

$218.3

Fiscal Year


Expenditures for Long-Lived Assets

$294.2

Approx.

$337-$341

$67.0

2002 2003 2004 2005 2006 4.29 4 5.27 3.73 5.48

Fiscal Year


Net Cash Provided by Operating Activities per Diluted Share

EPS Guidance & Sensitivity

Natural Gas

($/MMBtu)

Oil

($/Bbl)

At 09/21/06

$65.35

$7.471

Average

$66.67

$7.476

Sept-07

$66.49

$7.391

Aug-07

$66.25

$7.311

Jul-07

$65.96

$7.221

Jun-07

$65.61

$7.126

May-07

$65.18

$7.166

Apr-07

$64.65

$7.746

Mar-07

$64.03

$7.921

Feb-07

$63.32

$7.881

Jan-07

* Please refer to Safe Harbor for Forward-Looking Statements on pp. 33-35 of National Fuel Gas's 2/6/07 Form 10-Q. The sensitivity table is current as of February1, 2007 and only considers revenue from the Exploration and Production segment's crude oil and natural gas sales. The sensitivities will become obsolete withthe passage of time, changes in Seneca's production forecast, changes in basis differentials, as additional hedging contracts are entered into, and with thesettling of NYMEX hedge contracts at their maturity.

- -$0.07

+$0.07

- -$0.11

+$0.11

Decrease

Decrease

Increase

$5 change perBbl Oil

$1 change perMMBtu Gas

Diluted Earnings Per Share Guidance*

Range

$2.15 - $2.35

Consolidated Earnings

Earnings per Share Sensitivity toChanges From 9/21/06 NYMEX Prices*

Increase

Fiscal 2007

NFG & Subsidiaries

NYMEX Settlement Prices

2002 2003 2004 2005 2006 1Q 2007 61.3 60.7 65.1 65.4 66.3 14.8

* Excludes SFAS 88 settlement loss of -$3.0 million

*

Pipeline & Storage

O & M Expense

$ Millions

Fiscal Year

Swaps Volume Average Hedge Price Oil 0.5 MMBBL $37.86 / BBL Gas 4.5 BCF $ 7.32 / MCF No-cost Collars Volume Lowest Floor Price Highest Ceiling Price Oil 0.1 MMBBL $70.00 / BBL $77.00 / BBL Gas 4.1 BCF $ 7.42 / MCF $18.52 / MCF

Nine Months Remaining Fiscal 2007


Hedging Summary at 12/31/06

Fiscal 2008 Swaps Volume Average Hedge Price Oil 0.2 MMBBL $51.80 / BBL Gas 5.1 BCF $ 8.31 / MCF No-cost Collars Volume Lowest Floor Price Highest Ceiling Price Gas 1.4 BCF $ 8.83 / MCF $16.45 / MCF

E&P's Forecast Data for Fiscal 2007

Production: 47 - 52 BCFE

Number of Wells to be Drilled: 255 - 298

Expenses/Mcfe Estimated RangeDD&A $1.90

LOE $1.10 - $1.30

Other Taxes (% of Revenue) $0.10 - $0.14

Other Operating Expenses $8.5 MM - $10.5 MM

General and Administrative $ 24 MM - $26 MM

Standard & Poor's Moody's Fitch, Inc. Long-Term Debt BBB+ Baa1 A- Outlook Stable Stable Stable Commercial PaperA-2P-2F2

NFG Debt Ratings

at March 30, 2007

Commercial Paper Program And Bilateral CreditFacilities - Aggregate Of $635 MM

$71.6 MM borrowed at December 31, 2006

$300.0 MM Committed Credit Facility ThroughSeptember 2010

$0 borrowed at December 31, 2006

Universal Shelf Registration on File - Additional

$550 MM Can Be Issued As Debt Or Equity Securities

Any offer and sale of such securities will be made only by meansof a prospectus meeting requirements of securities laws


Capital Resources

Comparable GAAP Financial Measure Slides

And

Reconciliations

2001 2002 2003 2004 2005 2006 1Q 2007 387.9 205.8 104.8 163.2 103.3 297.4 65.1

Fiscal Year


Consolidated Net Cash Used in Investing Activities

$ Millions

P&S Utility Timber Energy Mkt. Corp. & Other E&P NI 53.5 45.2 4.4 5.3 2.5 24.3


Net Income from Continuing Operations*

$135.2 Million

12 Months Ended December 31, 2006

1999 2000 2001 2002 2003 2004 2005 2006 1Q 2007 Utility 0.51 0.4 0.76 0.62 0.7 0.56 0.46 0.58 0.2 All Other Segments 0.96 1.21 0.06 0.84 1.5 1.45 1.77 1.03 0.44

$1.46

$2.20

$2.01

$2.23

Fiscal Year

Utility vs. Consolidated NFG


$1.61

$0.64

2002 2003 2004 2005 2006 1Q 2007 Utility 169 179 194 211 204 51 All Other Segments 225 207 220 193 210 48

Fiscal Year

$ Millions

Utility vs. Consolidated NFG

O & M Expense

$394

$386

$414

$404

$414

$99

1999 2000 2001 2002 2003 2004 2005 2006 1Q 2007 Pipeline & Storage 0.51 0.4 0.5 0.37 0.56 0.58 0.71 0.65 0.16 All Other Segments 0.96 1.21 0.32 1.09 1.64 1.43 1.52 0.96 0.48

$1.46

$2.20

$2.01

$2.23

Fiscal Year

Pipeline & Storage vs. Consolidated NFG


$1.61

$0.64

2002 2003 2004 2005 2006 1Q 2007 Pipeline & Storage 61 61 68 65 66 15 All Other Segments 333 325 346 339 348 84

Fiscal Year

$ Millions

Pipeline & Storage vs. Consolidated NFG

O & M Expense

$394

$386

$414

$404

$414

$99

2001 2002 2003 2004 2005 2006 1Q 2007 Energy Marketing -0.04 0.11 0.07 0.07 0.06 0.07 0.01 All Other Segments 0.86 1.35 2.13 1.94 2.17 1.54 0.63

Fiscal Year

Energy Marketing vs. Consolidated NFG


$1.46

$2.20

$2.01

$2.23

$1.61

$0.64

1999 2000 2001 2002 2003 2004 2005 2006 1Q 2007 Exploration & Production 0.09 0.44 -0.4 0.33 -0.39 0.66 0.6 0.24 0.24 All Other Segments 1.38 1.17 1.22 1.13 2.59 1.35 1.63 1.37 0.4

$1.46

$2.20

$2.01

$2.23

Fiscal Year

Exploration & Production vs. Consolidated NFG


$1.61

$0.64

1999 2000 2001 2002 2003 2004 2005 2006 1Q 2007 Timber 0.06 0.08 0.1 0.12 1.38 0.06 0.06 0.07 0.003 All Other Segments 1.41 1.53 0.72 1.34 0.82 1.95 2.17 1.54 0.637

$1.46

$2.20

$2.01

$2.23

Fiscal Year

Timber vs. Consolidated NFG


$1.61

$0.64

NATIONAL FUEL GAS COMPANY
AND SUBSIDIARIES
RECONCILIATION TO REPORTED EARNINGS

Fiscal Year Fiscal Year Fiscal Year Fiscal Year Fiscal Year Fiscal Year 2007

Ended Ended Ended Ended Ended Q1 - 3 Mos Ended

(Diluted Earnings Per Share) September 30, 2002 September 30, 2003 September 30, 2004 September 30, 2005 September 30, 2006 December 31, 2006

Utility

Reported earnings $ 0.62 $ 0.70 $ 0.56 $ 0.46 $ 0.58 $ 0.20

Out-of-period adjustment to symmetical sharing (0.03 )

Pension settlement loss 0.03

Earnings before non-recurring items 0.62 0.70 0.59 0.46 0.55 0.20

Pipeline and Storage

Reported earnings 0.37 0.56 0.58 0.71 0.65 0.16

Discontinuance of hedge accounting (0.02 )

Impairment of Independence Pipeline 0.12


Gain associated with insurance proceeds (0.05 )

Base gas sale (0.03 )


Exploration and Production

Reported earnings 0.33 (0.39 ) 0.66 0.60 0.24 0.24

Income tax adjustments -0.13

Loss on sale of oil and gas assets 0.48

Impairment of oil and gas producing properties 0.36 0.80

Cumulative Effect of Change in Accounting 0.01

Adjustment of loss on sale of oil and gas assets (0.06 )



International

Reported earnings (0.06 ) (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 (0.06 ) (0.02 ) 0.01

Energy Marketing

Reported earnings 0.11 0.07 0.07 0.06 0.07 0.01

Pension settlement loss


Timber

Reported earnings 0.12 1.38 0.06 0.06 0.07

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 0.12 0.07 0.06 0.07

Corporate and All Other

Reported earnings (0.03 ) 0.01 (0.08 ) 0.03


Earnings before non-recurring items (0.03 ) 0.03 (0.08 ) 0.03

Consolidated

Reported earnings 1.46 2.20 2.01

Total non-recurring items from above 0.12 (0.31 ) (0.03 )

Earnings before non-recurring items $ 1.58 $ 1.89 $ 1.98

Consolidated Earnings from Continuing Operations

Reported earnings from continuing operations 1.81 1.61 0.64

Total non-recurring items from above (0.08 ) 0.64 (0.02 )

Earnings from continuing operations before non-recurring items $ 1.73 $ 2.25 $ 0.62

Discontinued Operations

Reported earnings from discontinued operations 0.42

Consolidated

Reported earnings $ 2.23 $ 1.61 $ 0.64

Reconciliation of Segment Net Income from Continuing Operations to
Consolidated Net Income from Continuing Operations
(000)

12 Mos Ended 12/31/06

Utility $ 45,235

Pipeline & Storage $ 51,570

Plus: Discontinuance of hedge accounting 1,900 53,470

Exploration & Production $ 81,705

Plus: Impairment of O&G Prod. Prop. (68,646 )

Income Tax Adjustments 11,202 24,261

Energy Marketing 5,303

Timber 4,456

Corporate & Other 2,467

Consolidated Net Income from Continuing Operations $ 135,192

Reconciliation of Utility Segment O&M Expense to
Consolidated O&M Expense (From Continuing Operations)
($000s)

2002 2003 2004 2005 2006 1Q FY 007

Utility Segment $ 168,633 $ 179,052 $ 190,669 $ 211,019 $ 204,330 $ 50,767

SFAS 88 Pension Settlement $ $ $ 3,374 $ $ $

All Other Segments 225,524 207,218 $ 219,550 $ 193,498 $ 209,396 $ 48,607

Total Corporation $ 394,157 $ 386,270 $ 413,593 $ 404,517 $ 413,726 $ 99,374

Reconciliation of Utility Segment Aged Accounts Receivable to
Consolidated Accounts Receivable Net
($Millions)

at12/31/04 at9/30/05 at12/31/05 at9/30/06 at12/31/06

Utility Aged Accounts Receivable $ 67.3 $ 76.3 $ 79.7 $ 89.7 $ 86.6

Utility Current/Other Accounts Receivable $ 78.7 $ 16.4 $ 143.1 $ 11.8 $ 62.2

POR Program $ $ $ (8.0 ) $ $

Utility Gross Accounts Receivable $ 146.0 $ 92.7 $ 214.8 $ 101.5 $ 148.8

Utility Reserve for Bad Debt $ (15.1 ) $ (25.1 ) $ (31.5 ) $ (29.7 ) $ (34.2 )

Utility Net Accounts Receivable $ 130.9 $ 67.6 $ 183.3 $ 71.8 $ 114.6

All Other Segments Gross Accounts Receivable $ 71.5 $ 89.3 $ 107.7 $ 74.2 $ 79.5

All Other Segments Reserve for Bad Debts $ (4.7 ) $ (1.8 ) $ (1.8 ) $ (1.7 ) $ (1.5 )

All Other Segments Net Accounts Receivable $ 66.8 $ 87.5 $ 105.9 $ 72.5 $ 78.0

Total Corporation Accounts Receivable Net $ 197.7 $ 155.1 $ 289.2 $ 144.3 $ 192.6

Reconciliation of Pipeline & Storage Operating Revenues to
Consolidated Operating Revenues Fiscal 2006
($Millions)

Pipeline Revenues $ 123.4

Storage Revenues $ 66.8

Other Revenues $ 24.2

Total Pipeline & Storage Revenues $ 214.4

All Other Segments $ 2,097.3

Total Corporation $ 2,311.7

Reconciliation of Exploration & Production Operating Revenue to
Consolidated Operating Revenue
($000s)

1Q FY 2007 1Q FY2006

Exploration & Production $ 88,709 $ 82,087

All Other Segments 415,531 628,669

Consolidated Operating Revenue $ 504,240 $ 710,756

Reconciliation of Exploration & Production Net Income to
Consolidated Net Income
($000s)

1Q FY 2007 1Q FY2006

Exploration & Production $ 20,723 $ 17,435

All Other Segments 33,797 39,984

Consolidated Net Income $ 54,520 $ 57,419

Reconciliation of Exploration & Production Depreciation, Depletion and Amortization to
Consolidated Depreciation, Depletion and Amortization (DD&A)
($000s)

1Q FY 2007 1Q FY2006

Exploration & Production DD&A * $ 22,008 $ 21,540

All Other Segments DD&A 20,817 21,506

Consolidated DD&A $ 42,825 $ 43,046

* DD&A and Total LOE cost per Mcf equivalent equals Exploration & Production DD&A and Total LOEcosts, respectively, for the referenced fiscal period, divided by the Total Gas & Oil Production(Mmcfe) in that same fiscal period.

Reconciliation of Exploration & Production Lease Operating Expense (LOE)to
Consolidated O&M
($000s)

1Q FY 2007 1Q FY2006

Exploration & Production LOE $ 13,456 $ 13,539

Exploration & Production Property, Franchise andOther Taxes 1,150 1,208

Exploration & Production Total LOE * $ 14,606 $ 14,747

Exploration & Production LOE $ 13,456 $ 13,539

Exploration & Production Other O&M 8,212 8,272

Exploration & Production Total O&M $ 21,668 $ 21,811

All Other Segments O&M 77,706 81,817

Total Consolidated O&M $ 99,374 $ 103,628

Exploration & Production Property, Franchise andOther Taxes $ 1,150 $ 1,208

All Other Segments Property, Franchise and OtherTaxes 15,962 15,973

Total Consolidated Property Franchise and OtherTaxes $ 17,112 $ 17,181

Reconciliation of Exploration & Production General & Administrative Costs to
Consolidated O&M
($000s)

1Q FY 2007 1Q FY 2006

Exploration & Production General & Administrative * $ 5,571 $ 6,300

Exploration & Production All Other O&M 16,097 15,511

Exporation & Production Total O&M $ 21,668 $ 21,811

All Other Segments O&M 77,706 81,817

Total Consolidated O&M $ 99,374 $ 103,628

* General and Administrative cost per Mcf equivalent equals Exploration & Production General andAdministrative cost, for the referenced fiscal period, divided by the Total Gas & Oil Production(Mmcfe) in that same fiscal period.

Reconciliation of Exploration & Production Segment Capital Expenditures to
Consolidated Capital Expenditures
($000s)

2002 2003 2004 2005 2006 2007E 1Q FY 007

Exploration & Production Capital Expenditures $ 114,602 $ 75,837 $ 77,654 $ 121,200 $ 207,000 $ 210,000-$214,000 $ 46,589

Other 1,250

Total Exploration & Production Capital Expenditures $ 114,602 $ 75,837 $ 77,654 $ 122,450 $ 207,000 $ 210,000-$214,000 $ 46,589

All Other 117,766 76,414 94,687 97,080 95,500 127,000 18,713

Total Corporation $ 232,368 $ 152,251 $ 172,341 $ 219,530 $ 302,500 $ 337,000-$341,000 $ 65,302

Reconciliation of National Fuel Gas Expenditures for Long-lived Assets to
Consolidated Net Cash Used in Investing Activities
(000)

2001 2002 2003 2004 2005 2006 1Q FY 007

Capital Expenditures $ (292,706 ) $ (232,368 ) $ (152,251 ) $ (172,341 ) $ (219,530 ) $ (294,159 ) $ (65,302 )

Investment in Subsidiaries, Net of Cash $ (90,567 ) $ $ (228,814 ) $ $ $ $

Investment in Partnerships $ (1,830 ) $ (536 ) $ (375 ) $ $ $ $ (1,650 )

Expenditures for Long Lived Assets $ (385,103 ) $ (232,904 ) $ (381,440 ) $ (172,341 ) $ (219,530 ) $ (294,159 ) $ (66,952 )

Expenditures for Long Lived Assets $ (385,103 ) $ (232,904 ) $ (381,440 ) $ (172,341 ) $ (219,530 ) $ (294,159 ) $ (66,952 )

Net Proceeds from Sale of Foreign Subsidiary $ $ $ $ $ 111,619 $ $

Net Proceeds from Sale of Timber Properties $ $ $ 186,014 $ $ $ $

Net Proceeds from Sale of Oil and Gas Producing Properties $ 2,069 $ 22,068 $ 78,531 $ 7,162 $ 1,349 $ 13 $ 2,141

Other $ (4,892 ) $ 5,012 $ 12,065 $ 1,974 $ 3,238 $ (3,230 ) $ (316 )

Net Cash Used in Investing Activities $ (387,926 ) $ (205,824 ) $ (104,830 ) $ (163,205 ) $ (103,324 ) $ (297,376 ) $ (65,127 )

Reconciliation of Pipeline & Storage O&M Expense to
Consolidated O&M Expense (From Continuing Operations)
($000s)

2002 2003 2004 2005 2006 1Q FY 007

Pipeline & Storage $ 61,339 $ 61,286 $ 65,071 $ 65,397 $ 66,340 $ 14,903

SFAS 88 PensionSettlement $ $ $ 3,026 $ $ $

All Other Segments 332,818 324,984 $ 345,496 339,120 347,386 84,471

Total Corporation $ 394,157 $ 386,270 $ 413,593 $ 404,517 $ 413,726 $ 99,374

GRAPHIC3l25612al25612z0001.gifGRAPHIC

begin 644 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National Fuel Gas Company 8-K - SEC.gov | HOME Fuel Gas Company (the “Company”) plans to hold...

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Transcript of National Fuel Gas Company 8-K - SEC.gov | HOME Fuel Gas Company (the “Company”) plans to hold...