AGA Financial Forum May 15 17, 2011 Safe Harbor For Forward Looking - - PowerPoint PPT Presentation
AGA Financial Forum May 15 17, 2011 Safe Harbor For Forward Looking - - PowerPoint PPT Presentation
AGA Financial Forum May 15 17, 2011 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
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
- r accomplished.
ddi i h f h f ll i i f h ld l l diff i ll f l f d i h f d l ki fi i l d 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 occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and
- ther investments, 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; 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, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; changes in laws and regulations to p g p p y, g pp p , p g ; g g which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, and exploration and production activities such as hydraulic fracturing; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; significant changes in market dynamics or competitive factors affecting the Company’s ability to retain existing customers or obtain new customers; 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; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in the availability and/or cost of derivative financial instruments; changes in the price differential between similar quantities of natural gas at different geographic locations, and the effect of such changes on the demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of oil or natural gas having different quality, heating value, geographic location or delivery date; changes in the projected profitability of pending or potential projects, investments or t ti i ifi t diff b t th C ’ j t d d t l it l dit d ti d l h i t l ith t t th C ’ transactions; significant differences between the Company’s projected and actual capital expenditures and operating expenses; delays or changes in costs or plans with respect to the Company’s projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; governmental/regulatory actions, initiatives and proceedings, including those involving derivatives, acquisitions, financings, rate cases (which address, among
- ther 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; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; 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; 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 g g p y p p y p p g g g 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. Forward‐looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates
- ther than proved reserves are subject to substantially greater risk of being actually realized Investors are urged to consider closely the disclosure in our Form 10 K available at
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AGA Financial Forum – May 15‐17, 2011
- ther than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10‐K available at
www.nationalfuelgas.com. You can also obtain this form on the SEC’s website at www.sec.gov. For a discussion of the risks set forth above 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, 2010 and the Company’s Forms 10‐Q for the periods ended December 31, 2010 and March 31, 2011. The Company disclaims any
- bligation to update any forward‐looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events.
National Fuel Gas Company
Business Segment Reporting
Publicly Traded
National Fuel Gas Company
y Holding Company NYSE symbol ‐ NFG i
Exploration & Production Pipeline & Storage Utility Energy Marketing
Reporting Segments
Seneca Resources Corporation National Fuel Gas Supply Corporation National Fuel Gas Distribution Corporation National Fuel Resources, Inc.
Operating Subsidiaries
Empire Pipeline, Inc.
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AGA Financial Forum – May 15‐17, 2011
National Fuel Gas Company
Our Businesses
- Utility
- Pipeline & Storage
- Exploration & Production
p
Appalachia, California, Gulf of Mexico
- Energy Marketing
gy g
- Midstream
- Sawmills
- Sawmills
- Landfill Gas
- Gas Fired Generation
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AGA Financial Forum – May 15‐17, 2011
- Gas‐Fired Generation
5
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National Fuel Gas Company
Net Income from Continuing Operations
Excluding Items Impacting Comparability (1)
$266 3
$300
$266.3 $210.5 $219.1
$200
P&S
$33.4 MM 15.4%
$146.6 $98.0 $112.5 $200
$ Millions)
Utility
$62.3 MM 28 6%
E&P
$116.0 MM 53.3%
$61.5 $58 7 $62.5 $54.1 $47.4 $36.7 $100
($ 28.6%
$61.5 $58.7 $62.5 $0
2008 2009 2010
Fiscal Year Ended
$217.8 Million
Twelve Months Ended
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AGA Financial Forum – May 15‐17, 2011
(1) A reconciliation to GAAP Net Income is included at the end of this presentation.
Utility P&S E&P Mktg, Corp & All Other
Twelve Months Ended March 31, 2011
National Fuel Gas Company
Capital Expenditures(1) from Continuing Operations
$1,250
Utility Pipeline & Storage Exploration & Production All Other
$780‐895 $845‐1,010 $1,000
Millions)
$600‐655 $685‐800
$417 $501 $500 $750
nditures ($ M
$166 $100 150 $100 135 $147 $192 $188 $398 $600‐655
$248 $417 $307 $250 $500
Capital Expe
$54 $57 $56 $58 $55‐60 $55‐60 $43 $166 $53
$38
$100‐150 $100‐135
$0
2007 2008 2009 2010 2011 Forecast 2012 Forecast
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AGA Financial Forum – May 15‐17, 2011
Forecast Forecast
Fiscal Year
(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.
National Fuel Gas Company
$1,250
Appalachian Growth ‐ E&P Appalachian Growth ‐ Infrastructure Other Spending
Capital Expenditures(1) – An Appalachian Focus
(2) (3)
$115‐140
$780‐895 $845‐1,010 $1,000
Millions)
$95‐110 $85‐120 $120‐180 $
$417 $501 $500 $750
nditures ($ M
$356 $565‐605 $645‐750 $208 $351 $161 $129
$248 $417 $307 $250 $500
Capital Expe
$39 $66 $139 $208
$0
2007 2008 2009 2010 2011 Forecast 2012 Forecast
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AGA Financial Forum – May 15‐17, 2011
Forecast Forecast
Fiscal Year
(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. (2) Defined as spending related to efforts to drill for, gather, or transport Appalachian sources of natural gas. (3) Any other maintenance spending in the Appalachian region, plus spending in areas outside of the Appalachian region.
National Fuel Gas Company
Short‐Term Debt
2%
Capital Structure
Sh h ld ’ Long‐Term Debt
Long‐Term Debt
Shareholders’ Equity
63% 35% Shareholders’ Equity 63% Debt 37%
$2.866 Billion(1)
at March 31, 2011
Forecasted Capital Structure(2)
t S t b 30 2011
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AGA Financial Forum – May 15‐17, 2011
at September 30, 2011
(1) At March 31, 2011, Comprehensive Shareholders’ Equity, Long‐Term Debt and the Current Portion of Long‐Term Debt totaled $2.866 Billion as presented on the Company’s Balance Sheet, of which $0.899 Billion was Long‐ Term Debt, $0.150 Billion was the Current Portion of Long‐Term Debt and $1.817 Billion was Comprehensive Shareholders’ Equity (2) At September 30, 2011, forecasted Total Capitalization is $3.014 Billion, of which $0.899 Billion is Long‐Term Debt, $0.150 Billion is the Current Portion of Long‐Term Debt, $0.044 Billion is Short‐Term Debt and $1.921 Billion is Comprehensive Shareholders’ Equity
National Fuel Gas Company
Dividend Growth
$1.38
National Fuel has had 108 uninterrupted f di id d d h i d years of dividend payments and has increased its dividend for 40 consecutive years Compound Annual Growth Rate
5.1%
$0.19
%
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AGA Financial Forum – May 15‐17, 2011
Annual Rate at Fiscal Year End
National Fuel Gas Company
Natural Gas Industry ‐ 5‐Year Total Return
175%
i l l G C h
125% 150%
National Fuel Gas Company has consistently generated long‐term total returns that outperform its natural gas industry peers
75% 100% r Total Return
g y p
d Gas Peers bution Peers Peers
25% 50% 5‐Year
NFG OKE SJI OGE EGAS NST EGN CNP UGI Diversified WEC CMS GAS NJR RGCO Gas Distrib XEL ATO SWX CPK WGL DTE NWN PNY LNT STR DGAS EQT TE MGEE Gas/Elec. P AGL LG PCG TEG AVA CHG VVC SRE SUG SCG NI NEW UTL PEG MDU PNM AEE
0% 25%
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‐25%
Source: Edward Jones – Natural Gas Industry Summary: Quarterly Financial and Common Stock Information for the Quarter Ended March 31, 2011
National Fuel Gas Company
Peer Group Comparisons
1‐Year Total Return 3‐Year Total Return 5‐Year Total Return 1 Year Total Return
Peer Group Total Return
National Fuel 71%
Utility Peers 39%
3 Year Total Return
Peer Group Total Return
National Fuel 162%
Utility Peers 56%
5 Year Total Return
Peer Group Total Return
National Fuel 50%
E&P Peers 37% Utility Peers 39% Diversified Peers 2% E&P Peers ‐13% Utility Peers 56% Diversified Peers 56% E&P Peers 48% E&P Peers 37% Diversified Peers 35% Utility Peers 19%
National Fuel’s diversified business model continues to generate long‐term outperformance versus its peer groups by g g p f p g p y limiting downside risk through economically challenging times and capturing upside growth in an expanding market
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All returns are for the period starting at the close on April 1, 20XX and ending March 31, 2011. Calculated utilizing Bloomberg L.P. software and peer group averages calculated using an arithmetic mean Diversified Peers: EGN, EP, EQT, MDU, WMB; Utility Peers: AGL, ATO, CPK, NI, NJR, NWN, SWX, WGL; E&P Peers: BRY, CHK, CNX, COG, CRZO, EOG, PETD, PVA, RRC, SFY, SM, SWN, UNT
Utility Segment
N i l F l G Di ib i C i
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National Fuel Gas Distribution Corporation
Utility
Keys to Continued Success
Provide Stable Earnings
Operate Safe System Control Costs Excellent Customer Service Strong Regulatory Strategy
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Utility
$75
NY PA
Capital Spending
$ $18 0 $54.4 $54.2 $57.5 $56.2 $58.0
$60
Millions)
$16.0 $18.1 $18.3 $18.4 $18.0
$30 $45
pending ($
$38.4 $36.1 $39.2 $37.8 $40.0
$15 $30
Capital Sp
$0 2006 2007 2008 2009 2010
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Fiscal Year
Utility
$250
NY PA
O&M Expense
$63.8 $63.8 $62.1 $204.3 $203.0 $202.7 $191.2 $181.3
$200
Millions)
$ $60.7 $56.3
$100 $150
xpense ($ M
$140.5 $139.2 $140.6 $130.5 $125.0
$50 $100
O&M Ex
$0 2006 2007 2008 2009 2010
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AGA Financial Forum – May 15‐17, 2011
Fiscal Year
Utility
Excellent Customer Service
C S i P f NY G l NY A l(1) PA A l(1) Customer Service Performance Goal Actual(1) Actual(1)
Telephone Response (within 30 seconds) 74.0% 90.0% 89.0% Customer Satisfaction: Residential Commercial 85.1% 86.0% 92.2% 91.4% 88.5% PSC Complaints (per 100,000 Customers) 2.1 0.02 N/A Estimated Meter Reading
Not to Exceed
15.9% 13.1% 9.0% Adjusted Bills
Not to Exceed
1 9% 1.0% 1.2% 1.9% New Service Gas Installations Installed within 10 Days 98.0% 99.9% 99.6% Non‐Emergency Field Appointments Kept 98 0% 99 1% 99 4%
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Non‐Emergency Field Appointments Kept 98.0% 99.1% 99.4%
(1) 12‐months ended March 31, 2011
Utility
Rate Mechanisms
New York Pennsylvania
Revenue Decoupling Conservation Incentive Program
y
Low Income Rates Ch i P /POR Conservation Incentive Program Merchant Function Charge Low Income Rates Choice Program/POR Merchant Function Charge Pending: 90/10 Sharing Weather Normalization Pending: Distribution System Improvement Charge (DSIC) Choice Program Revenue Decoupling
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Utility
20.0 NY PA
Return on Equity (1)
14.0 13.2 14.7 15.0
uity (%)
10.3 9.1 10.9 9.8 10.6 11.8 10.0
urn on Equ
6.3 5.0
Retu
0.0 2006 2007 2008 2009 2010
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(1) Calculated using Average Total Comprehensive Shareholder Equity.
2006 2007 2008 2009 2010
Fiscal Year
Utility
Diluted Earnings per Share
(Before Items Impacting Comparability)
$1.00 $0.73 $0.73 $0.76 $0.75
Share
$0.55(1) $0.60 $0.50
arnings per
$0.25
Diluted Ea
$0.00 2006 2007 2008 2009 2010
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(1) Excludes out‐of‐period adjustment to symmetrical sharing of $0.03; Including this adjustment, GAAP earnings would be $0.58.
2006 2007 2008 2009 2010
Fiscal Year
Utility
2011
Provide Stable Earnings
Operate Safe System Control Costs Excellent Customer Service Strong Regulatory Strategy
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Pipeline & Storage / Midstream
National Fuel Gas Supply Corporation Empire Pipeline, Inc.
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National Fuel Gas Midstream Corporation
PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES
NORTHERN ACCESS EXPANSION LAMONT COMPRESSOR LAMONT COMPRESSOR TIOGA COUNTY EXTENSION EXPANSION CENTRAL TIOGA COUNTY COMPRESSOR STATION PHASE I & II COVINGTON G G COMPRESSOR STATION PHASE I & II EXTENSION GATHERING SYSTEM TROUT RUN GATHERING SYSTEM LINE “N” EXPANSION LINE “N” WEST TO EAST OVERBECK TO LEIDY EXPANSION
Seneca Drilling Activity EOG JV Drilling Activity
LINE “N” 2012 EXPANSION 25
W2E Overbeck to Leidy Northern Access Expansion Expansion Projects
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Exploration & Production
S R C i
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Seneca Resources Corporation
Exploration & Production
600 cf)
Natural Gas
Fiscal Year End Proved Reserves(1)
East – Appalachia R 333 B f (48%)
226 249 428 200 400 ved Reserves (B
Reserves: 333 Bcfe (48%)
2008 2009 2010
Prov At September 30 46.2 46.6 45.2 40 60 es (MMbbl)
Oil West – California R 333 B f (47%)
20 Proved Reserve
Reserves: 333 Bcfe (47%) (55.5 MMBoe) Gulf of Mexico Reserves: 34 Bcfe (5%)
T t l P d R 700 B f
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AGA Financial Forum – May 15‐17, 2011
2008 2009 2010
At September 30
(1) At September 30, 2010
Total Proved Reserves: 700 Bcfe
Exploration & Production
Historical Daily Production
250
West Upper Devonian Gulf Marcellus
200
mcfe/d) West Upper Devonian Gulf Marcellus
100 150
duction (Mm
50 100
Daily Prod
‐
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AGA Financial Forum – May 15‐17, 2011
Exploration & Production
Capital Expenditures by Region
$1,000 West Upper Devonian Gulf of Mexico Marcellus
$600 655 $685‐800
$750
Millions) $398 $600‐655
$500
nditures ($ M
$332 $560‐600 $640‐740
$192 $188 $398
$250
Capital Expen
$63 $31(1) $28 $35‐45 $40‐50
$61 $68 $64 $71 $0
Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Fiscal 2012 C
(1)
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Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Forecast Fiscal 2012 Forecast
(1) Does not include the $34.9MM acquisition of Ivanhoe’s US‐based assets in California, as this was accounted for as an investment in subsidiaries on the Statement of Cash Flows, and was not included in Capital Expenditures.
Exploration & Production
Annual Production by Region
83‐100
100 West Upper Devonian Gulf of Mexico Marcellus
66‐71
80
fe) Marcellus production in Fiscal 2012 could equal the entire company
7.2 35‐37 58‐71
40.8 42.5 49.7
60
duction (Bcf p y production in Fiscal 2011
7.9 8.7 9.3 7‐9 6‐8 14.1 13.7 13.4 5 20 40
Prod
18.8 20.1 19.8 19‐20 19‐21
Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Fiscal 2012
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Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Forecast Fiscal 2012 Forecast
Exploration & Production
C lif i
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California
Seneca’s California Properties
South Lost Hills
~1,830 BOEPD
North Lost Hills
~1,235 BOEPD Tulare & Etchegoin Formation Monterey Shale Primary 216 Active Wells Tulare & Etchegoin Formation Primary & Steamflood 181 Active Wells
North Midway Sunset North Midway Sunset
~4,050 BOEPD Potter & Tulare Formation Steamflood 703 Active Wells
Sespe
~990 BOEPD Sespe Formation Primary
South Midway Sunset
~680 BOEPD Primary 193 Active Wells Antelope Formation Steamflood 81 Active Wells
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As of March 27, 2011
California
Average Daily Production
10,000
- Modest capital spending
to maintain production
- Pursue additional bolt‐on
9,500 0,000
acquisitions
- 2011 Plans:
CapEx ‐ $40 MM
8,500 9,000
OE/Day
p $ 50 Development wells Two 5‐acre in‐fill wells at Sespe
7,500 8,000
B
7,000
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AGA Financial Forum – May 15‐17, 2011
California
Fiscal Year 2011 Sespe Field Development Plans
- d ll
f First drilling for Seneca at Sespe since 1991
- Will drill six wells during this fiscal year
Wells to be drilled at 10‐acre spacing: 4 wells Test wells to be drilled at 5‐acre spacing: 2 wells p g If successful, 5‐acre down‐spacing could add substantial new reserves and resource potential p
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Exploration & Production
E Di i i
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East Division
East Division
Average Daily Production
150 100 125 Mcfe/Day)
Upper Devonian Marcellus
75 100 roduction (MM
Rapid growth in the East Division as Marcellus is ramping up
25 50 erage Daily Pr
ramping up
Ave
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Marcellus Shale
Seneca’s Pennsylvania Acreage
Seneca Resource Acreage Position 745,000 Net Acres in the heart of the PA Marcellus fairway Risked Resource Potential: 8‐15 TCFE 80% Fee – Seneca owns the minerals No lease expiration 94% Average NRI
SRC L A SRC Fee Acreage
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AGA Financial Forum – May 15‐17, 2011
94% Average NRI
SRC Lease Acreage
Marcellus Shale
Seneca’s Development Areas
Eastern Development Area (Mostly Leased) Western Development Area Western Development Area (Mostly Fee and HBP)
SRC L A SRC Fee Acreage
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AGA Financial Forum – May 15‐17, 2011
SRC Lease Acreage
Marcellus Shale
Eastern Development Area
Covington Area – Full Development DCNR Block 001 43 Wells Drilled; 24 Producing (3 Shut‐In) Gross Prod: (As of 5/10/11): 90 MMCFD 1st Marcellus Well IP: 4.5 MMCFD 1st Geneseo Test IP: ~3 MMCFD DCNR Block 007 1st Well IP: 2.1 MMCFD DCNR Block 595 – Full Development 4 Wells Drilled; 4 Producing G P d (A f 5/10/11) 12 MMCFD
Tioga/Lycoming/Potter 55,000 Acres Potential: 2 Tcf
DCNR Block 100 1st W ll IP 15 8 MMCFD SRC L A SRC Fee Acreage Gross Prod: (As of 5/10/11): 12 MMCFD
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AGA Financial Forum – May 15‐17, 2011
1st Well IP: 15.8 MMCFD 2011: 6 Wells Planned First Production: Fall 2011 SRC Lease Acreage
Marcellus Shale
Longer Lateral EDA Wells Outpacing 6 Bcf Typecurve
8,000
Average EDA Production per Well 6 B f T
(1)
6,000
6 Bcf Typecurve
4,000
Rate (Mcf/d)
2,000
Gas
30 60 90 120 150 180 210 240 270 300 330 360 40
AGA Financial Forum – May 15‐17, 2011
30 60 90 120 150 180 210 240 270 300 330 360
Days
(1) Chart data represents horizontal well production from wells with lateral lengths greater than 3,500 feet
Marcellus Shale
Western Development Area ‐ Activity
SRC Lease Acreage SRC Fee Acreage
- Approx. Outline of JV Acreage
200 000 Gross Acres EOG Contributed JV Acreage SRC Contributed JV Acreage 200,000 Gross Acres Seneca 50% W.I. (Avg. 58% NRI) Owl’s Nest Area Owl s Nest Area Seneca Operated 2 New Wells Completed IP Rates: 4.0 – 4.5 MMCFD Beechwood Area Seneca Operated 3 Wells Drilled Seneca Operated EOG O d Punxy Area – Full Development EOG Operated 39 Wells Drilled; 25 Producing Gross Production (As of 5/10/11): 45 MMCFD
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AGA Financial Forum – May 15‐17, 2011
EOG Operated ( / / ) 2011: 30+ Wells Planned
Marcellus Shale
Target Zone Example
Important to Find Ideal Target
Must account for the variable rock quality and geomechanical profile Marcellus Interval Major factor in quality of Fracture Stimulation
Optimal Target Zone
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AGA Financial Forum – May 15‐17, 2011
Zone
Marcellus Shale
150 EOG JV Eastern Development Area Western Development Area
Marcellus Net Production
100 125 n (MMcfe) 75 00 y Net Production
Seneca Operated
25 50 Marcellus Daily ‐ 25
EOG JV
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Marcellus Shale
Centralized Water System
Recovering water discharged from an b d d l i hi h d l abandoned coal mine which was adversely impacting a local trout stream Authorized by SRBC to withdraw approximately 500,000 gallons per day of mine discharge Water pipeline system supplies frac water for Seneca in Tioga County (90 wells) Can supply water for 3 fracs per month Can supply water for 3 fracs per month System Cost: ~$3.7 Million Cost Savings: ~$120,000 per well
Pay Out: 31 Wells Pay Out: 31 Wells
Other Benefits:
Improved stream quality Substantial reduction of water truck activity
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AGA Financial Forum – May 15‐17, 2011
activity No need to withdraw water elsewhere
Utica Shale
Seneca Seneca Acreage
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Source rock maturation status based on combined CAI to Ro regression equation. (Trenton‐Black River Research Consortium, 2006)
Seneca Resources
Evaluation of JV Opportunities
- Seneca’s Marcellus joint venture goals:
- Ramp up development faster than current growth plans
- Bring forward the earnings stream, where a minority‐interest partner pays a
significant portion of the early drilling costs enhancing shareholder value significant portion of the early drilling costs, enhancing shareholder value
- Continue operating across most of its acreage position
- Seneca continues to have active and ongoing discussions with potential joint
- Seneca continues to have active and ongoing discussions with potential joint
venture partners
- Seneca has received serious offers
- Anticipate reaching a conclusion by the end of June
- Seneca will only consider joint venture opportunities that management
believes will enhance shareholder value
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AGA Financial Forum – May 15‐17, 2011
believes will enhance shareholder value
National Fuel Gas Company
Key Takeaways
High‐Quality Marcellus Acreage Position g Q y g
745,000 net acres with a resource potential of 8‐15 Tcfe Fee ownership results in superior economics Rapid Growth: 0 – 120 MMCFD in 18 months
Balanced Business Model
Regulated segments support dividend and are not sensitive to commodity prices Sizable oil production provides earnings stability
S Fi i l P i i Strong Financial Position
Simple balance sheet Well capitalized Si ifi t i t ll t d h fl
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Significant internally generated cash flows
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AGA Financial Forum – May 15‐17, 2011
National Fuel Gas Company
Corporate & Financial Highlights
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Corporate & Financial Highlights
National Fuel Gas Company
Fiscal Year 2011 Earnings Guidance – Key Drivers(1)
Exploration & Production
P d i ↑ 38%
FY 2011
- Production ‐ ↑ 38%
- DD&A: $2.17 Area per Mcfe
- LOE: $0.95 to $1.05 per Mcfe
- G&A: $41 ‐ $44 Million
FY 2011 GAAP EPS
$2.83 to
Pipeline & Storage
- Operating Expense: ↑ 3% to 5%
- Transportation Revenue: ↓ $7.5 Million
- Project Development Costs (O&M): $7 Million
FY2010 Operating Results +
=
to $2.98
Utility
- Operating Expense: ↑ 3% to 5%
- PA Normal Weather
$2.65(2)
Corporate & All Other
- Sale of Horizon Power, Inc. Investments: $0.38/Sh
- Midstream Earnings per Share: $0.05 to $0.10
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AGA Financial Forum – May 15‐17, 2011
NYMEX Pricing: Gas: $4.00/MMBtu ⏐ Oil: $80.00/Bbl
(1) The Earnings Guidance is current as of May 5, 2011 (2) Excludes gain on disposal of discontinued operations of $0.07 and earnings from discontinued operations of $0.01; including these items GAAP earnings were $2.73.
National Fuel Gas Company
Seneca Oil and Gas Hedge Positions
Natural Gas Volume Average Volume Average Natural Gas Swaps Volume (Bcf) Average Hedge Price
Fiscal 2011 14.6 $6.05 / Mcf Fiscal 2012 35 0 $5 89 / Mcf
Oil Swaps Volume (MMBbl) Average Hedge Price
Fiscal 2011 0.9 $70.93 / Bbl Fiscal 2012 1 6 $77 03 / Bbl Fiscal 2012 35.0 $5.89 / Mcf Fiscal 2013 23.9 $5.67 / Mcf Fiscal 2014 4.6 $5.89 / Mcf Fiscal 2012 1.6 $77.03 / Bbl Fiscal 2013 0.9 $86.21 / Bbl Fiscal 2014 0.2 $94.90 / Bbl
For fiscal year 2011, Seneca has hedged
NYMEX Strip Prices
(at 05/11/11)
Natural Gas Oil
Fi l 2011(1) $4 11 $92 97
Seneca has hedged 58% of its remaining forecasted production
Fiscal 2011(1) $4.11 $92.97 Fiscal 2012 $4.72 $99.15 Fiscal 2013 $5.16 $96.79
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AGA Financial Forum – May 15‐17, 2011
Fiscal 2014 $5.52 $94.93
(1) The NYMEX strip prices for fiscal year 2011 include the settlement prices for the October 2010 through May 2011 contracts.
Pipeline & Storage / Midstream
National Fuel Gas Supply Corporation Empire Pipeline, Inc.
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AGA Financial Forum – May 15‐17, 2011
National Fuel Gas Midstream Corporation
PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES
NORTHERN ACCESS EXPANSION LAMONT COMPRESSOR LAMONT COMPRESSOR TIOGA COUNTY EXTENSION EXPANSION CENTRAL TIOGA COUNTY COMPRESSOR STATION PHASE I & II COVINGTON G G COMPRESSOR STATION PHASE I & II EXTENSION GATHERING SYSTEM TROUT RUN GATHERING SYSTEM LINE “N” EXPANSION LINE “N” WEST TO EAST OVERBECK TO LEIDY EXPANSION
Seneca Drilling Activity EOG JV Drilling Activity
LINE “N” 2012 EXPANSION 54
W2E Overbeck to Leidy Northern Access Expansion Expansion Projects
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AGA Financial Forum – May 15‐17, 2011
Pipeline & Storage/Midstream
Expansion Initiatives
Project Name Capacity (Dth/D) Est. CapEx In‐Service Date Market Status
Covington Gathering System 145,000 $16 MM 11/17/09 Fully Subscribed Completed – Flowing into TGP 300 Line Lamont Compressor Station 40,000 $6 MM 6/15/10 Fully Subscribed Completed – Flowing into TGP 300 Line Lamont Phase II Project 50 000 $7 6 MM ~ 07/2011 Fully Subscribed Construction began March 2011 Lamont Phase II Project 50,000 $7.6 MM ~ 07/2011 Fully Subscribed Construction began March 2011 Line “N” Expansion 160,000 $20 MM ~ 09/2011 Fully Subscribed Construction began February 2011 Tioga County Extension 350,000 $49 MM ~ 09/2011 Fully Subscribed Certificate expected in May Trout Run Gathering System 300,000 $35 MM Fall 2011 85% Subscribed Preliminary work has begun Northern Access Expansion 320,000 $62 MM ~11/2012 Fully Subscribed Certificate filed in March 2011 Line “N” 2012 Expansion 150,000 $30 MM ~ 11/2012 Fully Subscribed Planned FERC 7(c) filing – June 2011 p y ( ) g West to East ~425,000 $260 MM Late 2013 29% Subscribed Pursuing post‐Open Season requests for remaining 300,000 Dth/day Central Tioga County Extension 365,000 Up to $135 MM 2013/ 2014 Open Season Closed Developing facility design and cost estimate
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AGA Financial Forum – May 15‐17, 2011
Extension $135 MM 2014 Closed estimate
Pipeline & Storage
Challenges & Opportunities
Challenges Opportunities
NFGSC Contract Turnbacks
Supply has received capacity turnbacks on expiring contracts
Expansion Projects
Both Supply and Empire have significant pipeline expansion turnbacks on expiring contracts, decreasing future revenue by:
FY11: ~$7.5 Million FY12: ~$4‐6 Million
significant pipeline expansion projects planned to transport gas
- ut of the Marcellus. Yearly
revenue from these expansion
Empire Unsold Capacity
~100 000 Dth/d of capacity projects is forecasted to total:
FY11: ~$0.2 Million FY12: ~$32.0 Million
100,000 Dth/d of capacity remains unsold after the construction of the Empire Connector in 2008
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AGA Financial Forum – May 15‐17, 2011
Midstream Corporation
Trout Run Gathering System – Lycoming County
Capacity: 300,000 Dth/d Will Interconnect with Transco Will Interconnect with Transco Pipelines in Lycoming County Seneca Resources will be the anchor shipper Estimated In‐Service: Fall 2011
Interstate Pipeline
Transco
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AGA Financial Forum – May 15‐17, 2011
Gathering System
Exploration & Production
S R C i
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Seneca Resources Corporation
Marcellus Shale
Pennsylvania Acreage Holdings
SRC Lease Acreage SRC Fee Acreage SRC Contributed JV Acreage
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AGA Financial Forum – May 15‐17, 2011
EOG Contributed JV Acreage
Marcellus Shale
Decline Curve – 6.0 BCF Estimated Ultimate Recovery (EUR)
8,000
Category Type Curve Parameters
Initial Rate 7 250 MCF/D 6,000 7,000
MCF/D
Initial Rate 7,250 MCF/D Average first year decline 72% Final decline 6% Hyperbolic Coefficient 1.4 4,000 5,000
Mcf/d
yp Abandonment rate 60 MCF/D Average first month rate 6,670 MCF/D Average first year rate 3,560 MCF/D 2,000 3,000 EUR 6.0 BCF 1,000
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AGA Financial Forum – May 15‐17, 2011
Marcellus Shale
Pre‐Tax IRR Comparison at NYMEX of $4.00/MMBtu
Net Net Well Costs ($ Millions)
Eastern Development Area
Description EUR Net Working Interest Net Revenue Interest Well Costs ($ Millions) $6.0 $6.4
Seneca – EDA Well 8 Bcf 100% 85% 73% 63% Seneca – EDA Well 6 Bcf 100% 85% 40% 34%
N N
Western Development Area
Description EUR Net Working Interest Net Revenue Interest Well Costs ($ Millions) $5.0 $6.0
Seneca – EOG JV Well 4 Bcf 50% 60% 44% 29% Seneca – WDA Well 4 Bcf 100% 100% 28% 19% Seneca is in active development within the Eastern Development Area. It is currently testing various well and completion designs in its Western Development Area and
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AGA Financial Forum – May 15‐17, 2011
testing various well and completion designs in its Western Development Area and expects to see results continue to improve over time.
Marcellus Shale
150
EOG JV Horizontal Wells Seneca Horizontal Wells
Gross Horizontal Wells Drilled per Year
115‐140 125 150 Marcellus Horizontal Rig Count
Current Rig Count: Seneca : 4 Rigs EOG : 2 Rigs 80‐95
85‐110 75 100
ells Drilled
g Additional Seneca Rigs Scheduled: 5th Rig: Summer 2011 6th Rig: Fall 2011 29 60‐75
58 50
Gross We
11 29 25‐35 35‐45
6 14 25
Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Fiscal 2012
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AGA Financial Forum – May 15‐17, 2011
Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Forecast Fiscal 2012 Forecast
Marcellus Shale
Transportation Capacity
- Eastern Development Area
Covington Gathering System: 150,000 Dth/d into TGP 300 Covington Gathering System: 150,000 Dth/d into TGP 300 Provides capacity for DCNR Tract 595 and Covington in Tioga county Firm sales of 100,000 Dth/d thru October 31, 2011 Trout Run Gathering System: 200 000 – 250 000 Dth/d into Transco (In Service: Fall 2011) Trout Run Gathering System: 200,000 – 250,000 Dth/d into Transco (In‐Service: Fall 2011) Provides capacity for DCNR Tract 100 in Lycoming county Tennessee Gas Pipeline: 50,000 Dth/d of firm capacity to Niagara P id it f C i t DCNR T t 595 d DCNR T t 007 Provides capacity for Covington, DCNR Tract 595 and DCNR Tract 007
- Western Development Area
National Fuel Gas Supply Corporation: ~100,000 Dth/d through 2013 (As of November 2011 ) Provides capacity to acreage in Elk, Cameron, McKean and Potter counties Supply’s West to East project will create additional capacity in 2013 and beyond
- Seneca continues to pursue long‐term firm capacity and sales contracts on many of the
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AGA Financial Forum – May 15‐17, 2011
p g p y y interstate pipeline networks running throughout the Marcellus region
National Fuel Gas Company
bl l 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
- f the Company’s ongoing operations.
The Company’s management uses these non GAAP financial measures for the same purpose and for planning 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
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AGA Financial Forum – May 15‐17, 2011
with GAAP.
Reconciliation of GAAP Net Income to Income From Continuing Operations Excluding Items Impacting Comparability Excluding Items Impacting Comparability ($ Thousands) 12 Mos. Ended FY 2008 FY 2009 FY 2010 3/31/2011 GAAP Net Income E&P Segment GAAP Net Income 146,612 $ (10,238) $ 112,531 $ 116,040 $ P&S Segment GAAP Net Income 54,148 47,358 36,703 33,434 Utility Segment GAAP Net Income 61,472 58,664 62,473 62,258 Marketing Segment GAAP Net Income 5,889 7,166 8,816 8,985 Corporate & All Other GAAP Net Income 607 (2,242) 5,390 34,424 Total GAAP Net Income 268,728 $ 100,708 $ 225,913 $ 255,141 $ Discontinued Operations (Income) Loss from Operations, Net of Tax (Corporate & All Other) (1,821) $ 2,776 $ (470) $ 358 $ Gain on Disposal Net of Tax (Corporate & All Other) (6 310) (6 310) Gain on Disposal, Net of Tax (Corporate & All Other)
- (6,310)
(6,310) (Income) Loss from Discontinued Operations, Net of Tax (1,821) $ 2,776 $ (6,780) $ (5,952) $ Items Impacting Comparability Gain on sale of turbine (Corporate & All Other) (586) $
- $
- $
- $
Gain on life insurance policies (Corporate & All Other)
- (2,312)
- Gain on sale of unconsolidated subsidiaries (Corporate & All Other)
- (31,418)
( p ) ( , ) Impairment of investment partnership (Corporate & All Other)
- 1,085
- Impairment of oil and gas properties (E&P)
- 108,207
- Total Items Impacting Comparability
(586) $ 106,980 $
- $
(31,418) $ Income from Continuing Operations excluding Items Impacting Comparability E&P Segment Operating Income 146,612 $ 97,969 $ 112,531 $ 116,040 $ P&S S O i I 4 148 4 3 8 36 03 33 434 P&S Segment Operating Income 54,148 47,358 36,703 33,434 Utility Segment Operating Income 61,472 58,664 62,473 62,258 Marketing Segment Operating Income 5,889 7,166 8,816 8,985 Corporate & All Other Operating Income (1,800) (693) (1,390) (2,946) Total Income from Continuing Operations excluding Items Impacting Comparability 266,321 $ 210,464 $ 219,133 $ 217,771 $ AGA Financial Forum – May 15‐17, 2011
Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures Consolidated Capital Expenditures ($ Thousands) FY 2011 FY 2012 FY 2007 FY 2008 FY 2009 FY 2010 Forecast Forecast Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 146,687 $ 192,187 $ 188,290 $ 398,174 $ $600,000-655,000 $685,000-800,000 Pipeline & Storage Capital Expenditures 43,226 165,520 52,504 37,894 $100,000-150,000 $100,000-135,000 Utility Capital Expenditures 54,185 57,457 56,178 57,973 $55,000-60,000 $55,000-60,000 Marketing, Corporate & All Other Capital Expenditures 3,414 1,614 9,829 7,311 $25,000-30,000 $5,000-15,000 Total Capital Expenditures from Continuing Operations 247,512 $ 416,778 $ 306,801 $ 501,352 $ $780,000-895,000 $845,000-1,010,000 Capital Expenditures from Discountinued Operations Exploration & Production Capital Expenditures 29,129 $
- $
- $
- $
- $
- $
All Other Capital Expenditures 87 131 216 150 All Other Capital Expenditures 87 131 216 150 Total Capital Expenditures from Discontinued Operations 29,216 $ 131 $ 216 $ 150 $
- $
- $
Plus (Minus) Accrued Capital Expenditures Exploration & Production FY 2010 Accrued Capital Expenditures
- $
- $
- $
(55,546) $
- $
- $
Exploration & Production FY 2009 Accrued Capital Expenditures
- (9,093)
9,093
- Pipeline & Storage FY 2008 Accrued Capital Expenditures
- (16,768)
16,768
- All Other FY 2009 Accrued Capital Expenditures
- (715)
715
- Total Accrued Capital Expenditures
- $
(16,768) $ 6,960 $ (45,738) $
- $
- $
Elimintations
- $
(2,407) $ (344) $
- $
- $
- $
Total Capital Expenditures per Statement of Cash Flows 276,728 $ 397,734 $ 313,633 $ 455,764 $ $780,000-895,000 $845,000-1,010,000
AGA Financial Forum – May 15‐17, 2011
R ili ti f A l hi G th C it l E dit t Reconciliation of Appalachian Growth Capital Expenditures to Consolidated Capital Expenditures ($ Millions) FY 2011 FY 2012 FY 2007 FY 2008 FY 2009 FY 2010 Forecast Forecast Appalachian Growth Capital Expenditures from Continuing Operations1 Exploration & Production Capital Expenditures - East Division 39.1 $ 65.8 $ 138.6 $ 355.7 $ $565-605 $645-750 p p p Pipeline & Storage Appalachian Expansion Capital Expenditures
- 10.3
$70-80 $80-105 Midstream Capital Expenditures
- 7.4
6.5 $25-30 $5-15 Total Appalachian Capital Expenditures from Continuing Operations 39.1 $ 65.8 $ 146.0 $ 372.5 $ $660-715 $730-870 Other Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 107.6 $ 126.4 $ 49.7 $ 42.5 $ $35-50 $40-50 Pipeline & Storage Capital Expenditures 43 2 165 5 52 5 27 6 $30-70 $20-30 Pipeline & Storage Capital Expenditures 43.2 165.5 52.5 27.6 $30-70 $20-30 Utility Capital Expenditures 54.2 57.5 56.2 58.0 $55-60 $55-60 Marketing, Corporate & All Other Capital Expenditures 3.4 1.6 2.3 0.8
- $
- $
Total Other Capital Expenditures from Continuing Operations 208.4 $ 351.0 $ 160.7 $ 128.9 $ $120-180 $115-140 Capital Expenditures from Discountinued Operations Exploration & Production Capital Expenditures 29.1 $
- $
- $
- $
- $
- $
All Oth C it l E dit 0 1 0 1 0 2 0 1 All Other Capital Expenditures 0.1 0.1 0.2 0.1 Total Capital Expenditures from Discontinued Operations 29.2 $ 0.1 $ 0.2 $ 0.1 $
- $
- $
Plus (Minus) Accrued Capital Expenditures Exploration & Production FY 2010 Accrued Capital Expenditures
- $
- $
- $
(55.5) $
- $
- $
Exploration & Production FY 2009 Accrued Capital Expenditures
- (9.1)
9.1
- Pipeline & Storage Accrued Capital Expenditures
- (16.8)
16.8
- All Other Accrued Capital Expenditures
- (0.7)
0.7
- Total Accrued Capital Expenditures
- $
(16.8) $ 7.0 $ (45.7) $
- $
- $
Eliminations
- (2.4)
(0.3)
- Total Capital Expenditures per Statement of Cash Flows
276.7 $ 397.7 $ 313.6 $ 455.8 $ $780-895 $845-1,010 (1) Defined as spending related to efforts to drill for gather or transport Appalachian sources of natural gas
AGA Financial Forum – May 15‐17, 2011
(1) Defined as spending related to efforts to drill for, gather, or transport Appalachian sources of natural gas.