Fiscal 2010 Y Year End Analyst Day E d A l t D November 9, 2010 - - PowerPoint PPT Presentation
Fiscal 2010 Y Year End Analyst Day E d A l t D November 9, 2010 - - PowerPoint PPT Presentation
Fiscal 2010 Y Year End Analyst Day E d A l t D November 9, 2010 Safe Harbor For Forward Looking Statements This presentation may contain forward looking statements as defined by the Private Securities Litigation Reform Act of 1995,
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.
I dditi t th f t th f ll i i t t f t th t ld t l lt t diff t i ll f lt f d t i th f d l ki t t t 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 their effect on the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments; occurrences affecting the Company’s ability to obtain financing under credit lines or other credit facilities or through the issuance of commercial paper, other short‐term notes or debt or equity securities, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from terrorist activities, acts of war, major accidents, fires, hurricanes, other severe weather, pest infestation or other natural disasters; changes in demographic patterns and weather conditions; changes in the availability and/or price of natural gas or oil and the effect of such changes on the accounting treatment of derivative financial instruments or the valuation of the Company’s natural gas and oil reserves; impairments under the SEC’s full cost ceiling test for l d il i f il d i f ff i h C ’ bili f ll id if d ill f d d i ll i bl l d natural gas and oil reserves; uncertainty of oil and gas reserve estimates; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and
- il 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, and the need to obtain governmental approvals and permits and comply with environmental laws and regulations; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in the availability and/or price of derivative financial instruments; changes in the price differentials between oil having different quality and/or different geographic locations, or changes in the price differentials between natural gas having different heating values and/or different geographic locations; changes in laws and regulations to 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; the nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits; significant differences between the Company’s projected and actual capital expenditures and operating expenses, and unanticipated project f f ff / delays or changes in project costs or plans; inability to obtain new customers or retain existing ones; significant changes in competitive factors affecting the Company; governmental/regulatory actions, initiatives and proceedings, including those involving derivatives, 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; 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 accounting principles or the application of such principles to the Company; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post‐retirement benefits; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. For a discussion of these risks and other factors that could cause actual results to differ materially from results referred to in the forward‐looking statements, see “Risk Factors” in the Company’s Form 10‐K for the fiscal year ended September 30, 2009 and the Company’s Forms 10‐Q for the quarters ended December 31, 2009, March 31, 2010 and June 30, 2010. The Company disclaims any obligation to update any forward‐looking statements to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events. The Securities and Exchange Commission (the “SEC”) currently permits the Company, in its filings with the SEC, to disclose only proved reserves that the Company has demonstrated by actual
2
Analyst Day – November 9, 2010
production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The Company uses the terms “probable,” “possible,” “resource potential” and other descriptions of volumes of reserves or resources potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines would prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and, accordingly, are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10‐K and Forms 10‐Q available at www.nationalfuelgas.com. You can also obtain these forms on the SEC’s website at www.sec.gov.
National Fuel Gas Company
Business Segment Reporting
Publicly Traded
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.
3
Analyst Day – November 9, 2010
National Fuel Gas Company
Our Businesses
- Utility
- Pipeline & Storage
- Exploration & Production
p
Appalachia, California, Gulf of Mexico
- Energy Marketing
gy g
- Midstream
- Timber
- Timber
- Landfill Gas
- Gas Fired Generation
4
Analyst Day – November 9, 2010
- Gas‐Fired Generation
National Fuel Gas Company
Net Plant by Segment
$5,000 Utility P&S E&P Mktg, Corp & All Other
$3,154 $3,133 $3,450 $3,906
$4,000
)
$1,002 $983 $1,096 $1,042 $1,339 $1,656
$2,878 $2,878 $ , $3,133
$2,000 $3,000
($ Millions)
$1 084 $1 099 $1 126 $1 144 $1,165 $1,179 $674 $682 $827 $839 $858 $952 $1,000 $2,000 $1,084 $1,099 $1,126 $1,144 $ , $0
2006 2007 2008 2009 2010 2011 Forecast
5
Analyst Day – November 9, 2010
Forecast
At Fiscal Year End
National Fuel Gas Company
Net Income from Continuing Operations
Excluding Items Impacting Comparability (1)
$266 3
$300
$192.2 $266.3 $210.5
$200
P&S
$36.7 MM 16.7%
$74.9 $146.6 $98.0
$
$200
$ Millions)
Utility
$62.5 MM 28 5%
E&P
$112.5 MM 51.4%
$50 9 $61.5 $58 7 $49.7 $54.1 $47.4 $100
($ 28.5%
$50.9 $61.5 $58.7 $0
2007 2008 2009
Fiscal Year Ended
$219.1 Million
Fiscal Year Ended
6
Analyst Day – November 9, 2010
(1) A reconciliation to GAAP Net Income is included at the end of this presentation.
Utility P&S E&P Mktg, Corp & All Other
Fiscal Year Ended September 30, 2010
National Fuel Gas Company
A Balanced Business Model
Net Income from Continuing Operations(1) – Excluding Items Impacting Comparability
$300
43%
$192 2 $266.3 $210.5
$
52% 43% 50%
$192.2
$200
Millions)
Unregulated
55%
Regulated
45%
48% 57% 50%
$100
($ M
55%
$0
2007 2008 2009
Fiscal Year Ended
$219.1 Million
Fiscal Year Ended
7
Analyst Day – November 9, 2010
(1) A reconciliation to GAAP Net Income is included at the end of this presentation.
Fiscal Year Ended
Unregulated Regulated
Fiscal Year Ended September 30, 2010
National Fuel Gas Company
Oil G
Seneca Resources Corporation – Oil and Gas Revenues
$453 $374 $426
$400 $500
Millions)
Oil Gas
46% 45% 41% 43% $311 $374
$300 $400
evenues ($ M 54% 55% 59% 57% 46%
$100 $200
il and Gas Re 54%
$0 $100
2007 2008 2009 2010 Total Oi
8
Analyst Day – November 9, 2010
Fiscal Year Ended
National Fuel Gas Company
Peer Group Comparisons
1‐Year Total Return 3‐Year Total Return 5‐Year Total Return
Peer Group Total Return Utility Peers 22%
National Fuel 19%
1 Year Total Return
Peer Group Total Return
National Fuel 20%
Utility Peers 19%
3 Year Total Return
Peer Group Total Return
National Fuel 74%
Utility Peers 34%
5 Year Total Return
National Fuel 19%
Diversified Peers 9% E&P Peers 8% Utility Peers 19% E&P Peers ‐10% Diversified Peers ‐27% Utility Peers 34% E&P Peers 4% Diversified Peers ‐3%
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
9
Analyst Day – November 9, 2010
All returns are for the period starting October 1, 20XX and ending September 30, 2010. 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: ATLS, BRY, CHK, CNX, COG, CRZO, EOG, PETD, PVA, RRC, SFY, SM, SWN, UNT, VQ, XCO
National Fuel Gas Company
Capital Expenditures(1) – An Appalachian Focus
$1,000
Appalachian Growth ‐ E&P Appalchian Growth ‐ Infrastructure Other Spending
(2) (3)
$605‐740 $750
Millions)
$90‐105 $129 $130 – 195
$417 $307 $501 $500
ditures ($ M
$ 39 $356 $385 ‐ 440 $225 $208 $351 $161
$252 $248 $307 $250
pital Expen
$139
$0
2006 2007 2008 2009 2010 2011 Forecast Cap
10
Analyst Day – November 9, 2010
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.
Seneca Resources
Evaluation of JV Opportunities
- Seneca has engaged Jefferies & Company to explore joint‐venture
- pportunities across a broad portion of its acreage with the following goals:
- pportunities across a broad portion of its acreage, with the following goals:
- Ramp up development faster than current aggressive 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’s unique Marcellus position provides a competitive advantage for a
potential joint‐venture partner:
- 800,000 net acres in PA – 745,000 in heart of the Marcellus Fairway
- Majority of acreage is held in fee, carrying no royalty and no lease expirations
j y g , y g y y p
- Large, contiguous acreage blocks allow for operating‐ and cost‐efficiency through
multi‐well pad drilling
- Seneca will forgo joint‐venture opportunities that do not enhance shareholder
11
Analyst Day – November 9, 2010
g j pp value when compared to its current growth plans
National Fuel Gas Company
Independent Directors – A Wealth of Industry Experience
Former Director, President & CEO of Northwest Natural Gas Co. Vice Chairman of DTE Energy Director of Northern Border Pipeline Co. Former Chairman and CEO of Questar Corporation Former Vice Chairman, COO and Director of Keyspan Corporation Individual Responsible for DTE’s Barnett & Antrim Shale Plays Former Advisor to the COO of Duke Energy Former Vice Chairman of PanEnergy Corporation (now part of Spectra) Founder of Kidder Exploration, an Appalachian E&P Co. Director of Hess Corporation Former Chairman & COO of MCN Energy Former CEO of Michigan Consolidated Gas Co. Former President, CEO & Director of NUI Corporation , p Former Director of the Independent Oil & Gas Assoc. of NY & PA CEO and Chairman of Moog Inc. for 20+ Years (Major Company in NFG’s Service Territory) Former Vice-Chairman and CFO of Verizon Inc., a Regulated Industry Director of CMS Energy Corporation
12
Analyst Day – November 9, 2010
Director of CMS Energy Corporation Director of Dynegy, Inc.
Utility Segment
N i l F l G Di ib i C i
13 13
Analyst Day – November 9, 2010
National Fuel Gas Distribution Corporation
Analyst Day – November 9, 2010
14
Utility
Keys to Continued Success
Provide Stable Earnings
Operate Safe System Control Costs Excellent Customer Service Strong Regulatory Strategy
15
Analyst Day – November 9, 2010
Utility
Diluted Earnings per Share
(Before Items Impacting Comparability)
$1.00 $0.73 $0.73 $0.76 $0.80 $0.55(1) $0.60 $0.60 $0.40 $0.00 $0.20
16 16
Analyst Day – November 9, 2010 (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
Utility
$75
NY PA
Capital Spending
$ $18 0
$60
Millions)
$54.4 $54.2 $57.5 $56.2 $58.0 $16.0 $18.1 $18.3 $18.4 $18.0
$30 $45
ending ($ M
$38.4 $36.1 $39.2 $37.8 $40.0
$15 $30
Capital Spe
$0 2006 2007 2008 2009 2010
C
17
Analyst Day – November 9, 2010
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
lions)
$63.8 $63.8 $62.1 $60.7 $56.3
$150
ense ($ Mil
$140.5 $139.2 $140.6 $130.5 $125.0
$50 $100
O&M Expe
$0 2006 2007 2008 2009 2010
18
Analyst Day – November 9, 2010
2006 2007 2008 2009 2010
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% 89.1% 92.3% Customer Satisfaction: Residential Commercial 85.1% 86.0% 92.4% 90.7% 89.5% PSC Complaints (per 100,000 Customers) 2.1 0.1 N/A Estimated Meter Reading
Not to Exceed
15.9% 13.2% 10.2% Adjusted Bills
Not to Exceed
1 9% 1.1% 1.4% 1.9% New Service Gas Installations Installed within 10 Days 98.0% 99.9% 99.7% Non‐Emergency Field Appointments Kept 98 0% 99 2% 99 4%
19
Analyst Day – November 9, 2010
Non‐Emergency Field Appointments Kept 98.0% 99.2% 99.4%
(1) 12-months ended September 30, 2010
Utility
New York Pennsylvania
Rate Mechanisms
Revenue Decoupling Customer Choice / POR
y
Low Income Rates Customer Choice / POR Customer Choice / POR Merchant Function Charge Customer Choice / POR Merchant Function Charge 90/10 Sharing (large volume users) Weather Normalization Under Consideration: Revenue Decoupling Low Income Rates Revenue Decoupling
20
Analyst Day – November 9, 2010
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 FY 2006 FY 2007 FY 2008 FY 2009 FY 2010
21
Analyst Day – November 9, 2010 (1) Calculated using Average Total Comprehensive Shareholder Equity.
FY 2006 FY 2007 FY 2008 FY 2009 FY 2010
Utility Challenges
22
Analyst Day – November 9, 2010
Utility
Average Use per Residential Customer
250 200
count
100 150
ed Mcf/Ac 98.824
50
Normaliz
23
Analyst Day – November 9, 2010
12 Months Ended September (Fiscal Year)
Utility
Accounts Receivable – Customer (1)
$125 30‐59 Days 60‐89 Days 90‐119 Days 120 Days & Over $91.4 $86 6 $102.4 $99.7 $100 $125
Millions)
$ $75.2 $78 9 $86.6 $72.5 $75
eivable ($ M
$67.9 $64.4 $78.9 $58.3 $ $50
ccounts Rece
$9.3 $9.1 $11.1 $8.3 $6.4
$7.2 $6.6 $7.9 $6.3 $4.2 $7.0 $6.5 $8.2 $6.2 $3.6
$0 $25
Ac
24
Analyst Day – November 9, 2010
At 09/30/06 At 09/30/07 At 09/30/08 At 09/30/09 At 09/30/10
(1) All values include Purchase of Receivables (“POR”) Program
Utility
HEAP/LIHEAP
$75 NY Basic & Emergency PA Regular & Crisis $58.0 $57.1 $
ions)
g y g $41.9 $35.8 $39.2 $50
nding ($ Mill
$7.7 $6.8 $6 8 $14.6 $14.0 $25
Fun
$7.7 $6.8 $6.8 $0 2006 2007 2008 2009 2010
25
Analyst Day – November 9, 2010
(1) Program year runs from November to May
Program Year (1)
Utility
2011
Provide Stable Earnings
Operate Safe System Control Costs Excellent Customer Service Strong Regulatory Strategy
26
Analyst Day – November 9, 2010
Exploration & Production
S R C i
27 27
Analyst Day – November 9, 2010
Seneca Resources Corporation
Seneca Resources
Fiscal 2010 Highlights
Production
- Increased annual production by 17% to 49 7 BCFE
- Increased annual production by 17% to 49.7 BCFE
Reserve Replacement
- Replaced 445% of production
Finding & Development Cost
- F&D Cost decreased to approximately $1.80 per Mcfe
M ll E it R t Marcellus Exit Rate
- Marcellus net production at fiscal year end 2010 was 53 MMcfe per day
Seneca‐Operated IP Rates
- 6.6 MMcfe per day IP rates across all Seneca‐operated wells
- 8.5 MMcfe per day IP rates in Tioga and Lycoming county Seneca‐operated wells
EOG Joint‐Venture Results
28
Analyst Day – November 9, 2010
- Large Frac IPs in Clearfield County have averaged 8.2 MMcfe per day
Exploration & Production
Fiscal 2010 Year End Proved Reserves
East ‐ Appalachia Reserves: 333 Bcfe (48%)
Proved Reserves @ 9/30 503 Bcfe 528 Bcfe 700 Bcfe
FY ’10 Production: 16.5 Bcfe (33%)
55% 53% 61%
503 Bcfe 528 Bcfe 700 Bcfe
53% 39% 45% 47%
2008 2009 2010 West – California Reserves: 333 Bcfe (47%) (55.5 MMBoe)
FY ’10 Production: 19.8 Bcfe (40%)
Gulf of Mexico Reserves: 34 Bcfe (5%)
29
Analyst Day – November 9, 2010
Oil Gas ( )
FY ’10 Production: 13.4 Bcfe (27%)
Exploration & Production
Proved Reserves at 9/30/10 Probable and Possible Reserves, plus Resource Potential
Marcellus Shale
Accelerate development; Convert resource potential to reserves
202 Bcfe
Appalachian Region ‐ Upper Devonian
Drill 25‐50 wells per year
700 Bcfe 8 ‐ 15 Tcfe 131 Bcfe f
California
l d
700 Bcfe 131 Bcfe
Continue to operate as a low‐cost producer
Gulf of Mexico
333 Bcfe 280 Bcfe
30
Analyst Day – November 9, 2010
No exploration; Develop and produce existing reserves
34 Bcfe 15 Bcfe
Exploration & Production
Capital Expenditures by Region
$425‐500
$500 West Upper Devonian Gulf of Mexico Marcellus
$398 $
$400
Millions)
$332 $380‐425
$192 $188
$300
nditures ($ M
$61 $66 $64 $71
$147 $192 $188
$100 $200
Capital Expen
$41 $63 $31(1) $28 $35‐45 $39 $61 $68
$23 $15
$0
Fiscal 2007 Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 C
31
Analyst Day – November 9, 2010
Fiscal 2007 Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 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
75 West Upper Devonian Gulf of Mexico Marcellus 25 30
49.7 60‐70
60
fe)
30% 17%
14 7 14.1 13.7 13.4 9 11 7.2 25‐30
39.3 40.8 42.5
45
duction (Bcf
6.3 7.9 8.7 9.3 7‐9 14.7 9‐11 15 30
Prod
18.3 18.8 20.1 19.8 19‐20
Fiscal 2007 Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011
32
Analyst Day – November 9, 2010
Fiscal 2007 Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Forecast
Exploration & Production
$8.00 NFG All E&P Companies
Finding & Development Cost (1)
$5.98 $4 95
$6.00 All E&P Companies Mid‐Sized Independents
(2)
$4.95 $4.27 $3.10
$4.00
$/Mcfe $1.80
$2.00
(3)
$0.00 2006 2007 2008 2009 2010
33
Analyst Day – November 9, 2010
Fiscal Year
(1) 2006 – 2009 Finding and Development cost information was obtained from IHS Herold, Inc. (2) National Fuel’s 2007 finding and development cost is adjusted for revisions due to a change in reserve auditors. (3) National Fuel’s 2010 finding and development cost was calculated internally.
Exploration & Production
C lif i
34 34
Analyst Day – November 9, 2010
California
Seneca’s California Properties
South Lost Hills
1,900 BOEPD
North Lost Hills
1,200 BOEPD Tulare & Etchegoin Formation Monterey Shale Primary 216 Active Wells Tulare & Etchegoin Formation Primary & Steamflood 221 Active Wells
North Midway Sunset North Midway Sunset
4,100 BOEPD Potter & Tulare Formation Steamflood 709 Active Wells
Sespe
1,000 BOEPD Sespe Formation Primary
South Midway Sunset
650 BOEPD Primary 182 Active Wells Antelope Formation Steamflood 74 Active Wells
35
Analyst Day – November 9, 2010
California
Average Daily Production
10,000
- Modest capital spending
to maintain production
9,500 0,000
- Pursue additional bolt‐on
acquisitions
- 2011 Plans:
8,500 9,000
OE/Day
- CapEx ‐ $40 MM
- 50 Development wells
- Two 5‐acre in‐fill wells at
7,500 8,000
B
Sespe
7,000
36
Analyst Day – November 9, 2010
Exploration & Production
G lf f M i
37 37
Analyst Day – November 9, 2010
Gulf of Mexico
Gulf of Mexico
Average Daily Production
60
Mi i l i l di
40 50
Minimal capital spending Expect production decline
30 40
MMcfe/Day
in 2011
10 20
M
38
Analyst Day – November 9, 2010
Exploration & Production
E Di i i
39 39
Analyst Day – November 9, 2010
East Division
East Division
Average Daily Production
70 50 60 Mcfe/Day)
Upper Devonian Marcellus
Rapid growth in the East Division as Marcellus is
30 40 roduction (MM
ramping up Expect significant production
10 20 erage Daily Pr
Expect significant production increase in Q1
Ave
40
Analyst Day – November 9, 2010
Marcellus Shale
Seneca’s Pennsylvania Acreage
Seneca Resource Acreage Position 745,000 Net Acres in the heart of the PA Marcellus fairway 160,000 Net Acres included in EOG JV 80% Fee – Seneca owns the minerals No lease expiration 94% Average NRI
SRC L A SRC Fee Acreage
41
Analyst Day – November 9, 2010
94% Average NRI
SRC Lease Acreage
Marcellus Shale
Recent Well Results Validate Seneca’s Position
McKean County
SM E
Lycoming County Tioga County
Seneca Resources SM Energy IP: 7+ MMCFD
y g y
Seneca Resources IP: 15.8 MMCFD
Elk County
- Avg. IP: 7.9 MMCFD
Clearfield County
Seneca Resources IP: 3.9 MMCFD
Clearfield County
Seneca/EOG IP: 8.9 MMCFD
Armstrong County
EQT IP: 15 MMCFD
SRC L A SRC Fee Acreage
42
Analyst Day – November 9, 2010
SRC Lease Acreage
Marcellus Shale
Recent Activity
- Approx. Outline of JV Acreage
200,000 Gross Acres Seneca 50% W.I. (Avg. 58% NRI) Seneca Operated – Tioga 3 Rigs Drilling 12 Wells Producing Average IP: 7.9 MMcf per Day Seneca Operated – Lycoming IP 15 8 MM f D EOG Acreage Contributed IP: 15.8 MMcf per Day EOG Acreage Contributed ~120,000 Gross Acres Seneca 50% W.I. (40% NRI) EOG Operated – Last 4 Completions Bigger Fracs – 5 ½” Casing SRC Lease Acreage SRC Fee Acreage SRC Contributed JV Acreage
43
Analyst Day – November 9, 2010
Average IP: 8.2 MMcf per Day EOG Contributed JV Acreage
Marcellus Shale
Eastern Development Area
Covington Area – Full Development Seneca Operated Initial Test Wells
- Tioga/Lycoming/Potter
55,000 Acres
Seneca Operated 24 Wells Drilled; 12 Producing Current Production: 62 MMcf/d 2011: 16 Wells Planned
Drilling / Fracing
Resource Potential: 2 Tcf
DCNR Block 595 – Full Development S O t d Seneca Operated 3 Wells Drilled; 1 Producing Current Production: 5.0 MMCFD 2011: 10‐15 Wells Planned DCNR Block 100 – Full Development Seneca Operated 1 well drilled 2011: 6 Wells Planned First Production: Fall 2011 SRC L A SRC Fee Acreage
44
Analyst Day – November 9, 2010
First Production: Fall 2011 SRC Lease Acreage
Marcellus Shale
Western Development Area
Seneca Operated
- Mt. Jewett Area
Seneca Operated EOG Operated 2011: 3 Wells Planned Beechwood Area Seneca Operated 2011: 3 Wells Planned Owl’s Nest Area Seneca Operated Drilling 2011: 3+ Wells Planned Boone Mtn. Area Seneca Operated 3 e s a ed Optimized Landing Target SRC Lease Acreage SRC Fee Acreage SRC Contributed JV Acreage Punxy Area – Full Development EOG Operated p 2011: 3 Wells Planned
45
Analyst Day – November 9, 2010
EOG Contributed JV Acreage 30 Wells Drilled; 8 Producing Current Gross Production: 16 MMcf/d 2011: 30+ Wells Planned
Tioga County Decline Curves
Longer Lateral Wells Outpacing Original Decline Curve
Avg Tioga Production per Well(1)
- Avg. Tioga Production per Well(1)
6.3 Bcf Typecurve
46
Analyst Day – November 9, 2010
(1) Chart data represents horizontal well production from wells with lateral lengths greater than 3,000 feet
Marcellus Shale
Pennsylvania Average Daily Gas Production per Horizontal Well
(Companies with at least 5 horizontal wells producing)
5.0 4.0 n per Well d) 2.0 3.0 Gas Production (Avg. MMcfd 0 0 1.0 Daily G 0.0
47
Analyst Day – November 9, 2010
Source: All data represents Marcellus Shale gas production from July 1, 2009 through June 30, 2010 for companies with at least five producing horizontal wells within the State of Pennsylvania and was provided by the Pennsylvania Department of Environmental Protection. The data was retrieved on November 4, 2010.
Marcellus Shale
60
Marcellus Net Production
Marcellus net production at
40 50 MMcfe)
September 30, 2010 was:
53 MMcfe per day
30 Production (M
Seneca Operated
20 Daily Net P ‐ 10
EOG JV
48
Analyst Day – November 9, 2010
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: ~$120,000 per well
Pay Out: 31 Wells Pay Out: 31 Wells
Other Benefits:
Improved stream quality Substantial reduction of water truck activity
49
Analyst Day – November 9, 2010
activity No need to withdraw water elsewhere
Marcellus Shale
100‐130 125
EOG JV Wells Seneca Vertical Wells Seneca Horizontal Wells
Wells Drilled per Year
100
60‐80
65 75
ells Drilled
7 5 29
24 25 50
We
11 29 35‐45 10
4 6
Fiscal 2007 Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011
50
Analyst Day – November 9, 2010
Fiscal 2007 Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Forecast
Marcellus Shale
Pre‐Tax IRR Comparison
D i ti EUR Well Cost ($ MM) Net Working I t t Net Revenue I t t Pre‐Tax IRR (NYMEX ‐ $/MMBtu)
$4 00 $5 00 $6 00
Description EUR ($ MM) Interest Interest
$4.00 $5.00 $6.00
Seneca Tioga County Wells at 18% Royalty 6 Bcf $4.6 100% 82% 63% 100+% 100+% Seneca Mineral Fee Seneca Mineral Fee Wells in EOG JV 4 Bcf $4.0 50% 60% 68% 100+% 100+% Seneca Mineral Fee Wells – No Royalty 4 Bcf $4.0 100% 100% 46% 75% 100+% Competitor Well with 15% Royalty Rate 4 Bcf $4.0 100% 85% 30% 51% 78%
51
Analyst Day – November 9, 2010
Marcellus Shale
$6.00
Breakeven Pricing at PV10
$4 00 $5.00
$/Mcfe)
On November 1, 2011, NYMEX Strip(1) for Fiscal Year 2011 was $4.03 $ $2.21 $2.32
$3.00 $4.00
even Price (
EUR: 4 Bcf EUR: 6 Bcf EUR: 4 Bcf
$1.93 $2.21
$1.00 $2.00
PV10 Break
NWI: 50% NRI: 60% NWI: 100% NRI: 82% NWI: 100% NRI: 100% $0.00
Seneca Mineral Fee Wells in EOG JV Seneca Tioga/Lycoming Wells at 18% Royalty Seneca Mineral Fee Wells With No Royalty
52
Analyst Day – November 9, 2010
Wells in EOG JV Wells at 18% Royalty Wells With No Royalty
(1) The NYMEX strip prices for fiscal year 2011 include the settlement prices for the October 2010 and November 2010 contracts.
Seneca Resources
Marcellus Shale Summary
- Continuing to achieve high IP rates and showing slow decline
- Continuing to achieve high IP rates and showing slow decline
- Fourth horizontal rig is on location
- Will have 3 rigs in East and 1 in West for 1st half of FY2011
- EOG Program is picking up and showing improvement
- First “big fracs” came on at high rate
- Infrastructure constrained in Clearfield County
- Marcellus production will continue to grow rapidly
- Fiscal Year 2010 exit rate was 53 MMCFD
- Fiscal Year 2010 exit rate was 53 MMCFD
- Expect net 100+ MMCFD by fiscal year end 2011 (9/30/2011)
- Explore joint‐venture opportunities
53
Analyst Day – November 9, 2010
Pipeline & Storage / Midstream
National Fuel Gas Supply Corporation Empire Pipeline, Inc.
54 54
Analyst Day – November 9, 2010
National Fuel Gas Midstream Corporation
Analyst Day – November 9, 2010
55
Analyst Day – November 9, 2010
55
Analyst Day – November 9, 2010
56
Analyst Day – November 9, 2010
56
Analyst Day – November 9, 2010
57
Analyst Day – November 9, 2010
57
Analyst Day – November 9, 2010
58
Analyst Day – November 9, 2010
58
PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES
NORTHERN ACCESS LAMONT COMPRESSOR TIOGA COUNTY EXTENSION ACCESS COMPRESSOR STATION PHASE I & II COVINGTON GATHERING SYSTEM LINE “N” EXPANSION PHASE I & II TROUT RUN GATHERING SYSTEM WEST TO EAST OVERBECK TO LEIDY PHASE I & II
Seneca Drilling Activity EOG JV Drilling Activity Expansion Projects
Analyst Day – November 9, 2010
59
Analyst Day – November 9, 2010
APPALACHIAN LATERAL
Appalachian Lateral/W2E W2E Overbeck to Leidy Northern Access Expansion
59
Pipeline & Storage/Midstream
Expansion Initiatives
Project Name Capacity Est. In‐Service Status Project Name (Dth/D) CapEx Date Status
Covington Gathering System 145,000 $16 MM 11/17/09 Completed – Flowing into TGP 300 Line Lamont Compressor Station 40,000 $6 MM 6/15/10 Completed – Flowing into TGP 300 Line p p g Lamont Phase II Project 50,000 $7 MM ~ 07/2011 Executed precedent agreements Line “N” Expansion 160,000 $23 MM ~ 09/2011 Filed FERC 7(c) application on 6/11/10. Negotiating final precedent agreement for 10 000 Dth/day 10,000 Dth/day Tioga County Extension 350,000 $46 MM ~ 09/2011 Filed FERC 7(c) filing on August 23, 2010 Trout Run Gathering System 250,000 $27 MM Fall 2011 Preliminary work has begun Northern Access Expansion 320,000 $60 MM Late 2012 Executed precedent agreement Line “N” Phase II Expansion ~195,000 $40 MM ~ 11/2012 Executed precedent agreement for 150,000 Dth/day W2E Overbeck to Leidy 425,000 $260 MM 2013 Pursuing post‐Open season requests for remaining 300 000 Dth/day
60
Analyst Day – November 9, 2010
remaining 300,000 Dth/day
Midstream Corporation
Covington Gathering System – Tioga County
Tennessee Gas Pipeline
TGP 300
C i 146 000 D h/d Capacity: 146,000 Dth/d Interconnects with Tennessee Gas Pipeline in Tioga County Gas Pipeline in Tioga County Seneca Resources is the sole shipper
Tract 595
pp Seneca is currently shipping gross production of
Interstate Pipeline
approximately 60 MMcf per day
61
Analyst Day – November 9, 2010
p Gathering System
Midstream Corporation
Trout Run Gathering System – Lycoming County
Capacity: 250,000 Dth/d Will Interconnect with Transco Will Interconnect with Transco Pipeline in Lycoming County Seneca Resources will be the primary shipper Estimated In‐Service: Fall 2011
Interstate Pipeline
Transco
62
Analyst Day – November 9, 2010
Gathering System
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: ~$4.5 Million FY12: ~$6.0 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
63
Analyst Day – November 9, 2010
Energy Marketing
National Fuel Resources
64 64
Analyst Day – November 9, 2010
National Fuel Resources National Fuel Resources
Fiscal 2010 Highlights
- Recently launched a residential marketing campaign on RG&E and
y g p g NYSEG
- Further diversify customer pool in areas where commercial, industrial and
holesale c stomers alread e ist wholesale customers already exist
- Falling natural gas futures prices have led to increased customer price
l k i lock‐ins over most customer groups
- NFR continued to be a significant customer of both NFGSC and Empire
- Increased competition in Pennsylvania, potentially due to PAPUC
initiatives to expand customer choice programs
65
Analyst Day – November 9, 2010
p p g
National Fuel Resources National Fuel Resources
Fiscal 2011 Expectations
- Strong focus on growth of new residential and small commercial
g g customer pools on RG&E and NYSEG using POR programs
- Expand residential customer program in NFGDC’s Pennsylvania territory
with the recently adopted POR program
- Monitor development of Marcellus production and position NFR to
p p p ensure diverse and reliable supplies at minimal cost structure
- Continue to evaluate strategic acquisition of pipeline capacity in NFR
- Continue to evaluate strategic acquisition of pipeline capacity in NFR
territories
66
Analyst Day – November 9, 2010
National Fuel Gas Company
Corporate & Financial Highlights
67 67
Analyst Day – November 9, 2010
Corporate & Financial Highlights
National Fuel Gas Company
2011 EPS Guidance & Sensitivity
NFG & Subsidiaries NFG & Subsidiaries
On November 4, 2010, the Company updated its fiscal 2011 earnings guidance utilizing flat di i i f $
Fiscal 2011
Preliminary Earnings per Share (Diluted) Guidance(1) commodity pricing of $4.00 per MMBtu for natural gas and $80.00 per Bbl for crude oil, and adjusting for basis differential y g p ( )
Range
Consolidated Earnings $2.40 ‐ $2.70(1) j g
Seneca Resources Preliminary
Earnings per Share Sensitivity to Changes from $4.00/MMBtu for natural gas and $80.00/Bbl for crude oil(1)
Production Guidance: 60 to 70 Bcfe
$1 change per MMBtu gas $5 change per Bbl oil
Increase Decrease Increase Decrease
+$0.19 ‐$0.19 +$0.05 ‐$0.05
68
Analyst Day – November 9, 2010
(1) The preliminary earnings guidance and sensitivity table are current as of November 4, 2010. 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 hedge contracts at their maturity. For its fiscal 2011 updated earnings forecast, the Company is using flat commodity pricing of $4.00 per MMBtu for natural gas and $80.00 per Bbl for crude oil, and adjusting for basis differential.
National Fuel Gas Company
Fiscal Year 2011 Earnings Guidance – Key Drivers
Exploration & Production
P d i ↑ 30%
FY 2011 EPS
- Production ‐ ↑ 30%
- DD&A: $2.05 to $2.15 per Mcfe
- LOE: $1.10 to $1.35 per Mcfe
- G&A: $38 ‐ $41 Million
FY2010 FY 2011 EPS
$2.40 to $2 70
Pipeline & Storage / Midstream
- Operating Expense: ↑ 3% to 5%
- Transportation Revenue: ↓ $4.5 Million
- Project Development Costs (O&M): $7 Million
FY2010 Operating Results
$2 65(1) +
=
$2.70
Utility
- Project Development Costs (O&M): $7 Million
- Midstream Earnings per Share: $0.05 to $0.10
$2.65(1)
- Operating Expense: ↑ 3% to 5%
- PA Normal Weather
NYMEX Pricing ⏐
69
Analyst Day – November 9, 2010
Gas: $4.00/MMBtu ⏐ Oil: $80.00/Bbl
(1) 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
Looking Beyond Fiscal 2011…
Exploration & Production p
- Marcellus = Substantial growth engine
- West = Stable production and cash flows
- Gulf = Produce out assets
- Gulf = Produce out assets
Pipeline & Storage / Midstream
- Major expansion projects on line starting in late 2011
- Rate case in Supply Corporation in early fiscal 2012
Utility
- Limited opportunities for growth
- i
i f &
70
Analyst Day – November 9, 2010
- Maintain focus on O&M costs
National Fuel Gas Company
Capital Expenditures(1) from Continuing Operations
$1,000
Exploration & Production Pipeline & Storage Utility All Other
$605‐740 $750
Millions)
$38
$100‐ 150
$57 $58 $55‐60
$501 $500
ditures ($ M
$417
$192 $188 $398 $425 ‐ 500
$43 $166 $53 $54 $54 $57 $56
$252 $248 $307 $250
pital Expen
$167 $147 $192 $188
$0
2006 2007 2008 2009 2010 2011 Forecast Cap
71
Analyst Day – November 9, 2010
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
$1,400 $1,400 $1,400
Sources and Uses of Cash
2010 Actual 2011 Forecast
$58
$1,050 $1,050 $1,050
Debt Maturities
Uses
$989 $989 $115 $200 $333 $58
$700 $700 $700
Dividend CapEx New Financing
Uses
- f Cash
$ Millions
$566 $566 $75 $69 $77 $674
$350
$82 $100 $113 $110
$350 $350
Cash on Hand Other Utility
Sources
- f Cash
$377
$0
Sources of Uses of Sources of Uses of
$257 $456
$0
Sources of Uses of Sources of Uses of
$0
Sources of Uses of Sources of Uses of
P&S E&P
f
72
Analyst Day – November 9, 2010
Sources of Cash Uses of Cash Sources of Cash Uses of Cash Sources of Cash Uses of Cash Sources of Cash Uses of Cash Sources of Cash Uses of Cash Sources of Cash Uses of Cash
(1) For its fiscal 2011 earnings forecast, the Company is using flat commodity pricing of $4.00 per MMBtu for natural gas and $80.00 per Bbl for crude oil, and adjusting for basis differential.
(1)
National Fuel Gas Company
Seneca Oil and Gas Hedge Positions
Natural Gas Swaps Volume (Bcf) Average Hedge Price
Fiscal 2011 19 9 $6 76 / Mcf
Oil Swaps Volume (MMBbl) Average Hedge Price
Fiscal 2011 1 6 $70 26 / Bbl Fiscal 2011 19.9 $6.76 / Mcf Fiscal 2012 14.6 $7.03 / Mcf Fiscal 2013 3.8 $6.65 / Mcf Fiscal 2011 1.6 $70.26 / Bbl Fiscal 2012 1.1 $70.55 / Bbl Fiscal 2013 0.3 $75.94 / Bbl
For fiscal year 2011, S ’ h h d d
NYMEX Strip Prices
(at 11/01/10)
Natural Gas Oil
Seneca’s has hedged 45% of their forecasted production
(at 11/01/10)
Gas Oil
Fiscal 2011(1) $4.03 $83.83 Fiscal 2012 $4.85 $87.53 Fiscal 2013 $5 24 $88 32
73
Analyst Day – November 9, 2010
Fiscal 2013 $5.24 $88.32
(1) The NYMEX strip prices for fiscal year 2011 include the settlement prices for the October 2010 and November 2010 contracts.
National Fuel Gas Company
Short‐Term Debt
2%
Capital Structure
Sh h ld ’ Long‐Term Debt
Shareholders’ Long‐Term Debt
Shareholders’ Equity
63%
Debt
35% Shareholders Equity
58%
Debt
42%
$2.995 Billion(1)
at September 30, 2010
Forecasted Capital Structure(2)
t S t b 30 2011
74
Analyst Day – November 9, 2010
at September 30, 2011
(1) At September 30, 2010, Comprehensive Shareholders’ Equity, Long‐Term Debt and the Current Portion of Long‐Term Debt totaled $2.995 Billion as presented on the Company’s Balance Sheet, of which $1.049 Billion was Long‐Term Debt, $0.2 Billion was the Current Portion of Long‐Term Debt and $1.746 Billion was Comprehensive Shareholders’ Equity (2) At September 30, 2011, forecasted Total Capitalization is $3.002 Billion, of which $0.899 Billion is Long‐Term Debt, $0.150 Billion is the Current Portion of Long‐Term Debt, $0.058 Billion is Short‐Term Debt and $1.896 Billion is Comprehensive Shareholders’ Equity
National Fuel Gas Company
Capital Resources & Credit Ratings
Capital Resources
CURRENT CREDIT RATINGS
$300.0 MM Commercial Paper Program and $405 MM in Uncommitted Credit Facilities – Aggregate of $705.0 MM
RATING AGENCY RATING
FITCH BBB+ ’
CURRENT CREDIT RATINGS
$300.0 MM Committed Credit Facility through September 2013 – backs Commercial Paper Program
MOODY’S Baa1 STANDARD & POOR’S BBB
75
Analyst Day – November 9, 2010
National Fuel Gas Company
Debt Maturity Schedule
$300
$300
$200 $250 $250
$200
Millions)
$150
$100 $200
aturity ($ M
$49 $50
7 500% 6 700% 5 250% 6 500% 8 750% 7 395% 7 375% $100
Debt Ma
7.500% 6.700% 5.250% 6.500% 8.750% 7.395% 7.375% $0 2011 2012 2013 2018 2019 2023 2025
Fiscal Year
76
Analyst Day – November 9, 2010
Total Long‐Term Debt Outstanding At September 30, 2010: $1.249 B
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%
$0.19
%
77
Analyst Day – November 9, 2010
Annual Rate at Fiscal Year End
National Fuel Gas Company
Key Takeaways
High‐Quality Marcellus Acreage Position g Q y g
745,000 net acres with a resource potential of 8‐15 Tcfe Recent well results validate the quality of our acreage Fee ownership results in superior economics
Balanced Business Model
Regulated segments support dividend and are not sensitive to commodity prices Sizable oil production provides earnings stability
S Fi i l P i i Strong Financial Position
Simple balance sheet Well capitalized Si ifi t i t ll t d h fl
78
Analyst Day – November 9, 2010
Significant internally generated cash flows
79 79
Analyst Day – November 9, 2010
Marcellus Shale
Recent Activity
SRC Lease Acreage SRC Fee Acreage SRC Contributed JV Acreage
80
Analyst Day – November 9, 2010
EOG Contributed JV Acreage
National Fuel Gas Company
bl l Comparable GAAP Financial Measure Slides and Reconciliations
This presentation contains certain non‐GAAP financial measures. For pages that contain non‐GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that follow. The Company believes that its non‐GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s operating results in a manner that is focused on the performance
- f the Company’s ongoing operations.
The Company’s management uses these non GAAP financial measures for the same purpose and for planning these non‐GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non‐GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP
81
Analyst Day – November 9, 2010
with GAAP.
Analyst Day – November 9, 2010
82
Reconciliation of GAAP Net Income to Income From Continuing Operations Excluding Items Impacting Comparability ($ Thousands) ($ Thousands) FY 2007 FY 2008 FY 2009 FY 2010 GAAP Net Income E&P Segment GAAP Net Income 210,669 $ 146,612 $ (10,238) $ 112,531 $ P&S Segment GAAP Net Income 56,386 54,148 47,358 36,703 Utility Segment GAAP Net Income 50,886 61,472 58,664 62,473 Marketing Segment GAAP Net Income 7,663 5,889 7,166 8,816 Marketing Segment GAAP Net Income 7,663 5,889 7,166 8,816 Corporate & All Other GAAP Net Income 11,851 607 (2,242) 5,390 Total GAAP Net Income 337,455 $ 268,728 $ 100,708 $ 225,913 $ Discontinued Operations (Income) Loss from Operations, Net of Tax (Corporate & All Other) (427) $ (1,821) $ 2,776 $ (470) $ Gain on Disposal, Net of Tax (Corporate & All Other)
- (6,310)
(Income) Loss from Operations, Net of Tax (Exploration & Production) (15,479)
- Gain on Disposal, Net of Tax (Exploration & Production)
(120,301)
- (Income) Loss from Discontinued Operations, Net of Tax
(136,207) $ (1,821) $ 2,776 $ (6,780) $ Items Impacting Comparability Reversal of reserve for preliminary project costs (P&S) (4,787) $
- $
- $
- $
R l i f h d i (M k i ) (2 344) Resolution of purchased gas contingency (Marketing) (2,344)
- Discontinuance of hedge accounting (P&S)
(1,888)
- Gain on sale of turbine (Corporate & All Other)
- (586)
- Gain on life insurance policies (Corporate & All Other)
- (2,312)
- Impairment of investment partnership (Corporate & All Other)
- 1,085
- Impairment of oil and gas properties (E&P)
- 108,207
- Total Items Impacting Comparability
(9 019) $ (586) $ 106 980 $ $ Total Items Impacting Comparability (9,019) $ (586) $ 106,980 $
- $
Income from Continuing Operations excluding Items Impacting Comparability E&P Segment Operating Income 74,889 $ 146,612 $ 97,969 $ 112,531 $ P&S Segment Operating Income 49,711 54,148 47,358 36,703 Utility Segment Operating Income 50,886 61,472 58,664 62,473 Marketing Segment Operating Income 5,319 5,889 7,166 8,816
Analyst Day – November 9, 2010
83
Marketing Segment Operating Income 5,319 5,889 7,166 8,816 Corporate & All Other Operating Income 11,424 (1,800) (693) (1,390) Total Income from Continuing Operations excluding Items Impacting Comparability 192,229 $ 266,321 $ 210,464 $ 219,133 $
Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2011 FY 2006 FY 2007 FY 2008 FY 2009 FY 2010 Forecast Capital Expenditures from Continuing Operations Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 166,535 $ 146,687 $ 192,187 $ 188,290 $ 398,174 $ $425,000-500,000 Pipeline & Storage Capital Expenditures 26,023 43,226 165,520 52,504 37,894 $100,000-150,000 Utility Capital Expenditures 54,414 54,185 57,457 56,178 57,973 $55,000-60,000 Marketing, Corporate & All Other Capital Expenditures 5,334 3,414 1,614 9,829 7,311 $25,000-30,000 Total Capital Expenditures from Continuing Operations 252,306 $ 247,512 $ 416,778 $ 306,801 $ 501,352 $ $605,000-740,000 Capital Expenditures from Discountinued Operations Exploration & Production Capital Expenditures 41,768 $ 29,129 $
- $
- $
- $
- $
All Other Capital Expenditures 85 87 131 216 150 Total Capital Expenditures from Discontinued Operations 41,853 $ 29,216 $ 131 $ 216 $ 150 $
- $
Plus (Minus) Accrued Capital Expenditures ( ) p p 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 294,159 $ 276,728 $ 397,734 $ 313,633 $ 455,764 $ $605,000-740,000
Analyst Day – November 9, 2010
84
Reconciliation of Appalachian Growth Capital Expenditures to Consolidated Capital Expenditures ($ Millions) FY 2011 FY 2006 FY 2007 FY 2008 FY 2009 FY 2010 Forecast Appalachian Growth Capital Expenditures from Continuing Operations1 Exploration & Production Capital Expenditures - East Division 27.0 $ 39.1 $ 65.8 $ 138.6 $ 355.7 $ $385-440 Pi li & St A l hi E i C it l E dit 10 3 $65 75 Pipeline & Storage Appalachian Expansion Capital Expenditures
- 10.3
$65-75 Midstream Capital Expenditures
- 7.4
6.5 $25-30 Total Appalachian Capital Expenditures from Continuing Operations 27.0 $ 39.1 $ 65.8 $ 146.0 $ 372.5 $ $475-545 Other Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 139.5 $ 107.6 $ 126.4 $ 49.7 $ 42.5 $ $40-60 Pipeline & Storage Capital Expenditures 26 0 43 2 165 5 52 5 27 6 $35-75 Pipeline & Storage Capital Expenditures 26.0 43.2 165.5 52.5 27.6 $35 75 Utility Capital Expenditures 54.4 54.2 57.5 56.2 58.0 $55-60 Marketing, Corporate & All Other Capital Expenditures 5.3 3.4 1.6 2.3 0.8
- $
Total Other Capital Expenditures from Continuing Operations 225.2 $ 208.4 $ 351.0 $ 160.7 $ 128.9 $ $130-195 Capital Expenditures from Discountinued Operations Exploration & Production Capital Expenditures 41.8 $ 29.1 $
- $
- $
- $
- $
All Other Capital Expenditures 0.1 0.1 0.1 0.2 0.1 Total Capital Expenditures from Discontinued Operations 41.9 $ 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 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
294.1 $ 276.7 $ 397.7 $ 313.6 $ 455.8 $ $605-740
Analyst Day – November 9, 2010
85
(1) Defined as spending related to efforts to drill for, gather, or transport Appalachian sources of natural gas.