EX-99 2 d346799dex99.htm EX-99 EX-99
National Fuel Gas Company
Investor Presentation
AGA Financial Forum
May 6-8, 2012
Exhibit 99

May 6-8, 2012
National Fuel Gas Company
2
Safe Harbor For Forward Looking Statements

May 6-8, 2012
National Fuel Gas Company
3
Our Business Mix Leads to Long-Term Value Creation
Upstream
Crude Oil
Midstream
Downstream
National Fuel Gas
Supply Corporation
Empire Pipeline, Inc.
National Fuel Gas
Midstream Corporation
National Fuel Gas
Distribution
Corporation
National Fuel
Resources, Inc.
The strategic, operational and financial benefits created by
the integrated mix of assets continues to generate
significant long-term value for the Company in nearly all
economic and commodity price scenarios
Upstream
Natural Gas
Seneca Resources
Corporation
(West Division)
Seneca Resources
Corporation
(East Division)

May 6-8, 2012
National Fuel Gas Company
4
Integrated Business Mix Provides Financial Balance
Note: A reconciliation of EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings is included at the end of this presentation. 

May 6-8, 2012
National Fuel Gas Company
5
Businesses with Steady Cash Flows Limit Downside Risk
Note: A reconciliation of EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings is included at the end of this presentation. 

May 6-8, 2012
National Fuel Gas Company
6
Highly Integrated Assets with Significant Marcellus Exposure…

May 6-8, 2012
National Fuel Gas Company
7
…And Exposure to Growth from the Utica Shale

May 6-8, 2012
National Fuel Gas Company
Business Mix Allows for Strategic Capital Allocation
Predictable Earnings and Cash Flow
Capital Allocation Priorities
Ongoing maintenance capital spending in regulated businesses
Returning earnings to shareholders through consistent dividends
Flexible, return-driven growth capital spending
8

May 6-8, 2012
National Fuel Gas Company
9
Strategically Allocating Growth Capital Expenditures
Growth Capital Focus
Increasing Marcellus Production
Eastern Development Area
Western Development Area
Delineate other Appalachian Plays
Utica Shale
Geneseo Shale
Marcellus Wet Gas
Expand FERC-Regulated Infrastructure
Develop New Gathering Infrastructure
Unlock Seneca Acreage Position
Build Projects for 3   Parties
Analyst Day –
September 2011
Current Allocation
Growth Capital Focus
Increasing Marcellus Production
Eastern Development Area
Western Development Area
Delineate other Appalachian Plays
Utica Shale
Geneseo Shale
Marcellus Wet Gas
Expand FERC-Regulated Infrastructure
Develop New Gathering Infrastructure
Unlock Seneca Acreage Position
Build Projects for 3   Parties
rd
rd

May 6-8, 2012
National Fuel Gas Company
10
Broadening Our Infrastructure Expansion Focus
Source: ITG IR (formerly Ross Smith Energy Group)

May 6-8, 2012
National Fuel Gas Company
11
Continued Reduction in Capital Spending
1.
Maintain a strong balance sheet
2.
Flexibility to strategically
redeploy capital based upon
return-driven opportunities
Analyst Day: 6.5 Operated Rigs
Current Plan: 3 Operated Rigs
Factors Behind Capital Reduction

May 6-8, 2012
National Fuel Gas Company
12
Capital Spending Flexibility to Maintain Financial Strength
Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.
To the extent additional infrastructure
expansions are available, additional capital
remains flexible and will be deployed
based upon return-driven decision making

May 6-8, 2012
National Fuel Gas Company
13
Strong Balance Sheet and Liquidity Position
Capital Resources
Total Short-Term Capacity: $1,085 Million
Committed Credit Facility:  $750 Million
Five-year syndicated facility entered into
January 6, 2012
Uncommitted Lines of Credit: $335 Million
$300.0 Million Commercial Paper Program
backed by Committed Credit Facility
$20.0
million
of
outstanding
commercial
paper
as
of
March
31,
2012
$3.386 Billion
(1)
As of March 31, 2012
Short-Term
Debt
0.6%
(1) Includes Notes Payable to Banks and Commercial Paper of $20.0 million and Current Portion of Long-Term Debt of $250.0 million as
of March 31, 2012.

May 6-8, 2012
National Fuel Gas Company
14
Dividend Track Record
Current
Dividend Yield
(1)
3.0%
Dividend Consistency
Consecutive Dividend Payments
109 Years
Consecutive Dividend Increases
41 Years
Current Annualized Dividend Rate
$1.42 per Share
(1) As of April 30, 2012

May 6-8, 2012
Pipeline & Storage / Midstream
15

May 6-8, 2012
Pipeline & Storage / Midstream
16
Ongoing Expansion to Transport Appalachian Production

May 6-8, 2012
Pipeline & Storage / Midstream
17
A Closer Look at the Expansion Progress

May 6-8, 2012
Midstream
18
Using a History of Excellence to Serve Appalachian Producers
Midstream’s gathering systems are
critical to unlock remote, but highly
productive Marcellus acreage
History of operational success and
efficiency within Pennsylvania
Original priority had been to assist
Seneca’s growing development
program and utilize those systems to
gather 3
rd
party producer volumes
As a result of Seneca’s delayed
development plans, the current focus is
shifting to expanding infrastructure for
others in the basin
TGP 300
Transco
Tioga County
Lycoming County

May 6-8, 2012
Pipeline & Storage Growth
19
Deploying Significant Growth Capital
Capital spending is increasing to fund system expansion and assuming recently
allowed industry average ROE and capital structure targets, this
segment can
achieve significant growth with a rapid increase in contracted volumes
19

May 6-8, 2012
Pipeline & Storage
20
Regulatory Rate Filings
National Fuel Gas Supply Corporation
Filed
a
general
rate
case
with
FERC
on
October
31,
2011
as
part
of
an
agreement
from
a
2006
rate
settlement
On April 14, 2012 an agreement in
principle was reached to settle the rate
case, with new rates effective May 1,
2012
Rates are effective subject to refund
beginning May 1, 2012
Empire Pipeline, Inc.
Filed a cost and revenue study on
March 14, 2012 as part of a 2006 FERC
order related to Empire’s transition to
a FERC-regulated interstate pipeline
Filing did not propose any changes to
the current rate structure

May 6-8, 2012
Utility
21

May 6-8, 2012
Rate Mechanisms
New York & Pennsylvania
Low Income Rates
Choice Program/POR
Merchant Function Charge
New York only
Revenue Decoupling
90/10 Sharing
Weather Normalization
Utility
22
Providing Financial Stability

May 6-8, 2012
Utility
23
Low Natural Gas Prices Have Reduced Customer Bills

May 6-8, 2012
Utility
24
Continued Cost Control Helps Provide Earnings Stability
Low natural gas prices,
combined with a focus on
cost control, continue to
help reduce expenses

May 6-8, 2012
Utility
25
Strong Commitment to Safety
Capital spending from 2011 to 2014 is
expected to be between
$55 and $60 million per year

May 6-8, 2012
Exploration & Production
26

May 6-8, 2012
Seneca Resources
27
Ongoing Strategic Responses to Low Gas Prices

May 6-8, 2012
California
28
Stable Production and Increasing Cash Flows
Rank
Company
California
2010
BOEPD
1
Chevron
174,856
2
Aera (Shell/Exxon)
158,786
3
Occidental
151,584
4
Plains Exploration
36,488
5
Venoco Inc.
19,121
6
Berry Petroleum
18,513
7
Seneca Resources
9,041
8
Breitburn Energy
7,414
9
MacPherson
7,185
10
E&B Natural Resources
5,259
Net Acreage:  11,833 Acres
Net Wells:  1,322
Oil Gravity:  12 –
37°
Api
NRI:  87.64

May 6-8, 2012
California
29
Stable Production Fields
South Lost Hills
~1,700 BOEPD
Monterey Shale
Primary
215 Active Wells
Sespe
~1,200 BOEPD
Sespe Formation
Primary
188 Active Wells
North Lost Hills
~1,200 BOEPD
Tulare & Etchegoin Formation
Primary & Steamflood
181 Active Wells
North Midway Sunset
~4,400 BOEPD
Potter & Tulare Formation
Steamflood
728 Active Wells
South Midway Sunset
~1,000 BOEPD
Antelope Formation
Steamflood
109 Active Wells

May 6-8, 2012
California
30
Strong Margins Support Significant Free Cash Flow
Average Revenue
in First Six Months of
Fiscal 2012
$87.33 per BOE
Note:
A
reconciliation
of
Exploration
&
Production
West
Division
EBITDA
to
Exploration
&
Production
Segment
Net
Income
is
included
at
the
end
of
this
presentation. 

May 6-8, 2012
Seneca Resources
31
California –
Recent Initiatives Driving Near-Term Growth
Production Increase Drivers
1.North Midway Sunset Steaming
2.South Midway Sunset Field Extensions
3.Sespe Infill Drill Program

May 6-8, 2012
32
Midway Sunset South Activity Update
2011 Drill Program
2012 Drilling Locations
Updip Sand Pinch-out
Approx. Oil/Water Contact
100 ft
100 ft
50 ft
Antelope “A-1”
and “A-2”
Sands
Antelope “B”
and “C”
Sands
Antelope “A-1”
Sand
Seneca Western Minerals 251T
Extended 251 Pool to the West
Seneca Western Minerals 242I
Extended 252 Pool to the West
100 ft
400’
50 ft
50 ft
50 ft
2011 Drill Program:  12 Wells / 4 Injectors
2012 Drill Program:  23 Wells / 3 Injectors
Seneca Resources

May 6-8, 2012
33
350’
Thick
(Medium Blue)
800’
Thick
(Dark Red)
~550’
Thick
(Green)
White Star –
5 Acre Tests
Powell –
10 Acre Tests
Powell 4
61 BOEPD
1st
Oil 11/11
WS 534-33
42 BOEPD
1st
Oil 1/12
White Star –
10 Acre Test
WS 48-33
Completion Begins
April 2012
WS 533-33
88 BOEPD
1st
Oil 1/12
“X”
SANDS ISOCHORE (Thickness)
Seneca Resources
Sespe Field –
2011 Drilling Highlights and Results
Powell 3
136 BOEPD
1st
Oil 10/11
1 Mile
2011 Sespe Highlights
5 Wells Drilled (Two 5-acre infill tests)
Estimated EURs: 150-200 MBoe/Well

May 6-8, 2012
34
Proposed Bottom Hole Locations
Oak Flat (10)
Frankel A (5)
Thornbury (10/5)
Coldwater Tests
“X”
SANDS ISOCHORE (Thickness)
Type Log for
Frankel A Wells
Seneca Resources
Sespe Field –
2012 Drill Plan Builds Upon 2011 Successes
350’
Thick
(Medium Blue)
800’
Thick
(Dark Red)
~550’
Thick
(Green)
1 Mile
2012 Sespe Plans
6 Wells Planned (2 5-acre infill wells)
Estimated EURs: 140-170 MBoe/Well

May 6-8, 2012
Seneca Resources
35
Monterey Shale Play
Monterey Shale Play
Belridge Field
5 AMIs across the field
Seneca WI:   12.5%
Seneca NRI:  11.1%
Producing (Gross):  50 BOPD
3-4 Delineation Wells Planned
AMI Outlines
Gross Thickness of Monterey Interval

May 6-8, 2012
Seneca Resources
36
Expansive Pennsylvania Acreage Position
SRC Lease Acreage
SRC Fee Acreage
Eastern Development Area
Net Acreage: 55,000 acres
Mostly leased (16-18% royalty)
No near-term lease expiration
First large expiration: 2018
Ongoing development drilling
in Tioga and Lycoming Counties
Western Development Area
Net acreage:
690,000 acres
Own most mineral rights
Minimal
royalty obligation
Minimal
lease expiration
Evaluating Marcellus rich-gas 
and Utica Shale potential
EOG Acreage

May 6-8, 2012
Seneca Resources
37
Net Rig Count (Working Interest)
Fiscal 2013 rig count
range depends on
participation in
EOG JV wells

May 6-8, 2012
Seneca Resources
38
Ramping Marcellus Shale Production

May 6-8, 2012
Seneca Resources
39
Eastern Development Area (EDA) –
Results & Plan Forward
SRC Lease Acreage
SRC Fee Acreage
DCNR Tract 595
FY2012: 1 Rig Operating
FY2013: 0-1 Rigs Operating
Production: 45 MMcf per Day
Covington –
Fully Developed
47 Wells Drilled and Producing
Production: 85 MMcf per Day
DCNR Tract 100
8 Wells Drilled
FY2012 & FY2013: 1-2 Rigs Operating
First Production:  Late May 2012
First Well Test: 15.8 MMcf per Day
DCNR Tract 001
Expiration Date:  January 2020
Minimum Wells to Hold Acreage:  24
DCNR Tract 007
Expiration Date:  January 2020
Minimum Wells to Hold Acreage:  33

May 6-8, 2012
Seneca Resources
40
Evaluating Marcellus Wet Gas Potential
More than 100,000 acres within the targeted
window of 1,100 Btu to 1,200 Btu
Will need cryogenic processing plant running in
“ethane rejection mode”
processing
Potential $0.50 -
$0.70 per Mcf uplift from sale
of NGLs (excluding Ethane)
SRC Lease Acreage
SRC Fee Acreage
EOG Acreage
Owl’s Nest (2 Wells)
Church Run (1 Well)
Proposed  Hz Well

May 6-8, 2012
41
Chesapeake
9.5 MMCFD
1,425 BLPD
Chesapeake
3.8 MMCFD
980 BLPD
Chesapeake
3.1 MMCFD
1,015 BLPD
Dry
Wet
Hess
11 MMCFD
Utica Shale –
Activity Summary
Seneca Resources
Vertical Well Drilled
Horizontal Well Permit
Horizontal Well Drilled
Mt. Jewett
Vertical:  Tested Dry Gas
Horizontal:  Prep to Complete
Henderson
Vertical Well
Tionesta
Horizontal: Drilling
Owl’s Nest
Horizontal FY2013
Chesapeake
6.4 MMCFD
Rex
9.2 MMCFD

May 6-8, 2012
Seneca Resources
42
Increased California Spending with Ongoing Marcellus Cuts
(1)
Does not include the $34.9 MM acquisition of Ivanhoe’s U.S.-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

May 6-8, 2012
Seneca Resources
43
Production Still Growing

May 6-8, 2012
National Fuel Gas Company
44
Appendix

May 6-8, 2012
National Fuel Gas Company
45
Manageable Debt Maturity Schedule

May 6-8, 2012
National Fuel Gas Company
46
Targeted Capital Structure
Long-Term Consolidated
Capital Structure Target
Capital Structure
Targets by Segment

May 6-8, 2012
Pipeline & Storage / Midstream
47
Appendix

May 6-8, 2012
Pipeline & Storage
48
Expansion Initiatives
Project Name
Capacity
(Dth/D)
Est.
CapEx
In-Service
Market
Status
Lamont Compressor Station
40,000
$6 MM
6/2010
Fully Subscribed
Completed
Lamont Phase II Project
50,000
$7.6 MM
7/2011
Fully Subscribed
Completed
Line “N”
Expansion
160,000
$22 MM
10/2011
Fully Subscribed
Completed
Tioga County Extension
350,000
$56 MM
11/2011
Fully Subscribed
Completed
Northern Access Expansion
320,000
~$71 MM
~11/2012
Fully Subscribed
Currently under construction
Line “N”
2012 Expansion
164,000
~$36 MM
~11/2012
Fully Subscribed
Currently under construction
Line “N”
2013 Expansion
30,000
~$4 MM
11/2013
OS Concluded
Negotiating with an anchor shipper for all
capacity
Mercer Expansion Project
150,000
~$30 MM
~6/2014
OS Concluded
In discussions with an anchor shipper for
all capacity
Central Tioga County
Extension
~250,000
~$135 MM
2014/2015
OS Concluded
In discussions with an anchor shipper
West to East
~425,000
~$290 MM
~2015
29% Subscribed
Marketing continues with producers in
various stages of exploratory drilling
Total Firm Capacity:  ~1,939,000 Dth/D
Capital Investment: ~$658 MM

May 6-8, 2012
Midstream Corporation
49
Expansion Initiatives
Project Name
Capacity
(Mcf/D)
Est.
CapEx
In-Service
Date
Market
Comments
Covington Gathering System
220,000
$54 MM
Multiple
Phases -
Most
In-Service
Fully Subscribed
Completed
–
Flowing into TGP 300
Line.  This includes $32 million of
spending to build pipeline and
compression needed to connect
future wells.
Trout Run Gathering System
466,000
$130 MM
May 2012
70% Subscribed
Under construction. This includes
spending to build pipeline and
compression needed to connect
future wells. 
Mt. Jewett Gathering System
170,000
$22 MM
FY2013
Fully Subscribed
Preliminary work underway
Owl’s Nest Gathering System
50,000
$17 MM
FY2014
Fully Subscribed
Preliminary work underway.  Any
processing costs would be
incremental. 
Total Firm Capacity:  ~906,000 Mcf/D
Capital Investment: ~$223 MM
The relative increase in spending on these projects from prior guidance is a result of a shift in
spending on certain gathering infrastructure from Seneca to NFG Midstream, which will now
handle the future build out of compression and well lines previously associated with Seneca.

May 6-8, 2012
Exploration & Production
50
Appendix

May 6-8, 2012
National Fuel Gas Company
51
Hedge Positions and Strategy
Natural Gas
Swaps
Volume
(Bcf)
Average
Hedge Price
Fiscal 2012
(1)
17.5
$5.89 / Mcf
Fiscal 2013
38.9
$4.97 / Mcf
Fiscal 2014
19.5
$4.34 / Mcf
Oil Swaps
Volume
(MMBbl)
Average
Hedge Price
Fiscal 2012
(1)
0.8
$77.03 / Bbl
Fiscal 2013
1.5
$92.52 / Bbl
Fiscal 2014
0.6
$95.68 / Bbl
Most hedges executed at sales point to eliminate basis risk
(1)
Fiscal 2012 hedge positions are for the remaining six months of the fiscal year
Seneca has hedged approximately 46% of its remaining
forecasted production for Fiscal 2012 

May 6-8, 2012
Marcellus Shale
52
Western Development Area (WDA) –
Results & Plan Forward
SRC Lease Acreage
SRC Fee Acreage
EOG Contributed JV Acreage
SRC Contributed JV Acreage
Seneca Operated
EOG Operated
Approx. Outline of JV Acreage
200,000 Gross Acres
Seneca 50% W.I. (Avg. 58% NRI)
Punxy (EOG Operated)
68 Wells Drilled; 39 Producing
FY2012: 2 Rigs Operating (Drill 33 wells)
Gross Production: ~54 MMcf per Day
Owl’s Nest
Drilled 3 Horizontal Wells
Acquiring 3D Seismic
Potential 2013 Wet Gas Development
Expected IPs: 4-5 MMcf per Day
Mt. Jewett
Drilled 3 Horizontal Wells
IPs: 2.4 -
3.1 MMcf per Day
Boone Mountain
Drilled 3 Horizontal Wells
IPs: 3.8 -
4.6 MMcf per Day
Rich Valley
1 Well to be completed
in FY2012 2Q
Church Run
FY2012: 1 Well 
To Test EUR & BTU Content

May 6-8, 2012
Marcellus Shale
53
Expanding 3D Seismic Coverage
Completed
In Progress
Punxy
West  Branch
Mt. Jewett
DCNR 001
DCNR 007
Covington
DCNR 595
DCNR 100
Owl’s Nest

May 6-8, 2012
Marcellus Shale
54
Covington
Typecurve
–
6.7
Bcfe
EUR
(Greater
Than
3,500’
Lateral)

May 6-8, 2012
Marcellus Shale
55
Targeting Continued Cost Reductions

May 6-8, 2012
Marcellus Shale
56
Breaking Down Our Acreage Position
Area
Net Acres
Possible
Locations
Wells Drilled
Wells
Completed
EUR (Bcfe)
Status
Eastern Development Area (EDA)
Covington
7,000
47
47
47
5.5
Developed
595
6,000
55
29
13
7.0
Full Development
100
10,000
70
12
1
8.0
Full Development
007
15,000
75
1
1
3.0 -
5.0
Delineating
001
13,000
58
1
1
3.0 -
5.0
Delineating
Other EDA
4,000
10
-
-
3.0 -
8.0
Untested
55,000
315
90
63
Western Development Area (WDA)
Owl's Nest / Ridgeway
91,000
680
4
4
4.0
Waiting on Development
Mt. Jewett
25,000
232
4
4
3.0 
Delineating
James City
30,000
340
1
1
3.0 -
5.0
Delineating
Boone Mtn
8,500
59
4
4
4.0
Waiting on Development
Rich Valley
30,000
188
1
-
4.0 -
5.0
Delineating
WDA Other
337,000
2,654
4
3
2.0 -
6.0
Untested
521,500
4,153
18
16
EOG Operated
Punxy
12,000
87
72
39
4.0
Full Development
West Branch
12,500
121
9
5
3.0 -
5.0
Delineating
Clermont
10,000
96
2
2
3.0 -
5.0
Delineating
Brady
13,500
113
-
-
4.0 -
5.0
Untested
EOG Other
120,500
502
2
2
2.0 -
5.0
Untested
168,500
919
85
48
Seneca Resources Total
745,000
5,387
193
127

May 6-8, 2012
Marcellus Shale
57
Water Management Program
Water Sourcing:
Coal mine runoff
Permitted freshwater sources
Recycled water
Water Management:
Instituted a “Zero Surface Discharge”
policy
Recycle Marcellus flowback and produced water
Centralized water handling in development areas
Tioga County –
DCNR 595 and Covington
Lycoming County –
DCNR 100
Elk County -
Owl’s Nest
Installing new evaporative technology
Investigating underground injection
Seneca is committed to protecting the surface from any type of pollution

May 6-8, 2012
Marcellus Shale
58
“Zero Liquid Discharge Operation”
Utilizing a state-of-the-art evaporative technology to ensure no liquid is
discharged at the surface
Building centrally located units in the Western Development Area
(WDA)
and the Eastern Development Area (EDA)
Removes all liquids from the production stream
Has the ability to be powered by the waste heat from a compressor station
End products:
Non-hazardous solidified salt material
Clean water vapor emissions

May 6-8, 2012
National Fuel Gas Company
59
Comparable GAAP Financial Measure Slides and Reconciliations
This presentation contains certain non-GAAP financial measures.  For pages
that contain non-GAAP financial measures, pages containing the most directly
comparable GAAP financial measures and reconciliations are provided in the
slides that follow. 
The Company believes that its non-GAAP financial measures are useful to
investors because they provide an alternative method for assessing the
Company’s operating results in a manner that is focused on the performance
of the Company’s ongoing operations.  The Company’s management uses
these non-GAAP financial measures for the same purpose, and for planning
and forecasting purposes.  The presentation of non-GAAP financial measures
is not meant to be a substitute for financial measures prepared in accordance
with GAAP. 

Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures

($ Thousands)

 

     FY 2009     FY 2010     FY 2011     FY 2012 Forecast    FY 2013 Forecast

Capital Expenditures from Continuing Operations

            

Exploration & Production Capital Expenditures

    $ 188,290      $ 398,174      $ 648,815      $610,000-690,000    $450,000-550,000

Pipeline & Storage Capital Expenditures - Expansion

      52,504        37,894        129,206      $135,000-165,000    $30,000-50,000

Utility Capital Expenditures

      56,178        57,973        58,398      $55,000-60,000    $55,000-60,000

Marketing, Corporate & All Other Capital Expenditures

      9,829        7,311        17,767      $100,000-130,000    $75,000-125,000
  

 

 

    

 

 

    

 

 

    

 

   

 

Total Capital Expenditures from Continuing Operations

    $ 306,801      $ 501,352      $ 854,186      $900,000-1,045,000    $610,000-785,000

Capital Expenditures from Discountinued Operations

            

All Other Capital Expenditures

      216      $ 150      $ —        $—      $—  
  

 

 

    

 

 

    

 

 

    

 

   

 

Plus (Minus) Accrued Capital Expenditures

            

Exploration & Production FY 2011 Accrued Capital Expenditures

    $ —        $ —        $ (63,460 )    $—      $—  

Pipeline & Storage FY 2011 Accrued Capital Expenditures

      —          —          (7,271 )    —      —  

All Other FY 2011 Accrued Capital Expenditures

      —          —          (1,389 )    —      —  

Exploration & Production FY 2010 Accrued Capital Expenditures

      —          (55,546 )      55,546      —      —  

Exploration & Production FY 2009 Accrued Capital Expenditures

      (9,093 )      9,093        —        —      —  

Pipeline & Storage FY 2008 Accrued Capital Expenditures

      16,768        —          —        —      —  

All Other FY 2009 Accrued Capital Expenditures

      (715 )      715        —        —      —  
  

 

 

    

 

 

    

 

 

    

 

   

 

Total Accrued Capital Expenditures

    $ 6,960      $ (45,738 )    $ (16,574 )    $—      $—  

Eliminations

    $ (344 )    $ —        $ —        $—      $—  
  

 

 

    

 

 

    

 

 

    

 

   

 

Total Capital Expenditures per Statement of Cash Flows

    $ 313,633      $ 455,764      $ 837,612      $900,000-1,045,000    $610,000-785,000
  

 

 

    

 

 

    

 

 

    

 

   

 

Reconciliation of Exploration & Production West Division EBITDA to Exploration & Production Segment Net Income

($ Thousands)

 

     6 Months Ended
March 31, 2012		  

Exploration & Production - West Division EBITDA

    $ 118,341   

Exploration & Production - All Other Divisions EBITDA

      68,866   
  

 

 

  

Total Exploration & Production EBITDA

    $ 187,207   

Minus: Exploration & Production Net Interest Expense

      (11,825 ) 

Minus: Exploration & Production Income Tax Expense

      (39,053 ) 

Minus: Exploration & Production Depreciation, Depletion & Amortization

      (83,822 ) 
  

 

 

  

Exploration & Production Net Income

    $ 52,507   

Exploration & Production Net Income

    $ 52,507   

Exploration & Production - West Division Production (MBoe)

      1,703   
  

 

 

  

Exploration & Production - Net Income per West Division Production (Boe)

    $ 30.84   

Exploration & Production - West Division EBITDA

    $ 118,341   

Exploration & Production - West Division Production (MBoe)

      1,703   
  

 

 

  

Exploration & Production - West Division EBITDA per West Division Production (Boe)

    $ 69.50   

Reconciliation of EBITDA to Net Income

($ Thousands)

 

     FY 2008     FY 2009     FY 2010     FY 2011     12 Months Ended
March 31, 2012		  

Exploration & Production - West Division EBITDA

    $ 188,008      $ 170,611      $ 187,838      $ 187,603      $ 217,180   

Exploration & Production - All Other Divisions EBITDA

      174,216        109,100        139,624        189,854        161,651   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

  

Total Exploration & Production EBITDA

    $ 362,224      $ 279,711      $ 327,462      $ 377,457      $ 378,831   

Exploration & Production EBITDA

    $ 362,224      $ 279,711      $ 327,462      $ 377,457      $ 378,831   

Utility EBITDA

      161,575        164,443        167,328        168,540        155,457   

Pipeline & Storage EBITDA

      129,171        130,857        120,858        111,474        116,965   

Energy Marketing EBITDA

      8,699        11,589        13,573        13,178        7,419   

Corporate & All Other EBITDA

      (8,156 )      (5,575 )      2,429        (2,960 )      716   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

  

Total EBITDA

    $ 653,513      $ 581,025      $ 631,650      $ 667,689      $ 659,388   

Total EBITDA

    $ 653,513      $ 581,025      $ 631,650      $ 667,689      $ 659,388   

Minus: Net Interest Expense

      (62,555 )      (81,013 )      (90,217 )      (75,205 )      (74,978 ) 

Plus: Other Income

      7,164        8,200        3,638        6,706        6,621   

Minus: Income Tax Expense

      (167,672 )      (52,859 )      (137,227 )      (164,381 )      (139,792 ) 

Minus: Depreciation, Depletion & Amortization

      (169,846 )      (170,620 )      (191,199 )      (226,527 )      (238,901 ) 

Minus: Exploration & Production Impairment

        (182,811 )       

Plus/Minus: Income/(Loss) from Discontinued Operations, Net of Tax

      1,821        (2,776 )      6,780        —          —     

Plus: Gain on Sale of Unconsolidated Subsidiaries

      —          —          —          50,879        —     

Plus/Minus: Income/(Loss) from Unconsolidated Subsidiaries

      6,303        3,366        2,488        (759 )      —     

Minus: Impairment of Investment in Partnership

      —          (1,804 )          —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

  

Net Income

    $ 268,728      $ 100,708      $ 225,913      $ 258,402      $ 212,338