8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): January 30, 2015

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

New Jersey	1-3880	13-1086010
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

6363 Main Street, Williamsville, New York	14221
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (716) 857-7000

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

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

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01 Regulation FD Disclosure.

On January 30, 2015, National Fuel Gas Company (the “Company”) updated its Investor Presentation. A copy of the presentation is furnished as part of this Current Report as Exhibit 99.

Neither the furnishing of the presentation as an exhibit to this Current Report nor the inclusion in such presentation of any reference to the Company’s internet address shall, under any circumstances, be deemed to incorporate the information available at such internet address into this Current Report. The information available at the Company’s internet address is not part of this Current Report or any other report filed or furnished by the Company with the Securities and Exchange Commission.

In addition to financial measures calculated in accordance with generally accepted accounting principles (“GAAP”), the presentation furnished as part of this Current Report as Exhibit 99 contains certain non-GAAP financial measures. The Company believes that such 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, for measuring the Company’s cash flow and liquidity, and for comparing the Company’s financial performance to other companies. 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.

Certain statements contained herein or in the materials furnished as part of this Current Report, including statements regarding estimated future earnings and statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will” and “may” and similar expressions, are “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. There can be no assurance that the Company’s projections will in fact be achieved nor do these projections reflect any acquisitions or divestitures that may occur in the future. While the Company’s expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis, actual results may differ materially from those projected in forward-looking statements. Furthermore, each forward-looking statement speaks only as of the date on which it is made. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: 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, title disputes, 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; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; governmental/regulatory actions, initiatives and proceedings, including those

involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; changes in the price of natural gas or oil; changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; delays or changes in costs or plans with respect to Company 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; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; 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 other 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 major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; significant differences between the Company’s projected and actual capital expenditures and operating expenses; changes in laws, 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; 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. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

Exhibit 99 Investor Presentation dated January 2015

SIGNATURES

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

NATIONAL FUEL GAS COMPANY
By:	/s/ James R. Peterson
	James R. Peterson
	Assistant Secretary

Dated: January 30, 2015

EXHIBIT INDEX

Exhibit Number	Description
99	Investor Presentation dated January 2015

EX-99

National Fuel Gas Company

Investor Presentation

January 2015

Exhibit 99

National Fuel Gas Company

Safe Harbor For Forward Looking Statements

2

This presentation may contain “forward-looking statements”

as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects,

plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated

capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules,

and

possible

outcomes

of

litigation

or

regulatory

proceedings,

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 are expressed

in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be

achieved or accomplished.

In addition to other factors, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the

forward-looking statements:  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, title disputes, 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;

the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; changes in laws, regulations or

judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real

property, and exploration and production activities such as hydraulic fracturing; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases

(which address, among other things, target rates of return, rate

design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure,

and franchise renewal; changes in the price of natural gas or oil; changes in price differentials between similar quantities of natural gas or oil sold at different geographic

locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; other changes in price

differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; impairments under the SEC’s full cost ceiling

test for natural gas and oil reserves;  uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for

natural

gas

or

oil;

delays

or

changes

in

costs

or

plans

with

respect

to

Company

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; changes in demographic patterns and weather

conditions; changes in the availability, price or accounting treatment of derivative financial instruments; 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 other 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 major accidents, fires, severe weather, natural disasters,

terrorist activities, acts of war, cyber attacks or pest infestation; significant differences between the Company’s projected and actual capital expenditures and operating expenses;

changes in laws, 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; 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 other 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, 2014 and the Form 10-Q for the quarter ended December 31, 2014. The Company disclaims

any

obligation 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

Our Business Mix Leads to Long-Term Value Creation

3

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.

Upstream

Natural Gas

Seneca Resources

Corporation

(West Division)

Seneca Resources

Corporation

(East Division)

The strategic, operational and financial benefits, along with capital

integrated mix of businesses continue to create significant

long-term value for the Company’s shareholders in nearly all

economic and commodity price scenarios

         flexibility and consistent growth opportunities, generated by this

NFG’s Unique Integration

4

NFG’s concentrated geographical footprint

differentiates our integrated structure and drives

distinct shareholder value creation opportunities

Common Geographic Footprint

FINANCIAL EFFICIENCIES

National Fuel Gas Company

Regulated Operations Provide Significant Synergies

5

OPERATIONAL SYNERGIES

Utility segment and Pipeline and Storage

segment share common:

COMMERCIAL RELATIONSHIPS

Utility segment and Energy Marketing segment

collectively hold 32% of Pipeline & Storage

contracted firm transportation and 46% of its

contracted storage capacity

•

Investment grade credit rating

•

Shared borrowing capacity

•

Consolidated tax return

•

Diversified cash flows support dividend

•

Management

•

Engineering services

•

Field labor

•

Facilities

•

Back office

•

Dispatch center

•

Materials warehouse

•

IT systems

•

Vehicles

•

Tools & equipment

Integration significantly reduces

operational and financing costs

and enhances the Company’s

navigate through volatile markets

and execute its long-term growth

strategy

            financial strength and flexibility to

National Fuel Gas Company

Upstream and Midstream –

Common Vision For Growth

6

Western Development Area

Tier I Acreage: 200,000 Acres

High quality

Marcellus acreage

Connected to our

interstate pipeline

network

Pipeline capacity to premium

and alternate markets

Northern Access Projects

490 MMcf/d to Canada by 2016

Clermont Gathering System

NFG Supply & Other Interconnects

The Company has a well-defined strategy to increase long-term value

Integrated model provides significant benefits in variety of market conditions

Creating sustainable value for shareholders remains our #1 priority

NFG Focused on Long-Term Value

7

•

Utility is a vital contributor to the consolidated financial strength of the Company

•

Regulated cash flows provide stability in challenging commodity price environment

•

Strong,

coordinated

emphasis

on

our

considerable

upstream

and

midstream

growth opportunities in Appalachia

•

We regularly evaluate structural alternatives as part of our ongoing assessment

of our strategic direction

•

We firmly believe our current strategy best positions us to deliver long-term

value to investors

National Fuel Gas Company

What Makes NFG Unique, Also Maximizes Value

8

Foundation of

Our Appalachian

Growth Strategy

Operational

Synergies

Strategic

Commercial

Relationships

Financial

Efficiencies

High Quality Assets

+ Lower Cost of Capital

+ Lower Operating Costs

+ Efficient Capital Spend

+ More Competitive Projects

+ Higher Free Cash Flow

+ Growing Dividend

National Fuel Gas Company

Targeting Sustained EBITDA Growth over the next Five Years

9

Exploration & Production Segment

Gathering Segment

Pipeline & Storage Segment

Utility Segment

Energy Marketing & Other

$0

$250

$500

$750

$1,000

$1,250

$327

$377

$397

$492

$539

$539

$632

$668

$704

$852

$953

$963

$167

$169

$160

$165

$163

$121

$111

$137

$161

$186

$187

$30

$64

$73

2010

2011

2012

2013

2014

TTM

12/31/14

Fiscal Year

$172

Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation.

National Fuel Gas Company

Capital Spending Adjusts to Capitalize on Opportunities

10

Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.

$1,500

$1,250

$1,000

$750

$500

$250

$0

2010

2011

2012

2013

2014

2015E

$501

$854

$977

$717

$970

$990 -

1,155

$115-$130

$89

$72

$58

$58

$58

$38

$129

$144

$80

$55

$56

$138

$140

$125-$175

$225-$275

$525-$575

$603

533

$694

$649

$398

Exploration & Production Segment

Gathering Segment

Pipeline & Storage Segment

Utility Segment

Energy Marketing & Other

Fiscal Year

National Fuel Gas Company

Maintaining a Strong Balance Sheet

11

Total Debt

(1)

41%

$4.4 Billion

As of December 31, 2014

Debt/Adjusted EBITDA

Capitalization

Note:  A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation.

(1)

Long-term debt of $1.649 billion and short-term debt of $172.9 million

1.98 x

1.75 x

1.89 x

1.89 x

1.77 x

1.80 x

0.0

0.5

1.0

1.5

2.0

2.5

2010

2011

2012

2013

2014

TTM

12/31/14

Fiscal Year

Shareholders’

Equity

59%

National Fuel Gas Company

Dividend Track Record

12

(1)

As of  January 26, 2015

$2.00

$1.50

$1.00

$0.50

$0.00

Annual Rate at Fiscal Year End

Dividend Consistency

Consecutive Dividend Payments

Consecutive Dividend Increases

Current Annualized Dividend Rate

112 Years

44 Years

$1.54 per Share

Current

Dividend

Yield

(1)

2.3%

13

Exploration & Production

Overview

(1)

Represents a three-year average U.S. finding and development cost

Fiscal

Years

3-Year

F&D Cost

(1)

($/Mcfe)

2007-2009

$5.35

2008-2010

$2.37

2009-2011

$2.09

2010-2012

$1.87

2011-2013

$1.67

2012-2014

$1.38

45.2

43.3

42.9

41.6

38.5

428

675

988

1,300

1,683

700

935

1,246

1,549

1,914

0

500

1,000

1,500

2,000

2010

2011

2012

2013

2014

At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

2014 F&D Cost = $1.15

Marcellus F&D: $1.00

327% Reserve

Replacement Rate

73% Proved Developed

Seneca Resources

Proven Record of Growth

14

Seneca Resources

Delivering Tremendous Production Growth

15

225

150

75

0

2010

2011

2012

2013

2014

2015E

Fiscal Year

49.6

67.6

83.4

120.7

160.5

155-190

13.3

16.5

19.8

19.2

20.5

20.0

21.2

21-23

43.2

62.9

100.7

139.3

134-167

Gulf of Mexico (Divested in 2011)

East Division

West Division

Seneca Resources

Disciplined Capital Spending  

16

$28

$47

$63

$105

$83

$40-$50

$356

$596

$631

$428

$520

$485-

$525

$398

$649

$694

$533

$603

$525-

$575

$0

$200

$400

$600

$800

$1,000

2010

2011

2012

2013

2014

2015E

Fiscal Year

Gulf of Mexico (Divested in 2011)

East Division

West Division

Seneca Resources

LOE: Operating Costs down; Transportation Costs up

17

(1)

Represents the midpoint of current General & Administrative Expense guidance of $0.40 to $0.45 per Mcfe for fiscal 2015

(2)

The total of the two LOE components represents the midpoint of current LOE guidance of $1.00 to $1.10 per Mcfe for fiscal 2015

(3)

The cost of firm transportation is reflected in price realizations (a deduction to gross revenues). As such, it is not included in LOE.

(2)

$4.00

$3.00

$2.00

$1.00

$0.00

2010

2011

2012

2013

2014

2015E

$2.23

$2.09

$2.01

$1.74

$1.65

$1.65

Property, Franchise & Other Taxes

Other O&M Expense

General & Administrative Expense

Lease Operating & Transportation Expense (Gathering Only)

Lease Operating & Transportation Expense (Excl. Gathering)

(3)

Fiscal Year

$0.64

$0.73

$0.65

$0.52

$0.40

$0.43

$0.17

$0.24

$0.34

$0.46

$0.51

$1.17

$0.91

$0.76

$0.65

$0.57

$0.54

(1)

(2)

$0.21

$0.18

$0.28

$0.14

$0.13

$0.10

Marcellus Shale

Prolific Pennsylvania Acreage

18

720,000

Acres

60,000

Acres

Average net revenue interest (NRI): 98%

No lease expiration

No royalty on most acreage

Highly contiguous

Significant economies of scale

1,700 to 2,000 locations de-risked

Seneca Lease

Seneca Fee

Mostly leased (16-18% royalty)

No near-term lease expiration

Limited development drilling until firm

transportation capacity on Atlantic

Sunrise becomes available in late 2017

Drilling activity will HBP key acreage

Eastern

Development

Area

(EDA)

Western

Development

Area

(WDA)

Marcellus Shale

EDA Delivering Significant Growth

19

Covington

–

Fully

Developed

DCNR Tract 595

DCNR Tract 100

Gamble

(1)

One well included in this total is drilled into and producing from the Geneseo Shale

DCNR Tract 007

Utica & Marcellus delineation wells

Results expected 1H FY2015

Productive Capacity:  ~45MMcf per Day

47 Wells Drilled and Producing

Productive Capacity: ~115 MMcf per Day

45

Wells

Drilled

(52

Total

Locations)

44

Wells

Producing

Productive Capacity:  ~380 MMcf per Day

58

Wells

Drilled

(70

Total

Locations)

58

Wells

Producing

Opportunity for Geneseo development

30 to 50 future locations

3 Wells Drilled; 1 Well Producing

Opportunity for Geneseo development

(1)

(1)

(1)

(1)

Marcellus Shale

EDA –

Historical Well Results are Exceptional

20

Development Area

Producing

Well Count

Average

IP Rate

(MMcf/d)

Average

7-Day

(MMcf/d)

Average

30-Day

(MMcf/d)

Average

EUR

per Well

(Bcf)

Average

Lateral

Length

EUR per

1,000’

of

Lateral

(Bcfe)

Covington

Tioga

County

47

5.2

4.7

4.1

5.8

4,023’

1.44

Tract 595

Tioga

County

43

(1)

7.4

6.1

5.2

8.1

4,765’

1.70

Tract 100

Lycoming

County

57

(1)

16.8

14.8

12.6

12.6

5,270’

2.39

(1)

Does not include a well drilled into and producing from the Geneseo Shale

Marcellus Shale

Focusing on WDA Development

21

Note: Assumes 6,000’

treated lateral length

Seneca’s Tier I Acreage:

200,000 Acres

6-8 Bcfe EUR Wells

Economic

at

$2.60

to

$4.00/MMbtu

4 -

6 BCF/well

6 -

8 BCF/well

4 -

6 BCF/well

2-4 BCF/well

2-4 BCF/well

SRC Fee Acreage

SRC Lease Acreage

EOG Earned JV Acreage

Marcellus Shale

Strong Wells Currently Producing Across WDA Acreage

22

Area

Producing Well

Count

Peak  24-Hour

Rate (MMcfd)

Average

7-Day (MMcf/d)

Average Treatable

Lateral Length (ft)

Clermont/Rich Valley

Elk, Cameron & McKean

counties

19

8.1

7.2

5,710’

WDA Development Areas:

WDA Delineation Areas:

Area

Producing Well

Count

Peak  24-Hour

Rate (MMcfd)

Average

7-Day (MMcf/d)

Average Treatable

Lateral Length (ft)

Ridgway

Elk County

1

7.1

6.4

5,537’

Church Run

Elk & Jefferson counties

2

4.8

4.5

4,690’

Hemlock

Elk County

2

5.4

5.2

7,067’

Owl’s Nest

Elk & Forest counties

1

6.1

5.8

6,137’

Sulger Farms

Jefferson County

1

6.1

5.6

5,778’

Marcellus Shale

Clermont/Rich Valley (CRV) Area

23

Planned Wells

Drilled Wells

Producing Wells

Pad H

6 Wells

Ave. IP: 8.0 MMCFD

Pad N

9 Wells

Ave. IP: 8.2 MMCFD

Clermont/Rich Valley

200-250

Planned

Horizontal

Locations

Productive

Capacity:

19

Wells;

~

60

MMcfd

Pad C8-F

Completing

Pad C8-G

Drilling

Pad D9-D

6 Wells

Completed

SRC Lease Acreage

SRC Fee Acreage

Marcellus Faults

Marcellus & Basement Faults

Marcellus Shale

~2,000 Economic WDA Locations Below $4/MMBtu

24

Prospect

Product

Locations

Remaining to

Be Drilled

Completed

Lateral

Length (ft)

EUR

Assumption

(MMcf)

BTU

$4.50

Dawn/Nymex

(% IRR)

$4.00

Dawn/Nymex

(% IRR)

15% IRR

Realized Price

DCNR 100

Dry Gas

13

5,582

13,540

1030

>100%

74%

$1.84

Gamble

Dry Gas

28

4,605

11,240

1030

72%

50%

$2.08

DCNR 595

Dry Gas

8

4,475

6,890

1030

46%

33%

$2.28

Clermont - Rich Valley

Dry Gas

148

7,000

7,817

1050

42%

28%

$2.60

Hemlock

Dry Gas

157

7,000

7,000

1050

35%

24%

$2.78

Ridgway

Dry Gas

564

7,000

6,300

1111

31%

21%

$2.90

Remaining Tier 1

Dry Gas

1,020

7,000

6,000

1030 - 1100

$3.00 -

$4.00

Future Resource

Dry & Wet

Gas

1,620

7,000

6,000

1030 - 1350

>$4.00

Additional Delineation Required

(1)

(1)

Internal Rate of Return (IRR) includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect.

Marcellus Shale

WDA Mineral Interests Significantly Enhance Returns

25

In Clermont/Rich Valley, a typical producer burdened by a

15%

royalty

would

require

a

$0.46

higher

net

realized

price 

to achieve same level of economics as Seneca Resources

(1)

Clermont/Rich Valley Example

($/Mcf)

Typical

Producer

15% Royalty

Average Net Realized Price

$ 3.06

Less: Cash Operating Expenses

(0.65)

Less: Royalty Payment

(0.46)

Cash Margin

$ 1.95

Before Tax IRR

(1)

15%

The Seneca

Advantage

0% Royalty

$ 2.60

(0.65)

(0.00)

$ 1.95

15%

Internal Rate of Return (IRR) includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect.

Natural Gas Marketing

How Does Seneca Sell its Production?

26

Well Head

Interconnection

with Interstate

Pipeline Network

Gathering

System

3rd Party

Marketer

(or spot market)

Firm Transport

Demand Center

(firm sales or

spot market)

Contracted Basis

Differential

FT Rate

Breakeven economics based on a

realized price after gathering

Spot Market

Natural Gas Marketing

Adding Long-Term Firm Transport to the Portfolio

27

(1)

A

large majority of the  executed firm sales agreements continue for the remainder of the firm transportation contract term.

Project

(Counterparty)

In-

Service

Date

Contract

Term

Delivery

Market

FT Capacity (Dth/day)

Matched Firm

Sales

Fiscal

2015

Fiscal

2016

Fiscal

2017

Fiscal

2018

Northeast Supply

Diversification

Project (TGP)

Nov.

2012

15 years

Canada

50,000

50,000

50,000

50,000

Executed Contracts

50,000 Dth/d

for 10 years

Niagara

Expansion/

TETCO (TGP & NFG)

Nov.

2015

15 years

Canada/

TETCO

---

170,000

170,000

170,000

Executed Contracts

140,000 Dth/d

for 15 years

Northern Access

2016 (NFG/

TransCanada/

Union)

Nov.

2016

15 years

Canada

---

---

350,000

350,000

Evaluating

marketing

opportunities

Atlantic Sunrise

(Transco)

Nov.

2017

15 years

Mid-

Atlantic/

Southeast

---

---

---

189,405

Executed Contracts

189,405 Dth/d

for first 5 years

(1)

Total Firm Transportation Capacity

50,000

220,000

570,000

759,405

Natural Gas Marketing

Significant Base of Long-Term Firm Contracts

28

Atlantic Sunrise

189,405 Dth/d

Northern Access 2016

350,000 Dth/d

Niagara Expansion

TETCO

170,000 Dth/d

1,000

750

500

250

-

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

Base Firm Sales Contracts

Firm Sales Matched to Firm Transport Capacity

Additional Firm Transport Capacity

Fiscal Year

Natural Gas Marketing

Firm Sales Provide a Market for Appalachian Production

29

Values shown represent the price or differential to a reference

price (netback price) at the first non-affiliated interstate pipeline,

including the cost of all related downstream transportation

29

EDA

(1)

320,098 Dth/d

280,036 Dth/d

280,036 Dth/d

WDA

(1)

61,427 Dth/d

60,000 Dth/d

60,000 Dth/d

Dominion

95,327

Less: $0.42

Dominion

85,000

Less: $0.47

Dominion

85,000

Less: $0.47

NYMEX

236,198

Less: $0.51

NYMEX

205,036

Less: $0.59

NYMEX

205,036

Less: $0.59

50,000

Fixed $3.77

50,000

Fixed $3.77

50,000

Fixed $3.77

381,525

340,036

340,036

0

100,000

200,000

300,000

400,000

500,000

Fixed Price

NYMEX

Dominion South Point

(1)

EDA and WDA carry an average net revenue interest (NRI) of 82% - 84% and 98%, respectively.

Q2

FY 2015

Q3

FY 2015

Q4

FY 2015

Natural Gas Marketing

Current Natural Gas Hedge Positions

30

(1)

For the remaining nine months of fiscal 2015.

100

75

50

25

0

2015

2016

2017

2018

Fiscal Year

68.7

65.7

46.8

5.6

18.6

18.8

12.7

NYMEX

Dominion

Dawn & MichCon

SoCal

14.5

5.6

49.1

32.4

23.1

11.0

Natural Gas Marketing

FY 2015 Production –

Firm Sales & Hedge Composition

31

(1)

Spot price assumptions reflected in fiscal 2015 earnings guidance range

(2)

Indicates firm sales not backed by financial hedges

Firm Sales with Price Certainty

76.5 Bcf at ~$3.70/Mcf

Spot Price Exposure

27 Bcf at $2.00-$2.25/Mcf

(1)

2.7 Bcf

(2)

1.7 Bcf

(2)

42.9 Bcf

47.4 Bcf

18 Bcf

11.1 Bcf

8.6 Bcf

18.6 Bcf

134-167 Bcf

0

100

150

200

Q1                                          

East Division

Production

NYMEX

Firm Sales

DOM

Firm Sales

Fixed Price

Sales

WDA

Spot Sales

EDA                      Total

Spot Sales

East Division

Production

50

Utica Shale

Seneca Activity in Tioga County

32

Seneca -

Tionesta

Horizontal: Completed Fall 2012

Peak 24-Hour Rate: 3.9 MMcf/d

Seneca -

Mt Jewett

Horizontal: Completed September 2013

Peak 24-Hour Rate: 8.5 MMcf/d

Seneca -

DCNR 007

Completing

Shell

26 MMcf/d

Shell

11 MMcf/d

California

Stable Production Fields; Modest Growth Potential

33

East Coalinga

Temblor Formation

Primary

North Lost Hills

Tulare & Etchegoin Formation

Primary/Steamflood

South Lost Hills

Monterey Shale

Primary

North Midway Sunset

Tulare & Potter Formation

Steamflood

South Midway Sunset

Antelope Formation

Steamflood

Sespe

Sespe Formation

Primary

Key Areas of Focus in 2015:

(1) LTM reflects the twelve month period ending 12/31/2014.

North

Midway

Sunset

South

Midway

Sunset

South Lost

Hills

North Lost

Hills

Sespe

East

Coalinga

1.

South Midway Sunset Extensions

2.

East Coalinga Evaluation

3.

South Lost Hills Monterey Evaluation

California

South Midway Sunset Has Delivered Significant Growth

34

252 Pool

97X Pool

SE Pool

251 Pool

B Pool

A Pool

Extended Pool Boundary

Original Pool Boundary

Existing Wells

1000’

16X Pool

Seneca Acquired

in June 2009

Highlights Since Acquisition

Significantly increased daily production

Drilled 114 new producers

Added 3.3 MMBO of proven reserves

Increased steam capacity by 420%

Identified opportunities for additional

pool development

California

East Coalinga Summary

35

Production has increased from 214 BOPD to

750 BOPD

Drilled 31 new producers and 1 water

disposal well in 2014

Plan to drill 5 wells in 2015

Evaluating potential of undeveloped Upper

Temblor heavy oil reservoir in Section 28

Seneca Acquired

in January 2013

California

Evaluating the Monterey Shale at South Lost Hills

Citrus 11

Upper Antelope A

Upper Antelope B

McDonald

Truman 1H

2013

190 BOEPD

Citrus 2H

2014

100 BOEPD

Truman 2H

Currently

Installing

Artificial Lift

GR

SP

ResD

Brittleness

Gas

Oil

18 potential locations in

each of the three

horizons (concept)

Seneca Lease

Lower Reef Ridge

1000’

36

California

Modest Growth Opportunities, But Strong Economics

37

Field

Average

Well Cost

Average

EUR

(MBO)

Estimated

IRR

@$55/Bbl

Fiscal 2015

Locations

South Midway Sunset

$250,000

39

57%

36

North Midway Sunset

$300,000

30

25%

15

East Coalinga

$420,000

29

15%

5

California

Modest Growth Anticipated in 2015

38

9,056

8,773

9,322

9,078

9,699

9,800-

10,200

7,000

8,000

9,000

10,000

11,000

2010

2011

2012

2013

2014

2015     

Forecast

Fiscal Year

California

Strong Margins Support Significant Free Cash Flow

39

Average Revenue

for TTM 12/31/14

$84.26 per BOE

$12.98

$4.77

$3.99

$3.15

$1.72

$57.65

Non-Steam Fuel LOE

Steam Fuel

G&A

Production & Other Taxes

Other Operating Costs

EBITDA

12-months ended 12/31/14 EBITDA 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.

40

Midstream Businesses

Overview

Midstream Businesses

Positioned to Serve Rapidly Growing Production in Appalachia

41

Gathering

Gathering is the First Step to Reaching a Market

42

TGP 300

Transco

Trout Run

Gathering System

(In-Service)

Covington

Gathering System

(In-Service)

Clermont

Gathering System

(In-Service)

Gathering Interconnects

(1)

Fiscal 2015 estimated revenue reflects projected throughput based on the range of Seneca’s Fiscal 2015 production guidance (155-190 Bcfe)

(1)

$34.8

$70.6

$75 -

$95

$0

$30

$60

$90

$120

2010

2011

2012

2013

2014

2015E

Fiscal Year

Gathering Segment Revenue

Gathering

Gathering Systems Supporting Seneca’s EDA Production

43

Covington Gathering System

In-Service Date: November 2009

Capacity: 220,000 Dth per day

Interconnect: TGP 300

Capital Expenditures (to date): $32 Million

Trout Run Gathering System

In-Service Date: May 2012

Capacity: 466,000 to 585,000 Dth per day

Interconnect: Transco

–

Leidy Lateral

Capital Expenditures (to date): $162 Million

Interconnects

(1)

Fiscal 2015 estimated throughput reflects the midpoint  of Seneca’s Fiscal 2015 production guidance range (155-190 Bcfe)

(1)

2010

2011

2012

2013

2014

2015E

Covington

Trout Run

0

25

50

75

100

125

150

7.0

30.9

44.7

51.0

48.3

41

5.3

45.0

103

87.4

Fiscal Year Throughput by Project

(Covington & Trout Run Systems)

Gathering

Clermont Gathering System has Large Expandability

44

Clermont Gathering

System

In-Service:  July 2014

Ultimate Trunkline Capacity:         

1+ Bcf per day

Interconnects

TGP 300 (current)

NFG Supply Corporation

(Northern Access 2016)

Capital Expenditures:

To date: $115 Million

2015

(1)

: $95 -

$135 Million

Compressor Station

Interconnect

(1)

For the remaining nine months of fiscal 2015.

Pipeline & Storage

Project Opportunities to Support Appalachian Growth

45

Develop multiple outlets

to high-value markets

Pipeline & Storage

Expansions to Move Gas from the WDA Are Significant

46

Projects to Support WDA Growth

Project

Capacity

(Dth/day)

Northern Access 2015

140,000

Northern Access 2016

350,000

Total New Capacity

490,000

Project

Capital Cost

Northern Access 2015

$66 Million

Northern Access 2016

$449 Million

Total Capital

Expenditures

$515 Million

Northern

Access 2015

(November 2015)

Northern

Access 2016

(Late 2016)

Pipeline & Storage

Major Expansion Designed for Canadian Deliveries

47

Customer: Seneca Resources

In-Service: November 2015

System: NFG Supply Corp.

Capacity: 140,000 Dth per day

Lease to TGP as part of their

Niagara Expansion project

Interconnect

Niagara (TransCanada)

Total Cost: $66 Million

Major Facilities

23,000 HP Compression

Northern Access 2015

Northern

Access 2015

(November 2015)

Pipeline & Storage

Northern Access 2016 Provides Additional Access to Canada

48

Customer: Seneca Resources

In-Service: Late 2016

System: NFG Supply Corp. &

Empire Pipeline, Inc.

Capacity

350,000 Dth per day

Interconnect

Chippawa (TransCanada)

Total Cost: ~$449 Million

FERC Timing

Pre-filing: July 2014

Certificate filing: anticipated

Q2 FY2015

Northern Access 2016

Northern

Access 2016

(Late 2016)

Pipeline & Storage

Recent 3

rd

Party Expansions Have Been Highly Successful

49

Completed Expansions

for 3

Parties

Capacity (Dth/day)

Northern Access 2012

320,000

Tioga County Extension

350,000

Line N & Mercer Expansion

458,000

Total New Capacity

1,128,000

Capital Cost ($Millions)

Northern Access 2012

$72

Tioga County Extension

$58

Line N & Mercer Expansion

$138

Total Capital Expenditures

$268

Northern

Access 2012

Tioga County

Extension

Line N Projects

Annual Reservation Charges ($Millions)

Northern Access 2012

$14.5

Tioga County Extension

$41.9

Line N & Mercer Expansion

$21.3

Total Reservation Charges

$77.7

rd

Mercer

(TGP Station 219)

Pipeline & Storage

Pairing Line N Expansions with System Modernization

50

In-Service: November 2015

System: NFG Supply Corp.

Capacity: 175,000 Dth per day

Range Resources (145,000 Dth/d)

Seneca Resources (30,000 Dth/d)

Interconnect

Mercer (TGP Station 219)

Holbrook (TETCO)

Total Cost: $86 Million

Expansion: $45 Million

Modernization: $41 Million

Major Facilities

3,550 HP Compressor

23.3 miles –

24”

Replacement Pipe

Westside Expansion &

Modernization

Holbrook (TETCO)

Westside

Expansion &

Modernization

Pipeline & Storage

Developing Unique Solutions for Shippers

51

In-Service: November 2015

System: NFG Supply & Empire Pipeline

New No-Notice Services

Precedent agreements executed with

RG&E, NYSEG & NFG Utility

Preserving 172,500 Dth per day (RG&E)

Preserving 20,000 Dth per day (NYSEG)

Retained Storage: 3.3 Bcf

New incremental transportation

capacity of 49,000 Dth per day

Interconnect

Tuscarora (NFG/Supply)

Total Cost: $58.5 Million

Major Facilities

1,384 HP Compressor

17 miles –

12”/16”

Pipeline

Tuscarora Lateral

Tuscarora

Lateral

Pipeline & Storage

Significant Expansions Are Driving Growth

52

Completed Projects (Since 2009)

Recent Capacity

Additions

1,128,000 Dth/day

Planned Projects (2015+)

Precedent Agreements Executed

Total Expansion (2009-2016+)

Capacity

Additions

1,932,000 Dth/day

In-Service 2015

364,000 Dth/day

In-Service 2016+

350,000 Dth/day

Delivering Gas North

Tioga County Extension

Northern Access 2012

Northern Access 2015

Northern Access 2016

Total Capacity

1,160 MDth/d

Other Projects

Lamont Compressor

Tuscarora Lateral

Total Capacity

139 MDth/d

Line N Corridor

Line “N”

Expansion

Line “N”

2012 Expansion

Line “N”

2013 Expansion

Mercer Expansion

West Side Expansion

Total Capacity

633 MDth/d

53

Utility

Overview

Utility

New York & Pennsylvania Service Territories

54

Revenue Decoupling

Weather Normalization

Low Income Rates

90/10 Sharing (Large Customers)

Rates Unchanged

9.1% ROE Confirmed

2-Tier Earnings Sharing Mechanism

9.5% to 10.5% -

Share 50%

10.5% > -

Share 80%

$8.2 MM CapEx -

system replacement

Low Income Rates

Merchant Function Charge

NY PSC Rate Case Settlement, May 2014

Natural Gas Vehicle Pilot Program

Total Customers: 213,500

Rate Mechanisms:

ROE: Black Box Settlement (2007)

Rate Mechanisms:

Total Customers: 524,300

Merchant Function Charge (Uncollectibles

Adjustment)

$8.0 MM incremental O&M (post-

retirement benefits)

New York

Pennsylvania

Utility

Shifting Trends in Customer Usage

55

Residential Usage

Industrial Usage

(1)

Weighted Average of New York and Pennsylvania service territories (assumes normal weather)

80

90

100

110

120

15

20

25

30

35

12-Months Ended December 31

12-Months Ended December 31

Utility

A Proven History of Controlling Costs

56

$154

$152

$152

$152

$151

$154

$13

$16

$16

$20

$33

$31

$14

$11

$9

$6

$10

$10

$181

$179

$177

$178

$193

$195

$0

$100

$150

$200

$250

2010

2011

2012

2013

2014

12 Months

Ended

Fiscal Year

All Other O&M Expenses

O&M Pension Expense

O&M Uncollectible Expense

$50

12/31/14

Utility

Strong Commitment to Safety

57

The Utility remains focused on maintaining the ongoing

safety and reliability of its system

Near-term increase due

to ~$60MM upgrade of

the Utility’s Customer

Information System and

~$25MM NRG Dunkirk

power plant project

$45.0

$44.3

$43.8

$48.1

$49.8

$58.0

$58.4

$58.3

$72.0

$88.8

$115 -

$130

$0

$30

$60

$90

$120

$150

2010

2011

2012

2013

2014

2015E

Fiscal Year

Capital Expenditures for Safety

Total Capital Expenditures

58

Appendix

National Fuel Gas Company

Natural Gas Hedge Positions

59

(Volumes in thousands Mmbtu; Prices in $/Mmbtu)

Fiscal 2015

(1)

Fiscal 2016

Fiscal 2017

Fiscal 2018

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

NYMEX Swaps

49,130

$4.18

32,350

$4.24

23,130

$4.50

5,550

$4.59

Dominion

Swaps

18,630

$3.74

18,840

$3.78

12,720

$3.87

-

-

SoCal Swaps

900

$4.35

-

-

-

-

-

-

MichCon

Swaps

-

-

9,000

$4.10

3,000

$4.10

-

-

Dawn Swaps

-

-

5,490

$4.36

7,950

$4.14

-

-

Fixed Price

Physical Sales

13,650

$3.77

18,300

$3.77

18,250

$3.77

1,550

$3.77

Total

82,310

$4.01

83,980

$4.03

65,050

$4.11

7,100

$4.41

(1)

For the remaining nine months of fiscal 2015.

National Fuel Gas Company

Crude Oil Hedge Positions

60

Fiscal 2015

(1)

Fiscal 2016

Fiscal 2017

Fiscal 2018

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Midway

Sunset

(MWSS)

Swaps

108,000

$92.10

36,000

$92.10

-

-

-

-

Brent

Swaps

765,000

$98.32

933,000

$95.18

384,000

$92.30

75,000

$91.00

NYMEX

Swaps

297,000

$90.14

300,000

$86.09

-

-

-

-

Total

1,170,000

$95.67

1,269,000

$92.95

384,000

$92.30

75,000

$91.00

(Volumes & Prices in Bbl)

(1)

For the remaining nine months of fiscal 2015.

Geneseo Shale

Path to Geneseo Development –

2018/2019 Start

61

1   Well (Tract 100 –

Pad N)

Peak IP: 14.1 MMcf per day

30-Day Average Rate: 8.6 MMcf per day

Estimated EUR: 7.0 Bcf

Lateral Length: 4,920’

Frac Stages: 33 stages

Current developed infrastructure from DCNR

100 & Gamble:

13 well pads

3 compressor pads

3 water impoundments

Gathering infrastructure

Savings estimate of ~$300,000 per well from

shared infrastructure

•

>125 Wells

•

Water Infrastructure = $13MM

•

Usable Pads = $16MM

•

Road Infrastructure = $16MM

Tract 100/Gamble (Lycoming County)

Geneseo Well

st

National Fuel Gas Company

Comparable GAAP Financial Measure Slides and Reconciliations

62

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 ongoing operating results, for measuring the Company’s cash flow

and liquidity, and for comparing the Company’s financial performance to

other companies. 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. 

The Company defines Adjusted EBITDA as reported GAAP earnings before the

following items: interest expense, depreciation, depletion and amortization,

interest and other income, impairments, items impacting comparability and

income taxes.

63

Reconciliation of Adjusted EBITDA to Consolidated Net Income

($ Thousands)

FY 2010

FY 2011

FY 2012

Exploration & Production - West Division Adjusted EBITDA

187,838

$           

187,603

$           

226,897

$           

215,042

$              

217,150

$              

206,875

$        

Exploration & Production - All Other Divisions Adjusted EBITDA

139,624

189,854

170,232

277,341

322,322

332,332

Total Exploration & Production Adjusted EBITDA

327,462

$           

377,457

$           

397,129

$           

492,383

$              

539,472

$              

539,207

$        

Total Adjusted EBITDA

Exploration & Production Adjusted EBITDA

327,462

$           

377,457

$           

397,129

$           

492,383

$              

539,472

$              

539,207

$        

Pipeline & Storage Adjusted EBITDA

120,858

111,474

136,914

161,226

186,022

186,799

Gathering Adjusted EBITDA

2,021

9,386

14,814

29,777

64,060

73,437

Utility Adjusted EBITDA

167,328

168,540

159,986

171,669

164,643

162,779

Energy Marketing Adjusted EBITDA

13,573

13,178

5,945

6,963

10,335

12,359

Corporate & All Other Adjusted EBITDA

408

(12,346)

(10,674)

(9,920)

(11,078)

(11,515)

Total Adjusted EBITDA

631,650

$           

667,689

$           

704,114

$           

852,098

$              

953,454

$              

963,066

$        

Total Adjusted EBITDA

631,650

$           

667,689

$           

704,114

$           

852,098

$              

953,454

$              

963,066

$        

Minus: Net Interest Expense

(90,217)

(75,205)

(82,551)

(89,776)

(90,107)

(88,818)

Plus:  Other Income

6,126

5,947

5,133

4,697

9,461

10,416

Minus: Income Tax Expense

(137,227)

(164,381)

(150,554)

(172,758)

(189,614)

(189,349)

Minus: Depreciation, Depletion & Amortization

(191,199)

(226,527)

(271,530)

(326,760)

(383,781)

(393,414)

Plus/Minus: Income/(Loss) from Discontinued Operations, Net of Tax (Corp. & All Other)

6,780

-

-

-

-

-

Plus: Gain on Sale of Unconsolidated Subsidiaries (Corp. & All Other)

-

50,879

-

-

-

-

Plus: Elimination of Other Post-Retirement Regulatory Liability (P&S)

-

-

21,672

-

-

-

Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P)

-

-

(6,206)

-

-

-

Minus: New York Regulatory Adjustment (Utility)

-

-

-

(7,500)

-

-

Rounding

-

-

(1)

-

-

-

Consolidated Net Income

225,913

$           

258,402

$           

220,077

$           

260,001

$              

299,413

$              

301,901

$        

Consolidated Debt to Total Adjusted EBITDA

Long-Term Debt, Net of Current Portion (End of Period)

1,049,000

$        

899,000

$           

1,149,000

$        

1,649,000

$          

1,649,000

$          

1,649,000

$     

Current Portion of Long-Term Debt (End of Period)

200,000

150,000

250,000

-

-

-

Notes Payable to Banks and Commercial Paper (End of Period)

-

40,000

171,000

-

85,600

172,900

Total Debt (End of Period)

1,249,000

$        

1,089,000

$        

1,570,000

$        

1,649,000

$          

1,734,600

$          

1,821,900

$     

Long-Term Debt, Net of Current Portion (Start of Period)

1,249,000

1,049,000

899,000

1,149,000

1,649,000

1,649,000

Current Portion of Long-Term Debt (Start of Period)

-

200,000

150,000

250,000

-

-

Notes Payable to Banks and Commercial Paper (Start of Period)

-

-

40,000

171,000

-

-

Total Debt (Start of Period)

1,249,000

$        

1,249,000

$        

1,089,000

$        

1,570,000

$          

1,649,000

$          

1,649,000

$     

Average Total Debt

1,249,000

$        

1,169,000

$        

1,329,500

$        

1,609,500

$          

1,691,800

$          

1,735,450

$     

Average Total Debt to Total Adjusted EBITDA

1.98 x

1.75 x

1.89 x

1.89 x

1.77 x

1.80 x

FY 2013

12-Months

Ended 12/31/14

FY 2014

64

Reconciliation of Segment Capital Expenditures to

Consolidated Capital Expenditures

($ Thousands)

FY 2015

FY 2010

FY 2011

FY 2012

FY 2013

FY 2014

Forecast

Capital Expenditures from Continuing Operations

Exploration & Production Capital Expenditures

398,174

$   

648,815

$   

693,810

$   

533,129

$   

602,705

$   

$525,000-575,000

Pipeline & Storage Capital Expenditures

37,894

129,206

144,167

56,144

$     

139,821

$   

$225,000-275,000

Gathering Segment Capital Expenditures

6,538

17,021

80,012

54,792

$     

137,799

$   

$125,000-175,000

Utility Capital Expenditures

57,973

58,398

58,284

71,970

$     

88,810

$     

$115,000-130,000

Energy Marketing, Corporate & All Other Capital Expenditures

773

746

1,121

1,062

$        

772

$           

-

Total Capital Expenditures from Continuing Operations

501,352

$   

854,186

$   

977,394

$   

717,097

$   

969,907

$   

$990,000-1,155,000

Capital Expenditures from Discountinued Operations

All Other Capital Expenditures

150

$           

-

$            

-

$            

-

$            

-

$            

-

$                               

Plus (Minus) Accrued Capital Expenditures

Exploration & Production FY 2014 Accrued Capital Expenditures

-

$            

-

$            

-

$            

-

$            

(80,108)

$    

Exploration & Production FY 2013 Accrued Capital Expenditures

-

-

-

(58,478)

58,478

-

Exploration & Production FY 2012 Accrued Capital Expenditures

-

-

(38,861)

38,861

-

-

Exploration & Production FY 2011 Accrued Capital Expenditures

-

(103,287)

103,287

-

-

-

Exploration & Production FY 2010 Accrued Capital Expenditures

(78,633)

78,633

-

-

-

-

Exploration & Production FY 2009 Accrued Capital Expenditures

19,517

-

-

-

-

-

Pipeline & Storage FY 2014 Accrued Capital Expenditures

-

-

-

-

(28,122)

Pipeline & Storage FY 2013 Accrued Capital Expenditures

-

-

-

(5,633)

5,633

-

Pipeline & Storage FY 2012 Accrued Capital Expenditures

-

-

(12,699)

12,699

-

-

Pipeline & Storage FY 2011 Accrued Capital Expenditures

-

(16,431)

16,431

-

-

-

Pipeline & Storage FY 2010 Accrued Capital Expenditures

-

3,681

-

-

-

-

Pipeline & Storage FY 2008 Accrued Capital Expenditures

-

-

-

-

-

-

Gathering FY 2014 Accrued Capital Expenditures

-

-

-

-

(20,084)

Gathering FY 2013 Accrued Capital Expenditures

-

-

-

(6,700)

6,700

-

Gathering FY 2012 Accrued Capital Expenditures

-

-

(12,690)

12,690

-

-

Gathering FY 2011 Accrued Capital Expenditures

-

(3,079)

3,079

-

-

-

Gathering FY 2009 Accrued Capital Expenditures

715

-

-

-

-

-

Utility FY 2014 Accrued Capital Expenditures

-

-

-

-

(8,315)

Utility FY 2013 Accrued Capital Expenditures

-

-

-

(10,328)

10,328

-

Utility FY 2012 Accrued Capital Expenditures

-

-

(3,253)

3,253

-

-

Utility FY 2011 Accrued Capital Expenditures

-

(2,319)

2,319

-

-

-

Utility FY 2010 Accrued Capital Expenditures

-

2,894

-

-

-

-

Total Accrued Capital Expenditures

(58,401)

$    

(39,908)

$    

57,613

$     

(13,636)

$    

(55,490)

$    

-

$                               

Eliminations

-

$            

-

$            

-

$            

-

$            

-

$            

-

$                               

Total Capital Expenditures per Statement of Cash Flows

443,101

$   

814,278

$   

1,035,007

$

703,461

$   

914,417

$   

$990,000-1,155,000