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): November 7, 2014

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 November 7, 2014, 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 November 2014

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: November 7, 2014

EXHIBIT INDEX

Exhibit Number	Description
99	Investor Presentation dated November 2014

EX-99

National Fuel Gas Company

Investor Presentation

November 2014

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, 2013 and the Forms 10-Q for the quarters ended December 31, 2013, March 31, 2014 and June

30, 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

Quality Assets -

Exceptional Location -

Unique Integration

3

1.914 Tcfe of Proved Reserves

(1)

811,000 Net Acres in Pennsylvania

3 Million Bbls of Crude Oil Production

(2)

$250 Million of Midstream Adjusted EBITDA

(2)(3)

(1)

As of September 30, 2014

(2)

Fiscal year ended September 30, 2014.  Midstream includes the Pipeline & Storage segment and Gathering segment.

(3)

A

reconciliation

of

Adjusted

EBITDA

to

Net

Income

is

included

at

the

end

of

this

presentation.

National Fuel Gas Company

Upstream and Midstream –

Common Vision For Growth

4

Western Development Area

Tier I Acreage: 200,000 Acres

Clermont Gathering System

NFG Supply & Other Interconnects

Northern Access Projects

490 MMcf/d to Canada by 2016

High quality

Marcellus acreage

Connected to our

interstate pipeline

network

Pipeline capacity to premium

and alternate markets

National Fuel Gas Company

Regulated Operations Provide Significant Synergies

5

National Fuel Gas Company

What Makes NFG Unique, Also Maximizes Value

6

Foundation of

Our Appalachian

Growth Strategy

National Fuel Gas Company

Targeting Sustained EBITDA Growth over the next Five Years

2015 –

2019

10-15%

Forecasted

Adjusted EBITDA

CAGR

$164

$167

$169

$160

$172

$165

$131

$121

$111

$137

$161

$186

$64

$280

$327

$377

$397

$492

$539

$581

$632

$668

$704

$852

$953

$0

$250

$500

$750

$1,000

$1,250

2009

2010

2011

2012

2013

2014

2019E

Fiscal Year

Exploration & Production Segment

Gathering Segment

Pipeline & Storage Segment

Utility Segment

Energy Marketing & Other

7

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

8

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

(1)

Does not include the $34.9 MM Seneca Resources Corporation’s 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 the Exploration & Production segment’s Capital Expenditures.

National Fuel Gas Company

Maintaining a Strong Balance Sheet

9

Total Debt

(1)

42%

$4.1 Billion

As of September 30, 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 $85.6 million

National Fuel Gas Company

Dividend Track Record

10

Dividend Consistency

Consecutive Dividend Payments

112 Years

Consecutive Dividend Increases

44 Years

Current Annualized Dividend Rate

$1.54 per Share

(1) As of November 5, 2014

11

Exploration & Production

Overview

Seneca Resources

Proven Record of Growth

12

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

(1)

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

2014 F&D Cost = $1.15

Marcellus F&D: $1.00

327% Reserve

Replacement Rate

73% Proved Developed

Seneca Resources

Delivering Tremendous Production Growth

13

Disciplined Capital Spending

14

$31

$28

$47

$63

$105

$83

$55-$80

$139

$356

$596

$631

$428

$520

$545

-

$620

$188

(1)

$398

$649

$694

$533

$603

$600-$700

$0

$200

$400

$600

$800

$1,000

2009

2010

2011

2012

2013

2014

2015E

Fiscal Year

Gulf of Mexico (Divested in 2011)

East Division

West Division

Seneca Resources

(1)

Does not include the $34.9 MM Seneca Resources Corporation’s 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 the Exploration & Production segment’s Capital Expenditures.

Seneca Resources

LOE: Operating Costs down; Transportation Costs up

15

(1)

Represents the midpoint of current General & Administrative Expense guidance of $0.35 to $0.40 per Mcfe for fiscal 2015

(2)

The total of the two LOE components represents the midpoint of current LOE guidance of $0.95 to $1.05 per Mcfe for fiscal 2015

Seneca matches its long-term firm transport

(FT) contracts with firm sales (FS)

agreements, with the cost of transportation

reflected in price realization.  As such, it is

not included in LOE.

Marcellus Shale

Prolific Pennsylvania Acreage

16

Eastern Development Area (EDA)

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

Western Development Area (WDA)

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

720,000 Acres

60,000 Acres

Marcellus Shale

EDA Delivering Significant Growth

17

Covington –

Fully Developed

Gross Production:  ~45MMcf per Day

47 Wells Drilled and Producing

DCNR Tract 595

Gross Production: ~90 MMcf per Day

45 Wells Drilled

(1)

(52 Total Locations)

38 Wells Producing

DCNR Tract 100

Gross Production:  ~410 MMcf per Day

58 Wells Drilled

(2)

(70 Total Locations)

53 Wells Producing

(2)

Opportunity for Geneseo development

Gamble

30 to 50 future locations

3 Wells Drilled; 1 Well Producing

Opportunity for Geneseo development

(1)

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

(2)

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

Marcellus Shale

EDA –

Historical Well Results are Exceptional

18

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

38

7.2

6.0

5.2

8.0

4,716’

1.70

Tract 100

Lycoming

County

52

(1)

17.0

14.9

12.7

12.6

5,304’

2.38

(1)

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

Marcellus Shale

Focusing on WDA Development

19

SRC Lease Acreage

SRC Fee Acreage

EOG Earned JV Acreage

Note: Assumes 6,000’

treated lateral length

Seneca’s Tier I Acreage:

200,000 Acres

6-8 Bcfe EUR Wells

Economic at $2.80 to $3.80/Mcfe

Marcellus Shale

Strong Wells Currently Producing Across WDA Acreage

20

Area

Producing

Well Count

Peak

24-Hour Rate

(MMcfd)

Average

7-Day (MMcf/d)

Average Treatable

Lateral Length

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

Ridgway

Elk County

1

7.1

6.4

5,537’

Church Run

Elk & Jefferson counties

2

4.8

4.5

4,690’

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

Marcellus Faults

Marcellus & Basement Faults

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

FY 2014 Year-end: 19 Wells; ~ 75 MMcfd

FY 2015 Fcst Year-end:~50 Wells; ~180 MMcfd

SRC Lease Acreage

SRC Fee Acreage

Pad C8-F

Completing

Pad C8-G

Drilling

Pad D9-D

6 Wells

Drilled

21

Marcellus Shale

WDA Mineral Interests Significantly Enhance Returns

22

($/Mcf)

Typical

Producer

15% Royalty

Average Net Realized Price

$ 3.27

Less: Cash Operating Expenses

(0.65)

Less: Royalty Payment

(0.47)

Cash Margin

$ 2.15

Before Tax IRR

(1)

15%

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

15% royalty would require a $0.47 higher net realized price

to achieve same level of economics as Seneca Resources

The Seneca

Advantage

0% Royalty

$ 2.80

(0.65)

(0.00)

$ 2.15

15%

(1)

Internal

Rate

of

Return

(IRR)

includes

estimated

well

costs

under

current

coststructure,

LOE,

and

Gathering

tariffs

anticipated

for

each

prospect.

Clermont/Rich Valley Example

Natural Gas Marketing

How Does Seneca Sell its Production?

23

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

24

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/TETCO)

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

(1)

A

large

majority

of

the

executed

firm

sales

agreements

continue

for

the

remainder

of

the

firm

transportation

contract

term.

Natural Gas Marketing

Significant Base of Long-Term Firm Contracts

25

Natural Gas Marketing

Firm Sales Provide a Market for Appalachian Production

26

26

EDA

(2)

318,033 Dth/d

320,036 Dth/d

280,036 Dth/d

280,036 Dth/d

WDA

(2)

58,034 Dth/d

61,100 Dth/d

60,000 Dth/d

60,000 Dth/d

(1)

Fixed price sales contracts totaling 50,000 Dth/day at an average fixed price of $3.77 per Dth starting November 2014 through October 2017

(2)

EDA

and

WDA

carryan

average

net

revenue

interest

(NRI)

of

82%

-

84%

and

98%,

respectively

Natural Gas Marketing

Current Natural Gas Hedge Positions

27

Natural Gas Marketing

Current Hedge Book has Seneca Positioned Very Well

28

(1)

Natural gas hedges include fixed price firm sales

(2)

Hedge positions reflect the midpoint of Seneca’s target annual production growth (20%) starting with the midpoint of Fiscal 2015 guidance (180-220 Bcfe)

Natural Gas

$4.01/MMBtu

$4.03/MMBtu

$4.11/MMBtu

$4.41/MMBtu

Crude Oil

$95.27/Bbl

$92.95/Bbl

$92.30/Bbl

$91.00/Bbl

Natural Gas Marketing

FY 2015 Production –

Firm Sales & Hedge Composition

29

Firm Sales with Price Certainty

108 Bcf at ~$3.70 /Mcf

Spot Price Exposure

66 Bcf at $2.50-$2.75 /Mcf

(1)

(1)

Spot price assumptions reflected in fiscal 2015 earnings guidance range

(2)

Dominion based firm sales contracts without a matching Dominion financial hedge

68.1 Bcf

24.1 Bcf

16.2 Bcf

22.0 Bcf

43.5 Bcf

4.1 Bcf

(2)

159-197 Bcf

0

50

100

150

200

NYMEX

Firm Sales

DOM

Firm Sales

Fixed

Price Sales

WDA

Spot Sales

EDA                     

Spot Sales

Total

East Division

Production

Utica Shale

Seneca Activity in Tioga County

30

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

Drilling

Shell

26 MMcf/d

Shell

11 MMcf/d

California

Stable Production Fields; Modest Growth Potential

31

California

East Coalinga Summary

32

Production has increased from 214 BOPD to

800

BOPD

•

Highest on leases since 2000

Drilled 12 evaluation wells in 2013

•

Producing ~150 BOPD

Drilled 31 new producers and 1 water

disposal well in 2014. Currently have 27 of

the new producers on line.

2014 Location

2013 Well

Active Well

Idle Well

P&A

Seneca Lease

Field Boundary

California

South Midway Sunset Has Delivered Significant Growth

33

252 Pool

97X Pool

SE Pool

251 Pool

B Pool

A Pool

Extended Pool Boundary

Original Pool Boundary

Existing Wells

1000’

16X Pool

Highlights Since Acquisition

Increased daily production 310% to

approximately 1,700 BOPD

Drilled 102 new producers

Added 3.3 MMBO of proven reserves

Increased steam capacity by 280%

Identified opportunities for additional pool

development

California

Evaluating the Monterey Shale at South Lost Hills

34

California

Modest Growth Opportunities, But Strong Economics

35

Field

Average

Well Cost

Average

EUR

(MBO)

Estimated

IRR

@$85/Bbl

Fiscal 2015

Locations

North Midway Sunset

$300,000

32

59%

29

South Midway Sunset

$300,000

38

96%

42

East Coalinga

$580,000

35

30%

25

California

Modest Growth Anticipated in 2015

36

California

Strong Margins Support Significant Free Cash Flow

37

Average Revenue

for Fiscal 2014

$87.71 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.

Seneca Resources

What Will Seneca Look Like Moving Forward?

38

Consistent Production Growth: 15-25% CAGR

Driven by a very large, high-quality Appalachian acreage position

Maintain Oil Production

Expand When Possible

Excellent operator and significant cash flow generation

Disciplined Spending Driven by Firm

Pace of development adapts to changing market dynamics

A Leader in Technology, Safety & Environmental Responsibility

Maintain a leadership role in using technology and developing best practices

39

Midstream Businesses

Overview

Midstream Businesses

Positioned to Serve Rapidly Growing Production in Appalachia

40

Gathering

Gathering is the First Step to Reaching a Market

41

Gathering

Gathering Systems Supporting Seneca’s EDA Production

42

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

Capital Expenditures (future): $30 to $70 Million

Interconnects

7.0

30.9

44.7

51.0

48.3

45-50

45.0

87.4

100-120

0

25

75

100

125

150

2010

2011

2012

2013

2014

2015E

Fiscal Year Throughput by Project

(Covington & Trout Run Systems)

Covington

Trout Run

50

5.3

Gathering

Clermont Gathering System has Large Expandability

43

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:

2014: $96 Million

2015: $110 -

$160 Million

Seneca Pads Connected

SRC Pad N (9 wells)

connected July 2014

SRC Pad H (6 wells)

connected September 2014

Up to 25 pads connected

following the 2015

expansion

Pipeline & Storage

Project Opportunities to Support Appalachian Growth

44

Pipeline & Storage

Expansions to Move Gas from the WDA Are Significant

45

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

$410 Million

Total Capital

Expenditures

$476 Million

Clermont

Northern

Access 2015

(November 2015)

Northern

Access 2016

(Late 2016)

Pipeline & Storage

Major Expansion Designed for Canadian Deliveries

46

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)

Clermont

Pipeline & Storage

Northern Access 2016 Provides Additional Access to Canada

47

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: ~$410 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

48

Completed Expansions

for 3

rd

Parties

Capacity (Dth/day)

Northern Access 2012

320,000

Tioga County Extension

350,000

Line N (2011, 2012 & 2013)

353,000

Total New Capacity

1,023,000

Capital Cost ($Millions)

Northern Access 2012

$72

Tioga County Extension

$58

Line N (2011, 2012 & 2013)

$ 104

Total Capital Expenditures

$234

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 (2011, 2012 & 2013)

$ 16.0

Total Reservation Charges

$ 72.4

Pipeline & Storage

Additional Line N Expansions

49

Customer: Third Party

Placed in-service November 1, 2014

System: NFG Supply Corp.

Capacity: 105,000 Dth per day

Precedent agreements signed for

all available capacity

Interconnect

Mercer (TGP Station 219)

Total Cost: $34 Million

Expansion: $30 Million

System Modernization: $4 Million

Major Facilities

3,550 HP Compressor

2.1 miles –

24”

Replacement

Pipeline

Mercer Expansion

Mercer

(TGP Station 219)

Mercer

Expansion

Mercer

(TGP Station 219)

Pipeline & Storage

Pairing Line N Expansions with System Modernization

50

Customer: Third Party

In-Service: November 2015

System: NFG Supply Corp.

Capacity: 175,000 Dth per day

Precedent agreements signed for

all available capacity

Interconnect

Mercer (TGP Station 219)

Holbrook (TETCO)

Total Cost: $76 Million

Expansion: $39 Million

Modernization: $37 Million

Major Facilities

3,550 HP Compressor

23.3 miles –

24”

Replacement

Pipeline

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: $45 Million

Major Facilities

1,500 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

1,113,000 Dth/day

Line N Corridor

Line “N”

Expansion

Line “N”

2012 Expansion

Line “N”

2013 Expansion

Mercer Expansion

West Side Expansion

Total Capacity

633 MDth/d

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

Planned Projects (2014+)

Precedent Agreements Executed

Total Expansion (2009-2016+)

Capacity

Additions

1,932,000 Dth/day

In-Service 2014

105,000 Dth/day

In-Service 2015

364,000 Dth/day

In-Service 2016+

350,000 Dth/day

53

Utility

Overview

Utility

New York & Pennsylvania Service Territories

54

Total Customers: 524,300

Rate Mechanisms:

Revenue Decoupling

Weather Normalization

Low Income Rates

Merchant Function Charge (Uncollectibles

Adjustment)

90/10 Sharing (Large Customers)

NY PSC Rate Case Settlement, May 2014

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

$8.0 MM incremental O&M (post-

retirement benefits)

Natural Gas Vehicle Pilot Program

Total Customers: 213,500

Rate Mechanisms:

Low Income Rates

Merchant Function Charge

ROE: Black Box Settlement (2007)

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)

Utility

A Proven History of Controlling Costs

56

Utility

Strong Commitment to Safety

57

The Utility remains focused on maintaining the

ongoing safety and reliability of its system

Near-term

increase in capital

expenditures is

due to the

approx. $60MM

upgrade of the

Utility’s Customer

Information

System (CIS)

$44.4

$45.0

$44.3

$43.8

$48.1

$49.8

$56.2

$58.0

$58.4

$58.3

$72.0

$88.8

$95-$105

$0

$20

$40

$60

$80

$100

2009

2010

2011

2012

2013

2014

2015E

Fiscal Year

Capital Expenditures for Safety

Total Capital Expenditures

National Fuel Gas Company

A History of Success & A Future of Opportunity

58

32% CAGR

Since 2010

Adjusted

EBITDA

Growth

Production

Growth

Midstream

Businesses

Adjusted

EBITDA

A History of Success

11% CAGR

Since 2010

19% CAGR

Since 2010

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

A Future of Opportunity

Adjusted

EBITDA

Growth

Production

Growth

Midstream

Businesses

Adjusted

EBITDA

10-15% CAGR

2015 to 2019

15-25% CAGR

2015 to 2019

10-15% CAGR

2015 to 2019

59

Appendix

National Fuel Gas Company

Natural Gas Hedge Positions

60

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

Fiscal 2015

Fiscal 2016

Fiscal 2017

Fiscal 2018

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

NYMEX Swaps

70,690

$4.16

32,350

$4.24

23,130

$4.50

5,550

$4.59

Dominion

Swaps

24,840

$3.74

18,840

$3.78

12,720

$3.87

-

-

SoCal Swaps

1,200

$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

16,700

$3.77

18,300

$3.77

18,250

$3.77

1,550

$3.77

Total

113,430

$4.01

83,980

$4.03

65,050

$4.11

7,100

$4.41

National Fuel Gas Company

Crude Oil Hedge Positions

61

Fiscal 2015

Fiscal 2016

Fiscal 2017

Fiscal 2018

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Midway

Sunset

(MWSS)

Swaps

258,000

$92.10

36,000

$92.10

-

-

-

-

Brent

Swaps

903,000

$98.42

933,000

$95.18

384,000

$92.30

75,000

$91.00

NYMEX

Swaps

396,000

$90.14

300,000

$86.09

-

-

-

-

Total

1,557,000

$95.27

1,269,000

$92.95

384,000

$92.30

75,000

$91.00

(Volumes & Prices in Bbl)

Marcellus Shale

Position Offers Attractive Economics at $2.00 to $3.80/Mcfe

62

Prospect

County

Product

Approx.

Remaining

Locations

EUR

(Bcfe)

BTU

IRR

(1)

@

$4/MMBtu

15% IRR

(1)

Breakeven Price

($/Mcf)

EASTERN DEVELOPMENT AREA (EDA)

Tract 100

Lycoming

Dry Gas

18

11.5-12.5

1,030

90%

$1.92

Gamble

Lycoming

Dry Gas

29

10-11

1,030

77%

$2.05

Tract 595

Tioga

Dry Gas

14

8.1

1,030

45%

$2.63

Covington

Tioga

Dry Gas

Developed

5.8

1,030

22%

$3.49

WESTERN DEVELOPMENT AREA (WDA)

Clermont/Rich Valley

Elk/Cameron

Dry Gas

213

6-8

1,050

38%

$2.80

Ridgway

Elk

Dry Gas

450-570

6-8

1,111

26%

$3.30

Hemlock

Elk

Dry Gas

130-170

6-8

1,070

23%

$3.40

Church Run

Elk

Dry Gas

60-70

6-8

1,125

22%

$3.45

(W) West Branch

McKean

Dry Gas

47

6-8

1,050

22%

$3.48

Heath

Jefferson

Dry Gas

260-330

5-8

1,060

19%

$3.65

Sulger Farms

Jefferson

Dry Gas

170-210

5-8

1,020

19%

$3.66

Owl’s Nest/James City

Elk/Forest

Dry Gas

120-160

5-8

1,125

18%

$3.69

Boone Mt.

Elk

Dry Gas

230-290

4-6

1,020

18%

$3.76

Church Run

Elk

Wet Gas

40-50

2-4

1,140

13%

$4.32

Tionesta

Forest/Venango

Wet Gas/

Liquids

300-340

4-6

1,325

12%

$4.50

Owl’s Nest/James City

Elk/Forest

Wet Gas

150-180

4-6

1,140

11%

$4.51

Mt. Jewett

McKean

Wet Gas

90-110

2-4

1,140

6%

$5.50

Beechwood

Cameron

Dry Gas

210-280

2-4

1,030

2%

$7.14

Red Hill

Cameron

Dry Gas

150-200

2-4

1,030

2%

$7.14

(1)

Internal

Rate

of

Return

(IRR)

includes

estimated

well

costs

under

current

cost

structure,

LOE,

and

Gathering

tariffs

anticipated

for

each

prospect.

Geneseo Shale

Path to Geneseo Development –

2018/2019 Start

63

1

st

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

National Fuel Gas Company

Comparable GAAP Financial Measure Slides and Reconciliations

64

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.

65

Reconciliation of Adjusted EBITDA to Consolidated Net Income

($ Thousands)

FY 2009

FY 2010

FY 2011

FY 2012

Exploration & Production - West Division Adjusted EBITDA

171,572

$           

187,838

$           

187,603

$           

226,897

$           

215,042

$              

217,150

$              

Exploration & Production - All Other Divisions Adjusted EBITDA

108,139

139,624

189,854

170,232

277,341

322,322

Total Exploration & Production Adjusted EBITDA

279,711

$           

327,462

$           

377,457

$           

397,129

$           

492,383

$              

539,472

$              

Total Adjusted EBITDA

Exploration & Production Adjusted EBITDA

279,711

$           

327,462

$           

377,457

$           

397,129

$           

492,383

$              

539,472

$              

Pipeline & Storage Adjusted EBITDA

130,857

120,858

111,474

136,914

161,226

186,022

Gathering Adjusted EBITDA

(141)

2,021

9,386

14,814

29,777

64,060

Utility Adjusted EBITDA

164,443

167,328

168,540

159,986

171,669

164,643

Energy Marketing Adjusted EBITDA

11,589

13,573

13,178

5,945

6,963

10,335

Corporate & All Other Adjusted EBITDA

(5,434)

408

(12,346)

(10,674)

(9,920)

(11,078)

Total Adjusted EBITDA

581,025

$           

631,650

$           

667,689

$           

704,114

$           

852,098

$              

953,454

$              

Total Adjusted EBITDA

581,025

$           

631,650

$           

667,689

$           

704,114

$           

852,098

$              

953,454

$              

Minus: Net Interest Expense

(81,013)

(90,217)

(75,205)

(82,551)

(89,776)

(90,107)

Plus:  Other Income

9,762

6,126

5,947

5,133

4,697

9,461

Minus: Income Tax Expense

(52,859)

(137,227)

(164,381)

(150,554)

(172,758)

(189,614)

Minus: Depreciation, Depletion & Amortization

(170,620)

(191,199)

(226,527)

(271,530)

(326,760)

(383,781)

Minus: Impairment of Oil and Gas Properties (E&P)

(182,811)

-

-

-

-

-

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

(2,776)

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)

-

Minus: Plugging and Abandonment Accrual (E&P)

-

-

-

-

-

-

Rounding

-

-

-

(1)

-

-

Consolidated Net Income

100,708

$           

225,913

$           

258,402

$           

220,077

$           

260,001

$              

299,413

$              

Consolidated Debt to Total Adjusted EBITDA

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

Total Debt (End of Period)

1,249,000

$        

1,249,000

$        

1,089,000

$        

1,570,000

$        

1,649,000

$          

1,734,600

$          

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

999,000

1,249,000

1,049,000

899,000

1,149,000

1,649,000

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

100,000

-

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)

1,099,000

$        

1,249,000

$        

1,249,000

$        

1,089,000

$        

1,570,000

$          

1,649,000

$          

Average Total Debt

1,174,000

$        

1,249,000

$        

1,169,000

$        

1,329,500

$        

1,609,500

$          

1,691,800

$          

Average Total Debt to Total Adjusted EBITDA

2.02 x

1.98 x

1.75 x

1.89 x

1.89 x

1.77 x

FY 2013

FY 2014

66

Reconciliation of Segment Capital Expenditures to

Consolidated Capital Expenditures

($ Thousands)

FY 2015

FY 2009

FY 2010

FY 2011

FY 2012

FY 2013

FY 2014

Forecast

Capital Expenditures from Continuing Operations

Exploration & Production Capital Expenditures

188,290

$   

398,174

$   

648,815

$   

693,810

$   

533,129

$   

602,705

$   

$600,000-700,000

Pipeline & Storage Capital Expenditures

52,504

37,894

129,206

144,167

56,144

$     

139,821

$   

$225,000-275,000

Gathering Segment Capital Expenditures

9,433

6,538

17,021

80,012

54,792

$     

137,799

$   

$1250,000-200,000

Utility Capital Expenditures

56,178

57,973

58,398

58,284

71,970

$     

88,810

$     

$95,000-105,000

Energy Marketing, Corporate & All Other Capital Expenditures

396

773

746

1,121

1,062

$        

772

$           

-

Total Capital Expenditures from Continuing Operations

306,801

$   

501,352

$   

854,186

$   

977,394

$   

717,097

$   

969,907

$   

$1,070,000-1,238,000

Capital Expenditures from Discountinued Operations

All Other Capital Expenditures

216

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

(9,093)

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

16,768

-

-

-

-

-

-

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)

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

6,960

$        

(58,401)

$    

(39,908)

$    

57,613

$     

(13,636)

$    

(55,490)

$    

-

$                               

Eliminations

(344)

$          

-

$            

-

$            

-

$            

-

$            

-

$            

-

$                               

Total Capital Expenditures per Statement of Cash Flows

313,633

$   

443,101

$   

814,278

$   

1,035,007

$

703,461

$   

914,417

$   

$1,070,000-1,238,000