Analyst Presentation - EQTir.eqt.com/.../doc_library/file/Analyst_Presentation__September_.pdf · Analyst Presentation ... the expected terms and structure of the proposed joint venture

Analyst Presentation

September 2014

2

EQT Corporation (NYSE: EQT)

EQT Plaza

625 Liberty Avenue, Suite 1700

Pittsburgh, PA 15222

Pat Kane - Chief Investor Relations Officer

(412) 553-7833

The Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible

reserves that a company anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to

known accumulations. We use certain terms in this presentation, such as “EUR” (estimated ultimate recovery) and total resource potential, that the SEC's rules

strictly prohibit us from including in filings with the SEC. We caution you that the SEC views such estimates as inherently unreliable and these estimates may

be misleading to investors unless the investor is an expert in the natural gas industry. We also note that the SEC strictly prohibits us from aggregating proved,

probable and possible (3P) reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.

Disclosures in this presentation contain certain forward-looking statements. Statements that do not relate strictly to historical or current facts are forward-

looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of plans,

strategies, objectives and growth and anticipated financial and operational performance of the Company and its subsidiaries, including guidance regarding the

Company’s strategy to develop its reserves; drilling plans and programs (including spacing and the number, type, average lateral length and location of wells to

be drilled); projected natural gas prices, including liquids price uplift and changes in basis; projected market mix and Permian Basin production mix; total

resource potential, reserves, EUR and expected decline curve; projected production sales volume and growth rates (including l iquids sales volume and growth

rates); internal rate of return (IRR), compound annual growth rate (CAGR), and expected after-tax returns per well; technology (including drilling and

completion techniques); projected finding and development costs, operating costs, unit costs, well costs, and gathering and transmission revenue deductions;

projected gathering and transmission volumes and growth rates; the Company’s access to, and timing of, capacity on third-party pipelines; infrastructure

programs (including the timing, cost and capacity of such programs); the timing, cost and capacity of the Ohio Valley Connector (OVC) and Mountain Valley

Pipeline (MVP) projects; the expected terms and structure of the proposed joint venture related to the MVP project, including the affiliate(s) of the Company to

own and/or operate the MVP; projected EBITDA; projected cash flows resulting from, and the value of, the Company’s general partner and limited partner

interests and incentive distribution rights in EQT Midstream Partners, including the assumptions used in making such projections; monetization transactions,

including midstream asset sales (dropdowns) to EQT Midstream Partners and other asset sales and joint ventures or other transactions involving the

Company’s assets; the amount and timing of any repurchases under the Company’s share repurchase authorization; projected capi tal expenditures; liquidity

and financing requirements, including funding sources and availability; projected operating revenue and cash flows; hedging strategy; the effects of government

regulation and litigation; the Company dividend and EQT Midstream Partners distribution amounts and rates; and tax position. These forward-looking

statements involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place

undue reliance on forward-looking statements as a prediction of actual results. The Company has based these forward-looking statements on current

expectations and assumptions about future events. While the Company considers these expectations and assumptions to be reasonable, they are inherently

subject to significant business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are

beyond the Company’s control. With respect to the proposed OVC and MVP projects, these risks and uncertainties include, among others, the ability to obtain

regulatory permits and approvals, the ability to secure customer contracts, the availability of skilled labor, equipment and materials, and, with respect to the

MVP, the risk that the parties may not consummate the joint venture. Additional risks and uncertainties that may affect the operations, performance and results

of the Company’s business and forward-looking statements include, but are not limited to, those set forth under Item 1A, “Risk Factors,” of the Company’s

Form 10-K for the year ended December 31, 2013, as updated by any subsequent Form 10-Qs. Any forward-looking statement speaks only as of the date on

which such statement is made and the Company does not intend to correct or update any forward-looking statement, whether as a result of new information,

future events or otherwise.

EQT Cautionary Statements

3

The Company uses Adjusted EQT Midstream EBITDA as a financial measure in this presentation. Adjusted EQT Midstream EBITDA is defined as EQT Midstream operating income (loss) plus depreciation and amortization expense less gains on dispositions. Adjusted EQT Midstream EBITDA also excludes EQT Midstream results associated with the Big Sandy Pipeline and Langley processing facility. Adjusted EQT Midstream EBITDA is not a financial measure calculated in accordance with generally accepted accounting principles (GAAP). Adjusted EQT Midstream EBITDA is a non-GAAP supplemental financial measure that Company management and external users of the Company’s financial statements, such as industry analysts, investors, lenders and rating agencies, use to assess: (i) the Company’s performance versus prior periods; (ii) the Company’s operating performance as compared to other companies in its industry; (iii) the ability of the Company’s assets to generate sufficient cash flow to make distributions to its investors; (iv) the Company’s ability to incur and service debt and fund capital expenditures; and (v) the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

The Company believes that the presentation of Adjusted EQT Midstream EBITDA in this presentation provides useful information in assessing the Company’s financial condition and results of operations. Adjusted EQT Midstream EBITDA should not be considered as an alternative to EQT Midstream operating income or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EQT Midstream EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect operating income. Additionally, because Adjusted EQT Midstream EBITDA may be defined differently by other companies in the Company’s industry, the Company’s definition of Adjusted EQT Midstream EBITDA will most likely not be comparable to similarly titled measures of other companies, thereby diminishing the utility of the measure. Please see slide 49 in the Appendix for a reconciliation of Adjusted EQT Midstream EBITDA to EQT Midstream operating income, its most directly comparable financial measure calculated in accordance with GAAP.

The Company is unable to provide a reconciliation of projected EBITDA to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect, timing and potential significance of certain income statement items.

Non-GAAP Measures

4

Finding and development costs (F&D costs) from all sources for

peer companies presented in this presentation are calculated as

the cost incurred, relating to natural gas and oil activities in

accordance with Financial Accounting Standards Board

Accounting Standards Codification 932 (ASC 932), divided by the

sum of extensions, discoveries and other additions; purchase of

natural gas and oil in place; and revisions of previous estimates,

as provided for years 2011 – 2013 and derived from publicly

available information filed with the SEC.

Per unit operating expenses are calculated by dividing the sum of

lease operating expenses, production taxes and the gathering and

transmission costs for equity gas, by production sales volumes

for the same period. Per unit operating expenses in the

presentation are calculated from publicly available information

filed with the SEC for the year ended December 31, 2013.

Calculations Within This Presentation

5

Extensive reserves of natural gas*

8.3 Tcfe Proved; >23 years R/P

36.4 Tcfe 3P; >100 years R/P

44 Tcfe Total Resource Potential; >120 years R/P

Proven ability to profitably develop our reserves

> 24% production sales volume growth in 2014

Industry leading cost structure

Extensive and growing midstream business

EQT Midstream Partners, LP (NYSE: EQM)

EQT is general partner and owns 36.4% equity interest

Estimated G.P. value ~$4 billion

Ongoing source of low cost capital

Approximately 60% of midstream business

Key Investment Highlights

*As of 12/31/13

6

2013 Operating Income of $654.6 million

Leading Appalachian E&P Company

8.3 Tcfe proved reserves

3.6 MM acres

10,400 pipeline miles

As of 12/31/13

7

0

200

400

600

800

1,000

1,200

1,400

1,600

Marcellus

Huron horizontal

Vertical

Marcellus Shale drilling driving growth

Production By Play

Pro

du

cti

on

MM

cf/

d

Began horizontal drilling

2006 2007 2008 2009 2010 2011 2012 2013 2014E

8

Proved Reserve Growth

Reserves By Play

36.4 Tcfe 3P reserves (as of December 31, 2013)

44 Tcfe Total Resource Potential

1,061

2,879 3,414

4,278

5,956

2,016

1,475 1,062

965

1,316

991

866 889

761

861

215

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2009 2010 2011 2012 2013

Bcfe

Upper Devonian

CBM/Other

Huron

Marcellus

4,068

5,220

6,004

8,348

5,365

Marcellus 18.5

Huron 11.5

9

Near term development focused in four areas

Marcellus Play

580,000 EQT acres

86% NRI / 80% HBP

33% “wet”

18.5 Tcfe 3P

23.9 Tcfe total resource potential

201 wells in 2014

>50% of acreage will utilize RCS

Central PA

Southwestern PA

Northern WV (Wet)

EQT acreage

Northern WV (Dry)

10

Prolific dry gas region

Marcellus Play

Southwestern PA

115,000 EQT acres

1,460 locations 209 wells online*

102 wells in 2014

4,800 foot laterals

79 acre spacing

10.0 Bcfe EUR / well 2,088 Mcfe EUR / ft. of lateral

$6.4 MM / well

> 90% of locations utilize RCS

Scotts Run Pad

8 wells

5,814’ Avg Lateral Length per well

15,407 Mcfe Avg 30-day IP per well

Pierce Pad

9 wells



Kevech Pad

6 wells



* As of 6/30/2014

Oliver West Pad

3 wells



Gallagher Pad

5 wells



EQT acreage

Producing wells

11

Enhanced economics from liquids uplift

Marcellus Play

Northern West Virginia – Wet Gas Area

90,000 EQT acres

1,060 locations 134 wells online**

73 wells in 2014

4,800 foot laterals

83 acre spacing

9.8 Bcfe EUR / well* 2,043 Mcfe EUR / ft. of lateral*

$6.4 MM / well

100% of locations utilize RCS

Producing Pads

Big 190 Pad

5 wells



PEN 16 Pad

5 wells



* Liquids converted at 6:1 Mcfe per barrel (1.8 Bcfe per well from liquids.) EUR assumes ethane rejection. Ethane recovery would result in

EUR of 12.0 Bcfe

** As of 6/30/2014

OXF160 Pad

3 wells



EQT acreage

Producing wells

12

Early stages of acreage delineation

Marcellus Play

Central Pennsylvania

80,000 EQT acres

720 locations 50 wells online*

18 wells in 2014

4,800 foot laterals

110 acre spacing


$6.4 MM / well


Frano Pad

3 wells



Gibson Pad

2 wells

6,381’ Lateral Length

8,592 Mcfe 30-day IP

* As of 6/30/2014

EQT acreage

Producing wells

13

EQT’s newest development area

Marcellus Play

Northern West Virginia – Dry Gas Area

30,000 EQT acres

300 locations 46 wells online*

8 wells in 2014

4,800 ft laterals

97 acre spacing


$6.3 MM / well


GRT26 Pad

2 wells



RSM119 Pad

6 wells



* As of 6/30/2014

Flanigan Pad

2 wells


9,417 Mcfe Avg 30-day IP per well EQT acreage

Producing wells

14

Marcellus Economics

IRR - Blended Marcellus Development Areas

Realized Price

PRICE ATAX IRR

$4.00 59%

$4.50 82%

$5.00 110%

See appendix for IRR by development area

15

Developed in conjunction with Marcellus

Upper Devonian Play

*As of 6/30/2014

Near-term Upper

Devonian testing

& development area

170,000 near-term testing

& development EQT acres

2,000 locations 22 wells online*

36 wells in 2014

4,800 foot laterals

83 acre spacing

6.1 Bcfe EUR / well* 1,274 Mcfe EUR / ft. of lateral

$5.6 MM / well

2014 drilling program to

delineate acreage position

Wetzel County

11 wells



Greene County

7 wells



EQT acreage

16

Targeting deep, high pressure rock beneath existing

development areas

Dry Utica / Point Pleasant Potential

400,000 EQT acres

3,000 locations 1 well in Q4 2014

Greene County, PA

6,400 foot lateral

13,500 feet deep

$12 - $17 MM / well

EQT acreage

17

Targeting high-return, liquid-rich acreage

Huron Play

Kentucky

120 wells

1.4 MM EQT acres 85 % Wet; 15 % Dry

10,000+ horizontal locations 900 horizontal wells online**

120 wells planned in 2014

6,000 foot laterals

1.4 Bcfe EUR / well* 230 Mcfe EUR / ft. of lateral*

$1.6 MM / well

* Liquids converted at 6:1 Mcfe per barrel (0.4 Bcfe per well from liquids). EUR assumes ethane rejection.

** As of 6/30/2014

EQT acreage

18

Stacked Horizontal Potential

Permian Basin

Howard Mitchell Nolan

Coke

Sterling

Glasscock

Reagan Irion

Tom Green

73,000 net acres 78% WI / 62% NRI

98% HBP

500 MMBOE of resource potential

Stacked Play Opportunity Upper Wolfcamp

Lower Wolfcamp

Cline

Development 1,500-1,700 horizontal locations

2014: 4 wells

2015: 20-30 wells

~$7.5 MM / well

Production mix 28% Oil, 47% NGLs, 25% Gas

Permian reserves are based on internal estimates and have not been independently audited

EQT acreage

19

0.00

1.00

2.00

3.00

4.00

EQ

T

RIC

E

CH

K

SW

N

CO

G

NF

G

XC

O

RR

C

AR

XE

C

SM

ST

R

CX

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EO

G

EG

N

NF

X

WL

L

0.00

2.00

4.00

6.00

AR

CO

G

RR

C

EQ

T

SW

N

RIC

E

NF

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R

XE

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WL

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EG

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NF

X

Industry Leading Cost Structure

$/M

cfe

$/M

cfe

3-year F&D (all sources)

Per Unit Operating Expenses

Mean = $1.68

Mean = $2.74

For the three years ended 12/31/13

Year ended 12/31/13

$0.88

$0.52

20

Liquids

Volume Growth and Marcellus Price Uplift

(1) Pricing is as of 7/17/2014 and is the 1 year forward

NYMEX and Mount Belvieu for Propane $1.06, Iso-

Butane $1.30, Normal Butane $1.26, and Pentanes

$2.07

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2008 2009 2010 2011 2012 2013 2014F

Mb

bls

Includes natural gas liquids and oil

Liquids Volume Growth

$4.10 $4.10

$0.82 $0.18

$1.55(1) $4.93

$5.84

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

Not Processed Processed$

/Mc

f

Marcellus Liquids Price Uplift (1200 Btu Gas)

NGLs (1.6 Gal/Mcf)

Btu Premium

NYMEX

21

Transmission & Storage

Gathering

Marketing

Formed MLP in 2012 (NYSE: EQM)

~60% of midstream business

Midstream Overview

EQT

Midstream

Total*

Transmission capacity (BBtu/d) 2,700

Miles of transmission pipeline 900

Marcellus gathering capacity (BBtu/d) 1,500

Miles of Marcellus gathering pipeline 100

Compression horsepower 300,000

Working gas storage (Bcf) 47

*As of 12/31/13

Legend

Transmission

Gathering

EQT Leases

Storage Pool

Marcellus

Huron

Utica

22

EQT Production sales drive EQT Midstream EBITDA growth

70% of Midstream revenues from EQT Corporation

Fixed fee contracts

Transmission contracts with 15-year weighted average life*

Minimal direct commodity exposure

Midstream Overview

¹ Pro-forma reflecting full-year impact of Jupiter acquisition

*Based on revenues as of 12/31/2013

**Excludes Big Sandy and Langley in 2008-2011; see Non-GAAP Reconciliation on slide 49

Bcfe

$M

M

EQT Corporation Adjusted EQT Midstream EBITDA**

0

100

200

300

400

500

$0

$100

$200

$300

$400

$500

2008 2009 2010 2011 2012 2013 2014E¹

EQT Midstream

EQT Midstream Partners, LP

Production Sales Volumes (Bcfe)

23

Transmission and storage

2.25 Tbtu/d current capacity

700 mile FERC-regulated

interstate pipeline

32 Bcf of working gas storage

Gathering System

Jupiter Gathering System

Highlights market valuation of

midstream assets

EQT ownership

2.0% GP interest – 1.2 MM units

34.4% LP interest – 21.3 MM units

EQT Midstream Partners, LP (NYSE: EQM)

*Based on 2014 EBITDA guidance by EQT Midstream Partners

EQM Price

per Unit

Implied EBITDA

Multiple*

Value of EQM LP

Units ($MM)

$90 21.1x $1,917

$92 21.6x $1,960

$94 22.0x $2,002

$96 22.5x $2,045

$98 23.0x $2,087

$100 23.4x $2,130

EQM Compressor Station

Equitrans Transmission

Sunrise Pipeline

Jupiter area

Equitrans Gathering

Storage Pool

EQT Acreage

Marcellus Fairway

24

EQT Midstream Partners, LP Distributions

*Forecast based on assumed $0.03 per unit quarterly distribution increase each quarter through 2019

$2.14 $2.62

$3.10 $3.58

$4.06 $4.54

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

2014E 2015E 2016E 2017E 2018E 2019E

To

tal D

istr

ibu

tio

n p

er

LP

Un

it

LP Unit Distribution GP Distribution per LP Units

$2.37

$3.31

$4.27

$5.23

$6.19

$7.15

EQM forecasting 29% per unit distribution growth in 2014*

EQM forecasting 22% per unit distribution growth in 2015*

25

EQT Midstream Partners, LP General Partner Cash Flow Valuation

Assumptions:

-$0.03 per unit quarterly distribution increase each quarter through 2019

-$75 Million of EBITDA dropped in ’15, ’16, & ’17 at 10.0x EBITDA financed 50/50 debt/equity

$0

$50

$100

$150

$200

$250

2014E 2015E 2016E 2017E 2018E 2019E

$ M

illio

ns

$14

$45

$82

$123

$194

$158

Present value of GP cash flows = $3.9 billion

2014E

Present Value of 2014-2019 470$

Present Value Terminal Value 3,435$

Present Value of GP Cash Flows 3,905$

$ Billion

3.0% 4.0% 5.0%

7.0% 4.1$ 5.3$ 7.8$

8.0% 3.2$ 3.9$ 5.1$

9.0% 2.6$ 3.1$ 3.8$ WA

CC

GP Discounted Cash Flow Sensitivity

Terminal Growth

26

EQT sold to EQT Midstream

Partners May 2014

$1.2 billion

35 mile gathering system in

Greene and Washington

Counties in Pennsylvania

10-year firm transportation

agreement

Currently 225 MMcfe/d

Additional 550 MMcfe/d by

year-end 2015

EQT Midstream Partners, LP

Jupiter Gathering System

Jupiter

Central PA

Southwestern PA

Northern WV (Wet)

Northern WV (Dry)

27

Tioga

65 MMcf/d

Pluto

60 MMcf/d

Mercury

250 MMcf/d

Saturn

225 MMcf/d

Longhorn

130 MMcf/d

Terra

80 MMcf/d

Applegate

150 MMcf/d

Jupiter*


EQT acreage

EQT Midstream

Marcellus Gathering

(MMcf/d)

2013

year-end

capacity

2014

capacity

additions

Total

capacity

after

additions

Pennsylvania 1,150 120 1,270

West Virginia 350 320 670

Total 1,500 440 1,940

NOTE: Capacity for each system represents estimated year-end 2014 capacity

2014 CAPEX

$240 MM (EQT)

$105 MM (EQM)

28

Allegheny Valley Connector

EQT acquired December 2013

200 mile FERC-regulated

interstate pipeline

450 BBtu/d capacity

15 Bcf working gas storage

~$90 MM CAPEX in 2014

~$40 MM projected annual

EBITDA

EQT Midstream

Transmission


Allegheny Valley Connector

EQT acreage

Allegheny Valley Connector Storage Field

29

Pipeline to growing demand

center in southeast US

Completed a non-binding open

season in July 2014

JV with NextEra Energy

JV to construct & own pipeline

EQT and/or EQM will be operator

2 Bcf/day capacity

1 Bcf/day committed from two

Foundation Shippers

Q4 2018 expected in-service

EQT Midstream

Mountain Valley Pipeline Project

30

Safety – Our first priority

All accidents are preventable

Company goal = zero incidents

Committed to:

The environment

Our employees and contractors

The communities where we drill and work

EQT Foundation charitable giving of >$4 million / year

More than $20 million / year in state and local taxes

Corporate Citizenship

31

Committed to operate in accordance with federal, state and

local regulations

Industry leading spill prevention plans and results

Supports the disclosure of frac fluid additives

Utilize multiple barriers to protect drinking water supplies

Pre-drilling water sampling within 2,500’ of drilling locations

Multi-well pads reduce surface impacts

Drilling and Hydraulic Fracturing

32

Extensive reserves of natural gas

Proven ability to profitably develop our reserves

Committed to maximize shareholder value by:

Accelerating the monetization of our vast reserves

Operating in a safe and environmentally responsible manner

Funding with cash flow and debt capacity

Investment Summary

33

Appendix

34

Capital Investment Summary

Excludes acquisitions

Midstream Production Distribution

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2010 2011 2012 2013 2014F

$B

$1.1 $1.2

$1.4

$1.8

$2.3

35

EQT has 580,000 total Marcellus acres

Expect to develop in four areas for several years

Active areas represent 315,000 acres and 3,540 locations

EQT has 130,000 additional acres in PA & 135,000 additional

acres in WV

Estimated 1,200 Mcfe EUR per lateral foot for wells drilled on

additional acres

Marcellus Play

Acres Within Each Core Development Area

Type curve and well cost data posted on www.eqt.com under investor relations

1Based on 4,800 laterals with lateral spacing estimates ranging from 500’ to 1,000’ 2EQT holds approximately 45,000 acres in the northern WV dry area – near-term development focused on 30,000 acres 3EQT holds approximately 160,000 acres in central PA – near-term development is focused on 80,000 acres

EUR (Mcfe) /

Lateral Foot Total Net Acres

Total Net

Undeveloped

Acres

Locations Utilizing

Reduced Cluster

Spacing Locations¹

Southwestern PA 2,088 115,000 93,000 90% 1,460

Northern WV - Wet1

2,043 90,000 75,000 100% 1,060

Northern WV - Dry² 1,747 30,000 27,000 80% 300

Central PA3

1,375 80,000 72,000 100% 720

315,000 267,000 94% 3,540

36

Marcellus Play

Type Curves by Area - 4,800’ lateral


37

Marcellus Economics

IRR - Southwestern PA

Realized Price

PRICE ATAX IRR

$4.00 79%

$4.50 119%

$5.00 171%

38

Marcellus Economics

IRR - Northern WV – Wet Gas Area

Realized Price

PRICE ATAX IRR

$4.00 111%

$4.50 141%

$5.00 176%

39

Marcellus Economics

IRR - Central PA

Realized Price

PRICE ATAX IRR

$4.00 19%

$4.50 28%

$5.00 38%

40

Marcellus Economics

IRR - Northern WV – Dry Gas Area

Realized Price

PRICE ATAX IRR

$4.00 26%

$4.50 37%

$5.00 50%

41

Upper Devonian Play

Blended Type Curve - 4,800’ lateral


42

Upper Devonian

IRR

Realized Price

PRICE ATAX IRR

$4.00 32%

$4.50 45%

$5.00 59%

43

0%

20%

40%

60%

80%

100%

120%

$3.00 $3.50 $4.00 $4.50 $5.00

Wellhead Wellhead After OpEx ATAX

Huron Play

IRR

Realized Price

PRICE ATAX IRR

$4.00 35%

$4.50 42%

$5.00 50%

44

Marcellus Capacity

Market Mix* EQT Capacity & Firm Sales

2014E 2015E

Tetco M2 48-50% 36-38%

Tetco M3 26-28% 28-30%

TCO 11-13% 9-10%

Midwest 0% 9-10%

NYMEX 11-13% 14-16%

45

Ample Financial Flexibility to Execute Business Plan

Moody’s Standard & Poor’s Fitch

Long-term debt Baa3 BBB BBB-

Outlook Stable Stable Stable

Debt ratings

Strong balance sheet

-

200

400

600

800

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

$M

M$

MM

11

166

3 0

708 700

11

774

0 10 0 0

115

Manageable debt maturities

($ thousands, except net debt / capital) June 30, 3014

$330,000 2,497,619

(1,274,265)$1,553,354

4,276,592

27%Net debt / capital

Short-term debtLong-term debtCash and cash equivalentsNet debt (total debt minus cash)

Total common stockholders' equity

46

Risk Management

Hedging

As of July 24, 2014

* The average price is based on a conversion rate of 1.05 MMBtu/Mcf

** July through December

*** For 2016, the Company also has a natural gas sales agreement for approximately 35 Bcf that includes a NYMEX

ceiling price of $4.88 per Mcf

2014** 2015 2016***

Fixed Price

Total Volume (Bcf) 114 138 64

Average Price per Mcf (NYMEX)* $ 4.36 $ 4.33 $ 4.45

Collars

Total Volume (Bcf) 12 23 –

Average Floor Price per Mcf (NYMEX)* $ 5.05 $ 5.03 $ –

Average Cap Price per Mcf (NYMEX)* $ 8.85 $ 8.97 $ –

47

Price Reconciliation

(a)NGLs and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods. Information for the three and six

months ended June 30, 2013 has been recast to reflect this conversion rate.

Three Months Ended Six Months Ended

June 30, June 30,

in thousands (unless noted) 2014 2013 2014 2013

LIQUIDS

Natural Gas Liquids (NGLs):

Gross NGL Revenue (a) $ 58,034 $ 49,260 $130,148 $ 100,683

Oil:

Net Oil Revenue (a) $ 5,903 $ 4,575 $ 10,117 $ 9,561

Total Liquids Revenue 63,937 53,835 140,265 110,244

GAS

Gas Revenue $513,359 $385,417 $1,029,995 $ 655,843

Basis (85,701) (1,576) (109,370) (3,118)

Gas Price ($/Mcf) (unhedged) $ 4.20 $ 4.40 $ 4.61 $ 4.03

Total Gross Gas & Liquids Revenue (unhedged) $491,595 $437,676 $1,060,890 $ 762,969

Hedge impact (14,838) 9,728 (67,101) 53,226

Total Gross Gas & Liquids Revenue $476,757 $447,404 $993,789 $ 816,195

Total Sales Volume (MMcfe) 110,136 94,483 216,259 176,198

Average hedge adjusted price ($/Mcfe) $ 4.33 $ 4.74 $ 4.60 $ 4.63

Midstream Revenue Deductions ($/Mcfe)

Gathering to EQT Midstream $ (0.74) $ (0.81) $ (0.74) $ (0.84)

Transmission to EQT Midstream (0.19) (0.24) (0.20) (0.23)

Third-party gathering and transmission (0.54) (0.59) (0.54) (0.61)

Third-party gathering and transmission recoveries,

net 0.20 0.25 0.66 0.32

Third-party processing (0.14) (0.11) (0.13) (0.11)

Total midstream revenue deductions (1.41) (1.50) (0.95) (1.47)

Average effective sales price to EQT Production $ 2.92 $ 3.24 $ 3.65 $ 3.16

EQT Revenue ($/Mcfe)

Revenues to EQT Midstream $ 0.93 $ 1.05 $ 0.94 $ 1.07

Revenues to EQT Production 2.92 3.24 3.65 3.16

Average effective sales price to EQT Corporation $ 3.85 $ 4.29 $ 4.59 $ 4.23

48

Per Unit Operating Expenses

UNIT COSTS

Three Months Ended

June 30,

Six Months Ended

June 30,

2014 2013 (a) 2014 2013 (a)

Production segment costs: ($/Mcfe)

LOE $ 0.14 $ 0.15 $ 0.14 $ 0.16

Production taxes 0.15 0.14 0.15 0.14

SG&A 0.30 0.24 0.27 0.26

$ 0.59 $ 0.53 $ 0.56 $ 0.56

Midstream segment costs: ($/Mcfe)

Gathering and transmission $ 0.21 $ 0.22 $ 0.20 $ 0.23

SG&A 0.16 0.15 0.15 0.15

$ 0.37 $ 0.37 $ 0.35 $ 0.38

Total ($/Mcfe) $ 0.96 $ 0.90 $ 0.91 $ 0.94

(a) NGLs and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods. Information for

the three and six months ended June 30, 2013, has been recast to reflect this conversion rate.

49

Appendix

Non-GAAP Reconciliation

(millions) 2008 2009 2010 2011 2012 2013

Midstream operating income $120 $154 $179 $417 $237 $329

Add: depreciation and amortization 35 53 62 57 65 75

Less: gains on dispositions – – – 203 – 20

Less: Big Sandy and Langley 23 32 31 14 – –

Adjusted Midstream EBITDA $132 $175 $210 $257 $302 $384

EQT Corporation Adjusted Midstream EBITDA

Documents

Analyst Presentation - EQTir.eqt.com/.../doc_library/file/Analyst_Presentation__September_.pdf · Analyst Presentation ... the expected terms and structure of the proposed joint venture