EQT Analyst Presentation - July 30, 2015

Analyst Presentation

July 30, 2015

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, depth, lateral length and location of wells to be drilled);

projected natural gas prices, liquids price uplift, basis, recoveries and average differential; projected market mix; total resource potential, reserves, EUR, expected

rates and pressures, and expected decline curve; projected production sales volume and growth rates (including liquids 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 midstream revenue deductions; projected gathering and transmission volumes

and growth rates; the Company’s access to, and timing of, capacity on pipelines; infrastructure programs (including the timing, cost and capacity of expected

gathering and transmission expansion projects); the timing, cost, capacity and expected interconnects with facilities and pipelines of the Ohio Valley Connector and

Mountain Valley Pipeline (MVP) projects; the ultimate terms, partners, and structure of the MVP joint venture; projected EBITDA; monetization transactions,

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

Company’s assets; and the Company’s use of proceeds from the initial public offering of EQT GP Holdings, LP (EQGP) common units; the amount and timing of

any repurchases under the Company’s share repurchase authorization; projected capital 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; dividend and 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, many of

which are difficult to predict and beyond the Company’s control. The 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, 2014, 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.

Information in this presentation regarding EQGP and its subsidiaries, including EQM, is derived from publicly available information published by EQGP and EQM.

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 the Company’s EQT Midstream business segment’s operating income (loss) plus depreciation and amortization expense less gains on dispositions. Adjusted EQT Midstream EBITDA also excludes the Company’s EQT Midstream business segment’s 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 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 2012 – 2014 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, 2014.

Calculations Within This Presentation

5

Extensive reserves of natural gas*

10.7 Tcfe Proved; >22 years R/P

42.8 Tcfe 3P; >87 years R/P

53 Tcfe Total Resource Potential; >108 years R/P

Proven ability to profitably develop our reserves

>25% production sales volume growth forecasted in 2015

Industry leading cost structure

Extensive and growing midstream business

EQT owns 90% interest in EQT GP Holdings, LP (NYSE: EQGP)

EQGP owns:

30% LP interest, 2% GP interest and incentive distribution rights of EQT

Midstream Partners, LP (NYSE: EQM)

Strong liquidity position

$2.0 billion cash**

$1.5 billion undrawn, unsecured revolver

Key Investment Highlights

*As of 12/31/14

**As of 07/23/15, excludes EQM

6

2014 Operating Income of $853.4 million

Leading Appalachian E&P Company

10.7 Tcfe proved reserves

3.4 MM acres

9,100 pipeline miles

As of 12/31/14

7

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Marcellus

Huron

Other

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 2014 2015E

8

Proved Reserve Growth

Reserves By Play

42.8 Tcfe 3P reserves (as of December 31, 2014)

53 Tcfe Total Resource Potential

2,879 3,414

4,278

5,956

8,284

1,475 1,062

965

1,316

1,240

866 889

761

861

760

215

455

0

2,000

4,000

6,000

8,000

10,000

12,000

2010 2011 2012 2013 2014

Bcfe

Upper Devonian

Other

Huron

Marcellus

5,220 5,365

8,348

10,739

6,004

Marcellus 23.3

Huron 11.9

9

Near term development focused in four areas

Marcellus Play

600,000 EQT acres

86% NRI / 80% HBP

28% “wet”

23.3 Tcfe 3P

31 Tcfe total resource potential

140 wells in 2015

Central PA

Southwestern PA

Northern WV (Wet)

EQT acreage

Northern WV (Dry)

10

Marcellus Play

Southwestern PA

*As of 06/30/2015

EQT acreage

Producing pads

Oliver West Pad

7 wells

3,986’ Avg. Lateral Length per well

61.7 Bcfe Total Pad EUR

Gallagher Pad

11 wells



Kevech Pad

6 wells



Scotts Run Pad

8 wells



Tharpe Pad

10 wells



140,000 EQT acres

1,560 locations 281 wells online*

79 wells in 2015

5,400’ laterals

89 acre spacing

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

$5.7 MM / well

11

EQT acreage

Producing pads

BIG 190 Pad

8 wells



PEN 16 Pad

5 wells


39 Bcfe Total Pad EUR

SMI 27 Pad

7 wells



Marcellus Play

Northern West Virginia – Wet Gas Area

90,000 EQT acres

940 locations 196 wells online*

45 wells in 2015

5,400’ laterals

94 acre spacing

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

$5.7 MM / well

*As of 06/30/2015

12

EQT acreage

Producing pads Gibson Pad

2 wells



Frano Pad

3 wells



Rosborough Pad

2 wells



Marcellus Play

Central Pennsylvania

80,000 EQT acres


9 wells in 2015

5,400’ laterals

124 acre spacing


$5.7 MM / well

*As of 06/30/2015

13

EQT acreage

Producing pads

GRT 26 Pad

2 wells



RSM 119 Pad

6 wells



Flanigan Pad

2 wells



Marcellus Play

Northern West Virginia – Dry Gas Area

33,000 EQT acres


7 wells in 2015

5,400’ laterals

109 acre spacing


$5.7 MM / well

*As of 06/30/2015

14

Marcellus Economics

IRR - Blended Marcellus Development Areas

Realized Price

See appendix for IRR by development area

0%

50%

100%

150%

200%

250%

300%

350%

400%

$2.50 $3.00 $3.50 $4.00

Wellhead After OpEx After Tax

PRICE ATAX IRR

$2.50 16%

$3.00 34%

$3.50 57%

$4.00 89%

15

Dry Utica / Point Pleasant Potential

EQT acreage

Scotts Run 591340 Pad

3,221’ treated interval

24 hr. IP: 72.9 MMcf

22.6 MMcf / 1000’

8,641 psi flowing casing pressure

0.95 pore pressure gradient

Wetzel County well planned

for 3rd quarter 2015

400,000 EQT acres

3,000 locations 3 wells in 2015

13,500’ deep

5,400’ lateral

$12.5 – $14.5 MM / well

Targeting deep, high pressure rock beneath existing

development areas

Greene County well planned

for 3rd quarter 2015

16

$0

$1

$2

$3

$4

$5

$6

$7

CN

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AR

CO

G

EQ

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L

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G

WL

L

CX

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NB

L

QE

P

NF

X

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N

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$0.73

$0

$1

$2

$3

$4

EQ

T

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E

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K

SW

N

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G

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NFX SM

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CX

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QE

P

EO

G

EG

N

MD

U

WLL

$0.47

Industry Leading Cost Structure

$/M

cfe

$/M

cfe

3-year F&D (all sources)

Per Unit Operating Expenses

Mean = $1.69

For the three years ended 12/31/2014

Year ended 12/31/2014

Mean = $2.66

17

Transmission & Storage*

3.5 Bcf/d current capacity

47 Bcf gas storage capacity

Gathering*

2 Bcf/d capacity

Formed MLP in 2012 (NYSE: EQM)

EQT Corporation Midstream

Overview – Consolidated

*As of 12/31/2014

**Excludes Big Sandy and Langley in 2010-2011; see Non-GAAP Reconciliation in the appendix

***Pro-forma reflecting full-year impact of Northern West Virginia Marcellus Gathering System acquisition

0

100

200

300

400

500

600

700

$0

$100

$200

$300

$400

$500

$600

2010 2011 2012 2013 2014 2015E***

EQT Midstream

EQT Midstream Partners, LP

Production Sales Volumes (Bcfe)

EQT Corporation Adjusted EQT Midstream EBITDA**

EQT Production sales drive EQT

Midstream EBITDA growth

18

EQT Corporation Midstream

Marcellus Midstream Assets

Allegheny Valley

Connector

200-mile FERC pipeline

450 MMcf/d capacity

~$30MM CAPEX in 2015

~$40 MM projected annual

EBITDA

2015 Gathering CAPEX

$135 - $160 MM

Tioga

65 MMcf/d

Terra

80 MMcf/d

Longhorn

130 MMcf/d

Applegate

150 MMcf/d

Allegheny

Valley

Connector

19

EQT owns 90% LP interest of EQGP

EQGP owns in EQM

30% limited partner interest

2% general partner interest

incentive distribution rights

EQT GP Holdings, LP (NYSE: EQGP)

EQGP Price

per Unit

Value of EQGP Units

held by EQT ($MM)

Value per

EQT share

$29 $6,951 $46

$30 $7,191 $47

$31 $7,431 $49

$32 $7,670 $50

20

Transmission & Storage

3.1 Bcf/d current capacity

700 mile FERC-regulated

interstate pipeline

32 Bcf of gas storage capacity

Gathering System

Jupiter Gathering System

Supports EQT PA dry gas

production

Northern West Virginia Marcellus

Gathering System

Supports EQT wet and dry gas

production

EQT Midstream Partners, LP (NYSE: EQM)

21

Ohio Valley Connector

36-mile FERC regulated pipeline to connect transmission in West Virginia to Clarington, OH

Mid-2016 in-service

~1 Bcf/d capacity

650 MMcf/d contracted under firm 20-year term

Mountain Valley Pipeline

300-mile FERC-regulated pipeline to growing demand center in southeast US

Q4 2018 in-service

JV with NextEra Energy, WGL Midstream, and Vega Energy Partners

2 Bcf/d capacity commitments

20-year term

EQT Midstream Partners, LP

Growth Projects

22

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

23

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

24

Extensive reserves of natural gas

Proven ability to profitably develop our reserves

>25% production sales volume growth forecasted in 2015

Strong liquidity position

Committed to maximize shareholder value by:

Accelerating the monetization of our vast reserves

Operating in a safe and environmentally responsible manner

Investment Summary

25

Appendix

26

$3.05 $3.05

$0.61$0.13$0.48

$3.66 $3.66

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

Not Processed Processed$/M

cf

NGLs (1.6 Gal/Mcf)

Btu Premium

NYMEX

Liquids

Volume Growth and Marcellus Impact

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2009 2010 2011 2012 2013 2014 2015F

Mb

bls

Includes natural gas liquids and oil

Liquids Volume Growth Marcellus Liquids Price Impact

(1200 Btu Gas)

Pricing is as of 7/20/2015 and is the 1 year forward NYMEX

and Mount Belvieu for Propane $0.47, Iso-Butane $0.63,

Normal Butane $0.62, and Pentanes $1.10

27

Capital Investment Summary

Excludes acquisitions and EQT Midstream Partners, LP

Midstream Production Distribution

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2011 2012 2013 2014 2015F

$B $1.2 $1.3

$1.6

$1.9 $1.8

28

EQT has 600,000 total Marcellus acres

Expect to develop in four areas for several years

Active areas represent 343,000 acres and 3,420 locations

EQT has 123,000 additional acres in PA & 134,000 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 5,400 laterals with lateral spacing estimates ranging from 500’ to 1,000’ 2EQT holds approximately 50,000 acres in the northern WV dry area – near-term development focused on 33,000 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 Locations¹

Southwestern PA 2,088 140,000 113,000 1,560

Northern WV - Wet1

2,043 90,000 70,000 940

Northern WV - Dry² 1,741 33,000 27,000 300

Central PA3

1,375 80,000 69,000 620

343,000 279,000 3,420

29

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000

15,000

16,000

17,000

1 11 21 31 41 51 61 71 81 91

Dai

ly P

rod

uct

ion

(M

CFE

D)

Time in Months(First 100 Months Represented)

Central PA

Northern WV - Wet

Northern WV - Dry

Southwestern PA

Marcellus Play

Type Curves by Area – 5,400’ lateral

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

30

Marcellus Economics

IRR – Southwestern PA

Realized Price

0%

100%

200%

300%

400%

500%

600%

$2.50 $3.00 $3.50 $4.00


PRICE ATAX IRR

$2.50 23%

$3.00 49%

$3.50 87%

$4.00 143%

31

Marcellus Economics

IRR – Northern WV – Wet Gas Area

Realized Price

0%

50%

100%

150%

200%

250%

300%

350%

400%

$2.50 $3.00 $3.50 $4.00


NGL PRICE ($/bbl)

$15.00 $20.00 $25.00

$2.50 13% 19% 25%

$3.00 28% 35% 42%

$3.50 47% 56% 65%

$4.00 70% 81% 93%

GAS PRICE

(/MMbtu)

32

Marcellus Economics

IRR – Central PA

Realized Price

0%

20%

40%

60%

80%

100%

120%

140%

$2.50 $3.00 $3.50 $4.00


PRICE ATAX IRR

$2.50 10%

$3.00 19%

$3.50 32%

$4.00 49%

33

Marcellus Economics

IRR – Northern WV – Dry Gas Area

Realized Price

0%

20%

40%

60%

80%

100%

120%

140%

$2.50 $3.00 $3.50 $4.00


PRICE ATAX IRR

$2.50 7%

$3.00 15%

$3.50 26%

$4.00 41%

34

Record Utica IP of 22.6 MMcf / 1000’

3,221’ Lateral Length

Dry Utica Well Update: Scotts Run 591340

Rate and Pressure vs. Time

7 Day Test Period

Average: 27 MMcfd

with 9,563 CFP

24 Hour

Test Period

IP: 72.9

MMcfd

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000

15,000

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

110,000

0 1 2 3 4 5 6 7 8 9

Ca

sin

g F

low

ing

Pre

ss

ure

(p

sig

)

Ga

s R

ate

(M

cf/

d)

Delta Time (Days)

Gas Rate

CFP

35

Dry Utica Well Results: Scotts Run 591340

Cumulative Production vs. Time

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

220,000

240,000

260,000

280,000

300,000

0 1 2 3 4 5 6 7 8 9

Cu

mu

lati

ve

Pro

du

cti

on

(M

cf)

Delta Time (Days)

Cumulative Production

Cumulative Production/1000 ft

36

Developed in conjunction with Marcellus

Upper Devonian Play

*As of 06/30/2015

Upper Devonian

development area

170,000 EQT acres

1,560 locations 36 wells online*

24 wells in 2015

6,300’ laterals

109 acre spacing


$5.9 MM / well

EQT acreage

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

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

1 11 21 31 41 51 61 71 81 91

Daily P

rod

ucti

on

(M

CF

ED

)

Time in Months(First 100 Months Represented)

Upper Devonian Play

Type Curve – 6,300’ lateral

38

Upper Devonian

IRR

Realized Price

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

200%

$2.50 $3.00 $3.50 $4.00


PRICE ATAX IRR

$2.50 11%

$3.00 26%

$3.50 45%

$4.00 70%

39

Marcellus Capacity

Market Mix EQT Capacity & Firm Sales

FIRM SALES (SHORT-TERM)

FIRM SALES (LONG-TERM)

FIRM MIDWEST

FIRM GULF

FIRM NORTHEAST

-

500

1,000

1,500

2,000

2,500

Q3 2015 Q3 2016 Q3 2017

MDth/D

2015E 2016E

TETCO M2 31-33% 19-21%

TETCO M3 34-36% 31-33%

TCO 9-10% 9-10%

Midwest 9-10% 23-25%

NYMEX 14-16% 12-14%

40

($ MM, except net debt / capital) June 30, 2015

Short-term debt* $ -

Long-term debt* 2,478

Cash and cash equivalents* (1,957)

Net debt (total debt minus cash)* $ 521

Total common stockholders' equity $ 5,139

9%Net debt / capital

Ample Financial Flexibility to Execute Business Plan

Moody’s Standard & Poor’s Fitch

Long-term debt Baa3 BBB BBB-

Outlook Stable Stable Stable

EQT Debt ratings

Manageable debt maturities*

Strong balance sheet

41

Risk Management

Hedging

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

**July through December

***For 2016 and 2017, the Company also has a natural gas sales agreement for 35 Bcf that includes a NYMEX

ceiling price of $4.88/Mcf. The Company also sold calendar year 2016 and 2017 calls for approximately 11 Bcf and

13 Bcf at strike prices of $3.65 per Mcf and $3.90 per Mcf, respectively.

2015** 2016*** 2017***

Fixed Price

Total Volume (Bcf) 158 201 74

Average Price per Mcf (NYMEX)* $ 3.97 $ 4.00 $ 3.84

Collars

Total Volume (Bcf) 0.19 – 7

Average Floor Price per Mcf (NYMEX)* $ 4.55 $ – $ 3.15

Average Cap Price per Mcf (NYMEX)* $ 7.21 $ – $ 4.03

42

Three Months Ended June 30,

Six Months Ended June 30,

in thousands (unless noted) 2015 2014 2015 2014 LIQUIDS

NGLs:

Sales volume (MMcfe) (a) 12,444 7,954 25,725 15,721

Sales volume (Mbbls) 2,074 1,326 4,288 2,620

Gross price ($/Bbl) $ 15.58 $ 43.78 $ 18.97 $ 49.67

Gross NGL sales $ 32,304 $ 58,034 $ 81,318 $ 130,148

Third-party processing (18,733) (15,755) (37,114) (27,573)

Net NGL sales $ 13,571 $ 42,279 $ 44,204 $ 102,575

Oil:

Sales volume (MMcfe) (a) 1,138 395 2,148 699

Sales volume (Mbbls) 190 66 358 116

Net price ($/Bbl) $ 45.91 $ 89.75 $ 41.99 $ 86.85

Net oil sales $ 8,706 $ 5,903 $ 15,034 $ 10,117

Net liquids sales $ 22,277 $ 48,182 $ 59,238 $ 112,692

NATURAL GAS

Sales volume (MMcf) 133,469 101,788 264,376 199,839

NYMEX price ($/MMBtu) $ 2.64 $ 4.67 $ 2.81 $ 4.79

Btu uplift $ 0.23 $ 0.37 $ 0.25 $ 0.36

Gross natural gas price ($/Mcf) $ 2.87 $ 5.04 $ 3.06 $ 5.15

Basis ($/Mcf) $ (1.22) $ (0.84) $ (1.11) $ (0.55)

Recoveries ($/Mcf) (b) 0.50 0.33 1.00 0.79

Cash settled basis swaps (not designated as hedges) ($/Mcf) (0.02) — (0.04) (0.05)

Average differential ($/Mcf) $ (0.74) $ (0.51) $ (0.15) $ 0.19

Average adjusted price - unhedged ($/Mcf) $ 2.13 $ 4.53 $ 2.91 $ 5.34

Cash settled derivatives (cash flow hedges) ($/Mcf) 0.53 (0.18) 0.53 (0.24)

Cash settled derivatives (not designated as hedges) ($/Mcf) 0.25 0.01 0.17 —

Average adjusted price, including cash settled derivatives ($/Mcf)

$ 2.91 $ 4.36 $ 3.61 $ 5.10

Net natural gas sales, including cash settled derivatives $ 388,683 $ 444,159 $ 954,263 $ 1,021,862

Price Reconciliation

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

(b) Recoveries represent differences in natural gas prices between the Appalachian Basin and the sales points of other markets reached by utilizing

transportation capacity, differences in natural gas prices between Appalachian Basin and fixed price sales contracts, term sales with fixed differentials

to NYMEX and other marketing activity, including the sale of unused capacity. Recoveries includes approximately $0.19 and $0.20 per Mcf for the

three months ended June 30, 2015 and 2014, respectively, and $0.21 and $0.18 per Mcf for the six months ended June 30, 2015 and 2014,

respectively, for the sale of unused capacity.

43

Price Reconciliation (continued)

TOTAL PRODUCTION

Total net natural gas & liquids sales, including cash settled derivatives $ 410,960 $ 492,341 $ 1,013,501 $ 1,134,554

Total sales volume (MMcfe) 147,051 110,136 292,249 216,259

Net natural gas & liquids price, including cash settled

derivatives ($/Mcfe) $ 2.80 $ 4.47 $ 3.47 $ 5.25

Midstream Deductions ($/Mcfe)

Gathering to EQT Midstream $ (0.75) $ (0.74) $ (0.75) $ (0.74)

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

Third-party gathering and transmission costs (0.44) (0.54) (0.45) (0.54)

Total midstream deductions $ (1.39) $ (1.47) $ (1.39) $ (1.48)

Average realized price to EQT Production ($/Mcfe) $ 1.41 $ 3.00 $ 2.08 $ 3.77

Gathering and transmission to EQT Midstream ($/Mcfe) $ 0.95 $ 0.93 $ 0.94 $ 0.94

Average realized price to EQT Corporation ($/Mcfe) $ 2.36 $ 3.93 $ 3.02 $ 4.71

44

Per Unit Operating Expenses

UNIT COSTS Three Months Ended

June 30,

Six Months Ended June 30,

2015 2014 2015 2014

Production segment costs: ($/Mcfe)

LOE $ 0.12 $ 0.14 $ 0.12 $ 0.14

Production taxes 0.09 0.15 0.10 0.15

SG&A 0.21 0.30 0.25 0.27

$ 0.42 $ 0.59 $ 0.47 $ 0.56 Midstream segment costs: ($/Mcfe)

Gathering and transmission $ 0.18 $ 0.21 $ 0.17 $ 0.20

SG&A 0.14 0.16 0.14 0.15

$ 0.32 $ 0.37 $ 0.31 $ 0.35

Total ($/Mcfe) $ 0.74 $ 0.96 $ 0.78 $ 0.91

45

Appendix

Non-GAAP Reconciliation

(millions) 2010 2011 2012 2013 2014

Midstream operating income $179 $417 $237 $329 $384

Add: depreciation and amortization 62 57 65 75 87

Less: gains on dispositions – 203 – 20 7

Less: Big Sandy and Langley 31 14 – – –

Adjusted Midstream EBITDA $210 $257 $302 $384 $464

EQT Corporation Adjusted EQT Midstream EBITDA

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EQT Analyst Presentation - July 30, 2015