Analyst Presentation

October 22, 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; project firm pipeline capacity and sales; 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, 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 expendi tures; liquidity and financing

requirements, including funding sources and availability; projected operating revenue, cash flows and cash-on-hand; 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% limited partner interest; 2% general partner interest and all incentive

distribution rights of EQT Midstream Partners, LP**

Strong liquidity position

$1.7 billion cash**

$1.5 billion undrawn, unsecured revolver

Key Investment Highlights

*As of 12/31/2014

**As of 09/30/2015

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 12/31/2014

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

Core

Development

Area

Marcellus Play

600,000 EQT acres

• 86% NRI / 80% HBP

23.3 Tcfe 3P

31 Tcfe total resource

potential

138 wells in 2015

10

Marcellus Core Development Area

Core

Development

Area

Near term development strategically focused on core

~260,000 EQT acres

~2,840 locations

526 wells online*

123 wells in 2015

5,400’ laterals

91 acre spacing

11.2 Bcfe EUR / well

2,065 Mcfe EUR / ft. of lateral

$5.7 MM / well

*As of 09/30/2015

11

Core Marcellus IRR

Realized Price

0%

50%

100%

150%

200%

250%

300%

350%

$2.50 $3.00 $3.50

Wellhead After OpEx After Tax

PRICE ATAX IRR

$2.50 22%

$3.00 46%

$3.50 82%

12

Scotts Run 591340

Greene County, PA

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 BIG 190

Wetzel County, WV

Spud September 18, 2015

12,700’ vertical depth

3,500’- 4,000’ lateral

Utica Play

400,000 EQT acres

3,000 locations

1 well online*

2 wells in progress

~13,000’ deep

5,400’ lateral

$12.5 – $14.0 MM / well**

Pettit 593066

Greene County, PA

Spud August 17, 2015

13,400’ vertical depth

4,000’- 4,500’ lateral

*As of 09/30/2015

**Target cost

13

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

0 10 20 30 40 50 60 70 80 90 100

Dai

ly P

rodu

ctio

n (M

cf/d

)

Time in Months(First 100 Months Represented)

Utica 5.9 MMcf/ft

Utica 4.3 MMcf/ft

Utica Play Type Curves - 5,400’ lateral

ATAX IRR ($2.00 Realized Price)

Well Cost 4.3 MMcf/ft 5.9 MMcf/ft

$12.5 MM 34% 53%

$14.0 MM 21% 37%

Cumulative Production over Time

4.3 MMcf/ft 5.9 MMcf/ft

% of EUR at 1 year 47% 35%

% of EUR at 5 years 69% 61%

14

-

500

1,000

1,500

2,000

2,500

3,000

3,500

0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 480 510 540

0

10

20

30

40

50

60

70

-

2,000

4,000

6,000

8,000

10,000

12,000

0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 480 510 540

Scott’s Run Utica Well Update Cumulative Production, Pressure and Rate vs. Time

2.3 Bcf / 1,000’

recovered by day 254

Flowing pressure meets line

pressure (500 psi) at day 254

Days on Production

EUR: 5.9 Bcf / 1,000’

EUR: 4.3 Bcf / 1,000’

Cu

mu

lati

ve P

rod

ucti

on

(M

Mcf /

1,0

00’ Late

ral)

Casin

g F

low

Pre

ssu

re

(psig

)

40 psi/day pressure decline

30 MMcf/d

Days on Production

Daily

Flo

w R

ate

(M

Mcf/d

)

EUR: 5.9 Bcf / 1,000’

EUR: 4.3 Bcf / 1,000’

Actual Projected

15

$0

$1

$2

$3

$4

$5

$6

$7

CN

X

AR

CO

G

EQ

T

RR

C

NF

G

RIC

E

SW

N

SM

XC

O

XE

C

UP

L

EO

G

WL

L

CX

O

NB

L

QE

P

NF

X

CH

K

EG

N

MD

U

$0.73

$0

$1

$2

$3

$4

EQ

T

RIC

E

CH

K

SW

N

CO

G

UP

L

NFG

PX

D

RR

C

XC

O

NB

L

AR

CN

X

XE

C

NFX SM

STR

CX

O

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

16

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

17

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

$75 - $100 MM

Tioga

65 MMcf/d

Terra

80 MMcf/d

Longhorn

130 MMcf/d

Applegate

150 MMcf/d

Allegheny

Valley

Connector

18

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

$24 $5,753 $38

$26 $6,233 $41

$28 $6,712 $44

$30 $7,191 $47

*As of 09/30/2015

19

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)

20

Ohio Valley Connector

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

Q3 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, Vega Energy Partners, and RGC Resources

2 Bcf/d capacity commitments

20-year term

EQT Midstream Partners, LP Growth Projects

21

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

22

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

23

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

24

Appendix

25

$2.72 $2.72

$0.54

$0.12

$0.39

$3.27 $3.23

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

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 10/20/2015 and is the 1 year forward NYMEX

and Mount Belvieu for Propane $0.44, Iso-Butane $0.57,

Normal Butane $0.56, and Pentanes $.97

26

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

27

Marcellus Play Development Areas

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

Acres Undeveveloped Total Locations

Undeveloped

Locations

PA Core 145,000 116,000 1,610 1,300

WV Core 115,000 92,000 1,230 980

PA Tier 2 200,000 189,000 1,600 1,520

WV Tier 2 140,000 136,000 1,120 1,100

TOTAL 600,000 533,000 5,560 4,900

28

Type Curves - 5,400’ lateral Core Marcellus vs Utica

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

0 10 20 30 40 50 60 70 80 90 100

Dai

ly P

rod

uct

ion

(M

cf/d

)

Time in Months(First 100 Months Represented)

Utica 5.9 MMcf/ft

Utica 4.3 MMcf/ft

Core Marcellus 2.1 MMcf/ft

29

Marcellus Play Core Type Curve - 5,400’ lateral

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 20 30 40 50 60 70 80 90 100

Da

ily P

rod

uc

tio

n (

Mc

f/d

)

Time in Months(First 100 Months Represented)

30

Marcellus Capacity

Market Mix EQT Capacity & Firm Sales

Q4 2015 2016E 2017E

TETCO M2 29-31% 19-21% 14-16%

TETCO M3 34-36% 31-33% 28-30%

TCO 10-11% 9-10% 6-8%

Midwest 10-11% 23-25% 32-34%

NYMEX 14-16% 12-14% 15-17%

31

Risk Management

Hedge Position as of October 21, 2015

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

**October 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 17 Bcf

at strike prices of $3.65 per Mcf and $3.79 per Mcf, respectively.

84 248 110

$4.09 $3.81

$3.63

$2.70 $2.94

$3.16

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

-

50

100

150

200

250

300

2015** 2016 2017

$ / M

cf

Bcf

Hedged Volume Average Hedge Price NYMEX Price

2015** 2016*** 2017***

NYMEX Price ($/Mcf) as of 10/20/2015 $2.70 $2.94 $3.16

Fixed Price

Total Volume (Bcf) 75 248 103

Average Price per Mcf (NYMEX)* $4.04 $3.81 $3.66

Collars

Total Volume (Bcf) 9 - 7

Average Floor Price per Mcf (NYMEX)* $4.47 $0.00 $3.15

Average Cap Price per Mcf (NYMEX)* $7.19 $0.00 $4.03

32

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

Short-term debt* $ 0

Long-term debt* 2,478

Cash and cash equivalents* (1,661)

Net debt (total debt minus cash)* $ 817

Total common stockholders' equity $ 5,172

14%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*

* Excludes EQT Midstream Partners

Strong balance sheet

33

Price Reconciliation

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

(b) The Company’s volume weighted NYMEX natural gas price (actual average NYMEX natural gas price ($/MMBtu) was $2.77 and $4.06 for the three months ended

September 30, 2015 and 2014, respectively, and $2.80 and $4.55 for the nine months ended September 30, 2015 and 2014, respectively).

(c) 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 pipeline capacity. Recoveries include approximately $0.20 and $0.19 per Mcf for the three months ended September 30, 2015 and 2014,

respectively, and $0.20 and $0.18 per Mcf for the nine months ended September 30, 2015 and 2014, respectively, for the sale of unused pipeline capacity.

Three Months Ended

September 30, Nine Months Ended

September 30,

in thousands (unless noted) 2015 2014 2015 2014

LIQUIDS

NGLs:

Sales volume (MMcfe) (a) 13,827 12,047 39,552 27,768

Sales volume (Mbbls) 2,304 2,008 6,592 4,628

Gross price ($/Bbl) $ 8.10 $ 42.27 $ 15.17 $ 46.46

Gross NGL sales $ 18,665 $ 84,868 $ 99,983 $ 215,016

Third-party processing (19,970 ) (17,883 ) (57,084 ) (45,456 )

Net NGL sales $ (1,305 ) $ 66,985 $ 42,899 $ 169,560

Oil:

Sales volume (MMcfe) (a) 1,102 933 3,250 1,632

Sales volume (Mbbls) 184 155 542 272

Net price ($/Bbl) $ 39.13 $ 87.91 $ 41.02 $ 87.46

Net oil sales $ 7,187 $ 13,668 $ 22,221 $ 23,785

Net liquids sales $ 5,882 $ 80,653 $ 65,120 $ 193,345

NATURAL GAS

Sales volume (MMcf) 141,367 110,362 405,743 310,201

NYMEX price ($/MMBtu) (b) $ 2.77 $ 4.05 $ 2.80 $ 4.52

Btu uplift $ 0.28 $ 0.41 $ 0.26 $ 0.38

Gross natural gas price ($/Mcf) $ 3.05 $ 4.46 $ 3.06 $ 4.90

Basis ($/Mcf) $ (1.54 ) $ (1.54 ) $ (1.26 ) $ (0.90 )

Recoveries ($/Mcf) (c) 0.64 0.80 0.88 0.79

Cash settled basis swaps (not designated as hedges) ($/Mcf) 0.01 (0.02 ) (0.02 ) (0.04 )

Average differential ($/Mcf) $ (0.89 ) $ (0.76 ) $ (0.40 ) $ (0.15 )

Average adjusted price - unhedged ($/Mcf) $ 2.16 $ 3.70 $ 2.66 $ 4.75

Cash settled derivatives (cash flow hedges) ($/Mcf) 0.46 0.08 0.50 (0.12 )

Cash settled derivatives (not designated as hedges) ($/Mcf) 0.21 0.05 0.19 0.02

Average adjusted price, including cash settled derivatives ($/Mcf) $ 2.83 $ 3.83 $ 3.35 $ 4.65

Net natural gas sales, including cash settled derivatives $ 401,382 $ 422,359 $ 1,355,645 $ 1,444,221

TOTAL PRODUCTION

Total net natural gas & liquids sales, including cash settled derivatives $ 407,264 $ 503,012

$ 1,420,765

$ 1,637,566

Total sales volume (MMcfe) 156,296 123,342 448,545 339,601

Net natural gas & liquids price, including cash settled derivatives ($/Mcfe) $ 2.61 $ 4.08 $ 3.17 $ 4.82

34

Price Reconciliation (continued)

Three Months Ended

September 30, Nine Months Ended

September 30,

in thousands (unless noted) 2015 2014 2015 2014

Midstream Deductions ($/Mcfe)

Gathering to EQT Midstream $ (0.72 ) $ (0.74 ) $ (0.74 ) $ (0.74 )

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

Third-party gathering and transmission costs (0.49 ) (0.45 ) (0.46 ) (0.50 )

Total midstream deductions $ (1.40 ) $ (1.39 ) $ (1.39 ) $ (1.44 )

Average realized price to EQT Production ($/Mcfe) $ 1.21 $ 2.69 $ 1.78 $ 3.38

Gathering and transmission to EQT Midstream ($/Mcfe) $ 0.91 $ 0.94 $ 0.93 $ 0.94

Average realized price to EQT Corporation ($/Mcfe) $ 2.12 $ 3.63 $ 2.71 $ 4.32

35

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