Analyst Presentation

September 2014

EQT Cautionary Statements 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 forwardlooking. 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 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 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 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; 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.

2

Non-GAAP Measures 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.

3

Calculations Within This Presentation 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.

4

Key Investment Highlights  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 *As of 12/31/13

5

Leading Appalachian E&P Company  2013 Operating Income of $654.6 million

10,400 pipeline miles

8.3 Tcfe proved reserves

3.6 MM acres As of 12/31/13

6

Production By Play  Marcellus Shale drilling driving growth 1,600 Marcellus

1,400

Huron horizontal Vertical

Production MMcf/d

1,200 1,000 800 600 Began horizontal drilling

400

200 0

2006

2007

2008

2009

2010

2011

2012

2013

2014E 7

Reserves By Play 36.4 Tcfe 3P reserves

Proved Reserve Growth

(as of December 31, 2013) 9,000

8,348

Upper Devonian 8,000

215

CBM/Other

861

Huron

7,000

Marcellus

6,004 6,000 Bcfe

5,220 5,000

866

5,365

761

889

965

1,316

Huron 11.5

4,068 4,000

Marcellus 18.5

1,062 991

1,475

3,000 2,000

5,956 4,278

2,016 2,879

3,414

1,000

1,061 0 2009

2010

2011

2012

2013

44 Tcfe Total Resource Potential 8

Marcellus Play  Near term development focused in four areas

Central PA

580,000 EQT acres 86% NRI / 80% HBP 33% “wet”

18.5 Tcfe 3P 23.9 Tcfe total resource potential Southwestern PA

201 wells in 2014 >50% of acreage will utilize RCS

Northern WV (Dry)

Northern WV (Wet) EQT acreage

9

Marcellus Play Southwestern PA  Prolific dry gas region

Oliver West Pad 3 wells 3,919’ Avg Lateral Length per well 9,291 Mcfe Avg 30-day IP per well

115,000 EQT acres 1,460 locations

Kevech Pad 6 wells 2,970’ Avg Lateral Length per well 8,873 Mcfe Avg 30-day IP per well

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

Gallagher Pad 5 wells 4,436’ Avg Lateral Length per well 9,788 Mcfe Avg 30-day IP per well

$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

* As of 6/30/2014

Pierce Pad 9 wells 7,855’ Avg Lateral Length per well 17,025 Mcfe Avg 30-day IP per well

EQT acreage Producing wells

10

Marcellus Play Northern West Virginia – Wet Gas Area  Enhanced economics from liquids uplift Big 190 Pad 5 wells 6,308’ Avg Lateral Length per well 12,511 Mcfe Avg 30-day IP per well

90,000 EQT acres

1,060 locations 134 wells online** 73 wells in 2014 4,800 foot laterals 83 acre spacing

PEN 16 Pad 5 wells 3,562’ Avg Lateral Length per well 8,883 Mcfe Avg 30-day IP per well

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

$6.4 MM / well 100% of locations utilize RCS OXF160 Pad 3 wells 5,286’ Avg Lateral Length per well 9,317 Mcfe Avg 30-day IP per well

EQT acreage Producing Pads Producing 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

11

Marcellus Play Central Pennsylvania  Early stages of acreage delineation

80,000 EQT acres 720 locations

Frano Pad 3 wells 4,409’ Avg Lateral Length per well 7,532 Mcfe Avg 30-day IP per well

50 wells online* 18 wells in 2014 4,800 foot laterals 110 acre spacing

6.6 Bcfe EUR / well 1,375 Mcfe EUR / ft. of lateral

$6.4 MM / well 100% of locations utilize RCS

* As of 6/30/2014

Gibson Pad 2 wells 6,381’ Lateral Length 8,592 Mcfe 30-day IP

EQT acreage Producing wells

12

Marcellus Play Northern West Virginia – Dry Gas Area  EQT’s newest development area

30,000 EQT acres

GRT26 Pad 2 wells 3,270’ Avg Lateral Length per well 6,547 Mcfe Avg 30-day IP per well

300 locations 46 wells online* 8 wells in 2014 4,800 ft laterals 97 acre spacing

8.4 Bcfe EUR / well 1,741 Mcfe EUR / ft. of lateral

$6.3 MM / well 80% of locations utilize RCS Flanigan Pad 2 wells 6,889’ Avg Lateral Length per well 9,417 Mcfe Avg 30-day IP per well

* As of 6/30/2014

RSM119 Pad 6 wells 3,537’ Avg Lateral Length per well 3,529 Mcfe Avg 30-day IP per well

EQT acreage Producing wells

13

Marcellus Economics IRR - Blended Marcellus Development Areas

PRICE $4.00 $4.50 $5.00

ATAX IRR 59% 82% 110%

Realized Price See appendix for IRR by development area

14

Upper Devonian Play  Developed in conjunction with Marcellus

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

Greene County 7 wells 5,964’ Avg Lateral Length per well 8,191 Mcfe Avg 30-day IP per well

$5.6 MM / well 2014 drilling program to delineate acreage position Wetzel County 11 wells 4,396’ Avg Lateral Length per well 5,663 Mcfe Avg 30-day IP per well

*As of 6/30/2014

Near-term Upper Devonian testing & development area EQT acreage

15

Dry Utica / Point Pleasant Potential  Targeting deep, high pressure rock beneath existing development areas

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

16

Huron Play Kentucky  Targeting high-return, liquid-rich acreage

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*

120 wells

$1.6 MM / well

EQT acreage

* Liquids converted at 6:1 Mcfe per barrel (0.4 Bcfe per well from liquids). EUR assumes ethane rejection. ** As of 6/30/2014

17

Permian Basin  Stacked Horizontal Potential

73,000 net acres 78% WI / 62% NRI 98% HBP 500 MMBOE of resource potential

Howard

Mitchell

Nolan

Stacked Play Opportunity Upper Wolfcamp Lower Wolfcamp Cline

Sterling Glasscock

Coke

Development 1,500-1,700 horizontal locations 2014: 4 wells 2015: 20-30 wells ~$7.5 MM / well

Tom Green

Reagan

Irion

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

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

18

Industry Leading Cost Structure 3-year F&D (all sources) 6.00

Mean = $2.74 4.00 $/Mcfe

$0.88 2.00

NFX

XCO

EGN

WLL

EOG

CHK

CXO

XEC

STR

SM

NFG

RICE

SWN

EQT

RRC

COG

AR

0.00

For the three years ended 12/31/13

Per Unit Operating Expenses 4.00

Mean = $1.68

2.00

$0.52

1.00

WLL

NFX

EGN

EOG

CXO

STR

SM

XEC

AR

RRC

XCO

NFG

COG

SWN

CHK

RICE

0.00 EQT

$/Mcfe

3.00

Year ended 12/31/13

19

Liquids Volume Growth and Marcellus Price Uplift

Marcellus Liquids Price Uplift (1200 Btu Gas)

Liquids Volume Growth

8,000 7,000 6,000

$6.00

5,000

$5.00

NGLs (1.6 Gal/Mcf) Btu Premium NYMEX

$4.93

$/Mcf

Mbbls

$0.82 4,000 3,000

$4.00

$5.84 $1.55(1) $0.18

$3.00

2,000

$2.00

1,000

$1.00

$4.10

$4.10

Not Processed

Processed

$0.00

2008

2009

2010

2011

Includes natural gas liquids and oil

2012

2013 2014F

(1) Pricing is as of 7/17/2014 and is the 1 year forward NYMEX and Mount Belvieu for Propane $1.06, IsoButane $1.30, Normal Butane $1.26, and Pentanes $2.07

20

Midstream Overview  Transmission & Storage  Gathering  Marketing

Transmission capacity (BBtu/d) Miles of transmission pipeline Marcellus gathering capacity (BBtu/d) Miles of Marcellus gathering pipeline Compression horsepower Working gas storage (Bcf)

Legend Transmission Gathering EQT Leases Storage Pool Marcellus

EQT Midstream Total* 2,700 900 1,500 100 300,000 47

Huron Utica

*As of 12/31/13

 Formed MLP in 2012 (NYSE: EQM)  ~60% of midstream business

21

Midstream Overview  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 EQT Corporation Adjusted EQT Midstream EBITDA** $500

500 EQT Midstream EQT Midstream Partners, LP

$400

400

Production Sales Volumes (Bcfe) 300

$200

200

$100

100

$MM

Bcfe

$300

$0

0

2008

2009

2010

2011

2012

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

2013

2014E¹ 22

EQT Midstream Partners, LP (NYSE: EQM)  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

EQM Compressor Station Equitrans Transmission Sunrise Pipeline Jupiter area

 EQT ownership

Equitrans Gathering Storage Pool

 2.0% GP interest – 1.2 MM units

EQT Acreage Marcellus Fairway

 34.4% LP interest – 21.3 MM units EQM Price per Unit $90 $92 $94 $96 $98 $100

Implied EBITDA Multiple* 21.1x 21.6x 22.0x 22.5x 23.0x 23.4x

Value of EQM LP Units ($MM) $1,917 $1,960 $2,002 $2,045 $2,087 $2,130

*Based on 2014 EBITDA guidance by EQT Midstream Partners

23

EQT Midstream Partners, LP Distributions

 EQM forecasting 29% per unit distribution growth in 2014*  EQM forecasting 22% per unit distribution growth in 2015* $8.00 $7.15

$7.00 $6.19 Total Distribution per LP Unit

$6.00 $5.23 $5.00

$4.27 $4.00 $3.31

$3.00 $2.37

$2.00 $1.00

$2.14

$2.62

$3.58

$3.10

$4.06

$4.54

$0.00 2014E

2015E

2016E

LP Unit Distribution

2017E

2018E

2019E

GP Distribution per LP Units

*Forecast based on assumed $0.03 per unit quarterly distribution increase each quarter through 2019 24

EQT Midstream Partners, LP General Partner Cash Flow Valuation

 Present value of GP cash flows = $3.9 billion $250

$194

$200

$ Millions

$158 $150

$123 $100

$82 $45

$50

$14 $0 2015E

2016E

2017E

2014E

Present Value of 2014-2019 Present Value Terminal Value Present Value of GP Cash Flows

$ $ $

470 3,435 3,905

2018E

2019E

GP Discounted Cash Flow Sensitivity $ Billion Terminal Growth 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

WACC

2014E

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

25

EQT Midstream Partners, LP Jupiter Gathering System  EQT sold to EQT Midstream Partners May 2014  $1.2 billion

Central PA

 35 mile gathering system in Greene and Washington Counties in Pennsylvania  10-year firm transportation agreement

Southwestern PA

Jupiter

 Currently 225 MMcfe/d  Additional 550 MMcfe/d by year-end 2015

Northern WV (Dry)

Northern WV (Wet)

26

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

1,500

440

1,940

Total

Tioga 65 MMcf/d

Longhorn 130 MMcf/d Terra 80 MMcf/d

2014 CAPEX $240 MM (EQT) $105 MM (EQM)

Mercury 250 MMcf/d Saturn 225 MMcf/d

Applegate 150 MMcf/d

Jupiter* Pluto 60 MMcf/d

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

Equitrans Transmission EQT acreage

27

EQT Midstream Transmission  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

Equitrans Transmission Allegheny Valley Connector EQT acreage Allegheny Valley Connector Storage Field

28

EQT Midstream Mountain Valley Pipeline Project  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

29

Corporate Citizenship  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

30

Drilling and Hydraulic Fracturing  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

31

Investment Summary  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

32

Appendix

33

Capital Investment Summary 3.0

$2.3

2.5

$1.8

2.0 $B

$1.4 1.5

$1.1

$1.2

1.0 0.5 0.0 2010

2011 Midstream

Excludes acquisitions

2012 Production

2013

2014F

Distribution 34

Marcellus Play Acres Within Each Core Development Area  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

Southwestern PA 1 Northern WV - Wet Northern WV - Dry² Central PA3

EUR (Mcfe) / Lateral Foot Total Net Acres 2,088 115,000 2,043 90,000 1,747 30,000 1,375 80,000 315,000

Total Net Undeveloped Acres 93,000 75,000 27,000 72,000 267,000

Locations Utilizing Reduced Cluster Spacing Locations¹ 90% 1,460 100% 1,060 80% 300 100% 720 94% 3,540

1Based

on 4,800 laterals with lateral spacing estimates ranging from 500’ to 1,000’ 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 2EQT

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

35

Marcellus Play Type Curves by Area - 4,800’ lateral

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

36

Marcellus Economics IRR - Southwestern PA

PRICE $4.00 $4.50 $5.00

ATAX IRR 79% 119% 171%

Realized Price 37

Marcellus Economics IRR - Northern WV – Wet Gas Area

PRICE $4.00 $4.50 $5.00

ATAX IRR 111% 141% 176%

Realized Price 38

Marcellus Economics IRR - Central PA

PRICE $4.00 $4.50 $5.00

ATAX IRR 19% 28% 38%

Realized Price 39

Marcellus Economics IRR - Northern WV – Dry Gas Area

PRICE $4.00 $4.50 $5.00

ATAX IRR 26% 37% 50%

Realized Price 40

Upper Devonian Play Blended Type Curve - 4,800’ lateral

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

41

Upper Devonian IRR

PRICE $4.00 $4.50 $5.00

ATAX IRR 32% 45% 59%

Realized Price 42

Huron Play IRR 120%

Wellhead

Wellhead After OpEx

ATAX

100%

80%

60%

40%

PRICE $4.00 $4.50 $5.00

20%

ATAX IRR 35% 42% 50%

0%

$3.00

$3.50

$4.00

$4.50

$5.00

Realized Price 43

Marcellus Capacity EQT Capacity & Firm Sales

Market Mix* 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%

44

Ample Financial Flexibility to Execute Business Plan Debt ratings Moody’s

Standard & Poor’s

Fitch

Baa3

BBB

BBB-

Stable

Stable

Stable

Long-term debt Outlook

Strong balance sheet ($ thousands, except net debt / capital) Short-term debt Long-term debt Cash and cash equivalents Net debt (total debt minus cash)

June 30, 3014 $330,000 2,497,619 (1,274,265) $1,553,354

Total common stockholders' equity

4,276,592

Net debt / capital

27%

Manageable debt maturities 774

800

708

700

$MM$MM

600

400

166

200

115 11

3

2014

2015

2016

11

0 2017

2018

2019

2020

2021

0

10

0

0

2022

2023

2024

2025

2026

45

Risk Management Hedging

Fixed Price Total Volume (Bcf) Average Price per Mcf (NYMEX)* Collars Total Volume (Bcf) Average Floor Price per Mcf (NYMEX)* Average Cap Price per Mcf (NYMEX)*

2014**

2015

2016***

114 $ 4.36

138 $ 4.33

64 $ 4.45

12 $ 5.05

23 $ 5.03

$

– –

$ 8.85

$ 8.97

$

–

* 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

As of July 24, 2014

46

Price Reconciliation in thousands (unless noted) LIQUIDS Natural Gas Liquids (NGLs): Gross NGL Revenue (a) Oil: Net Oil Revenue (a) Total Liquids Revenue GAS Gas Revenue Basis Gas Price ($/Mcf) (unhedged) Total Gross Gas & Liquids Revenue (unhedged) Hedge impact Total Gross Gas & Liquids Revenue Total Sales Volume (MMcfe) Average hedge adjusted price ($/Mcfe) Midstream Revenue Deductions ($/Mcfe) Gathering to EQT Midstream Transmission to EQT Midstream Third-party gathering and transmission Third-party gathering and transmission recoveries, net Third-party processing Total midstream revenue deductions Average effective sales price to EQT Production EQT Revenue ($/Mcfe) Revenues to EQT Midstream Revenues to EQT Production Average effective sales price to EQT Corporation

Three Months Ended June 30, 2014 2013

Six Months Ended June 30, 2014 2013

$ 58,034

$ 49,260

$130,148

$ 100,683

$ 5,903 63,937

$

$ 10,117 140,265

$

$513,359 (85,701) $ 4.20 $491,595 (14,838) $476,757 110,136 $ 4.33

$385,417 (1,576) $ 4.40 $437,676 9,728 $447,404 94,483 $ 4.74

$1,029,995 (109,370) $ 4.61 $1,060,890 (67,101) $993,789 216,259 $ 4.60

$ 655,843 (3,118) $ 4.03 $ 762,969 53,226 $ 816,195 176,198 $ 4.63

$

$

$

$

$ $

$

(0.74) (0.19) (0.54) 0.20 (0.14) (1.41) 2.92 0.93 2.92 3.85

$ $

$

4,575 53,835

(0.81) (0.24) (0.59) 0.25 (0.11) (1.50) 3.24 1.05 3.24 4.29

$ $

$

(0.74) (0.20) (0.54) 0.66 (0.13) (0.95) 3.65 0.94 3.65 4.59

(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.

$ $

$

9,561 110,244

(0.84) (0.23) (0.61) 0.32 (0.11) (1.47) 3.16 1.07 3.16 4.23 47

Per Unit Operating Expenses

UNIT COSTS Production segment costs: ($/Mcfe) LOE Production taxes SG&A

Midstream segment costs: ($/Mcfe) Gathering and transmission SG&A Total ($/Mcfe)

Three Months Ended June 30, 2014 2013 (a)

Six Months Ended June 30, 2014 2013 (a)

$ 0.14 0.15 0.30 $ 0.59

$ 0.15 0.14 0.24 $ 0.53

$ 0.14 0.15 0.27 $ 0.56

$ 0.16 0.14 0.26 $ 0.56

$ 0.21 0.16 $ 0.37 $ 0.96

$ 0.22 0.15 $ 0.37 $ 0.90

$ 0.20 0.15 $ 0.35 $ 0.91

$ 0.23 0.15 $ 0.38 $ 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.

48

Appendix Non-GAAP Reconciliation EQT Corporation Adjusted Midstream EBITDA (millions)

2008

2009

2010

2011

2012

2013

$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

–

–

$132

$175

$210

$257

$302

$384

Midstream operating income

Adjusted Midstream EBITDA

49