1. Analyst Presentation
July 30, 2015

2. 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. 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. 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. 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. 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. 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
ProductionMMcf/d
Began horizontal drilling
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015E

8. 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. 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. 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
4,667’ Avg. Lateral Length per well
108.3 Bcfe Total Pad EUR
Kevech Pad
6 wells
2,970’ Avg. Lateral Length per well
54.6 Bcfe Total Pad EUR
Scotts Run Pad
8 wells
5,814’ Avg. Lateral Length per well
105.6 Bcfe Total Pad EUR
Tharpe Pad
10 wells
6,275’ Avg. Lateral Length per well
124.6 Bcfe Total Pad EUR
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. 11
EQT acreage
Producing pads
BIG 190 Pad
8 wells
5,657’ Avg. Lateral Length per well
100.0 Bcfe Total Pad EUR
PEN 16 Pad
5 wells
3,562’ Avg. Lateral Length per well
39 Bcfe Total Pad EUR
SMI 27 Pad
7 wells
6,084’ Avg. Lateral Length per well
100.9 Bcfe Total Pad EUR
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. 12
EQT acreage
Producing pads
Gibson Pad
2 wells
6,373’ Avg. Lateral Length per well
15.8 Bcfe Total Pad EUR
Frano Pad
3 wells
4,409’ Avg. Lateral Length per well
20.4 Bcfe Total Pad EUR
Rosborough Pad
2 wells
4,142’ Avg. Lateral Length per well
12.0 Bcfe Total Pad EUR
Marcellus Play
Central Pennsylvania
80,000 EQT acres
620 locations
75 wells online*
9 wells in 2015
5,400’ laterals
124 acre spacing
7.4 Bcfe EUR / well
1,375 Mcfe EUR / ft. of lateral
$5.7 MM / well
*As of 06/30/2015

13. 13
EQT acreage
Producing pads
GRT 26 Pad
2 wells
3,270’ Avg. Lateral Length per well
17.7 Bcfe Total Pad EUR
RSM 119 Pad
6 wells
3,537’ Avg. Lateral Length per well
32.3 Bcfe Total Pad EUR
Flanigan Pad
2 wells
6,889’ Avg. Lateral Length per well
20.3 Bcfe Total Pad EUR
Marcellus Play
Northern West Virginia – Dry Gas Area
33,000 EQT acres
300 locations
52 wells online*
7 wells in 2015
5,400’ laterals
109 acre spacing
9.4 Bcfe EUR / well
1,741 Mcfe EUR / ft. of lateral
$5.7 MM / well
*As of 06/30/2015

14. 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. 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. 16
$0
$1
$2
$3
$4
$5
$6
$7
CNX
AR
COG
EQT
RRC
NFG
RICE
SWN
SM
XCO
XEC
UPL
EOG
WLL
CXO
NBL
QEP
NFX
CHK
EGN
MDU
$0.73
$0
$1
$2
$3
$4
EQT
RICE
CHK
SWN
COG
UPL
NFG
PXD
RRC
XCO
NBL
AR
CNX
XEC
NFX
SM
STR
CXO
QEP
EOG
EGN
MDU
WLL
$0.47
Industry Leading Cost Structure
$/Mcfe$/Mcfe
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. 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. 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. 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. 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. 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. 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. 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. 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. 25
Appendix

26. 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
$/Mcf
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
Mbbls
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. 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. 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. 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
DailyProduction(MCFED)
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. 30
Marcellus Economics
IRR – Southwestern PA
Realized Price
0%
100%
200%
300%
400%
500%
600%
$2.50 $3.00 $3.50 $4.00
Wellhead After OpEx After Tax
PRICE ATAX IRR
$2.50 23%
$3.00 49%
$3.50 87%
$4.00 143%

31. 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 $4.00
Wellhead After OpEx After Tax
NGL PRICE ($/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. 32
Marcellus Economics
IRR – Central PA
Realized Price
0%
20%
40%
60%
80%
100%
120%
140%
$2.50 $3.00 $3.50 $4.00
Wellhead After OpEx After Tax
PRICE ATAX IRR
$2.50 10%
$3.00 19%
$3.50 32%
$4.00 49%

33. 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
Wellhead After OpEx After Tax
PRICE ATAX IRR
$2.50 7%
$3.00 15%
$3.50 26%
$4.00 41%

34. 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
CasingFlowingPressure(psig)
GasRate(Mcf/d)
Delta Time (Days)
Gas Rate
CFP

35. 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
CumulativeProduction(Mcf)
Delta Time(Days)
Cumulative Production
Cumulative Production/1000 ft

36. 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
8.7 Bcfe EUR / well
1,388 Mcfe EUR / ft. of lateral
$5.9 MM / well
EQT acreage

37. 37Type 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
DailyProduction(MCFED)
Time in Months
(First 100 Months Represented)
Upper Devonian Play
Type Curve – 6,300’ lateral

38. 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
Wellhead After OpEx After Tax
PRICE ATAX IRR
$2.50 11%
$3.00 26%
$3.50 45%
$4.00 70%

39. 39
Marcellus Capacity
Market MixEQT 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. 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. 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. 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. 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. 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. 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