Analyst Presentation September 28, 2015

Transcription

1 Analyst Presentation September 28, 2015

2 EQT Cautionary Statements EQT Corporation (NYSE: EQT) EQT Plaza 625 Liberty Avenue, Suite 1700 Pittsburgh, PA Pat Kane - Chief Investor Relations Officer (412) 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. 2

3 Non-GAAP Measures 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. 3

4 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 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,

5 Key Investment Highlights 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 *As of 12/31/14 **As of 07/23/15, excludes EQM 5

6 Leading Appalachian E&P Company 2014 Operating Income of $853.4 million 9,100 pipeline miles 10.7 Tcfe proved reserves 3.4 MM acres As of 12/31/14 6

7 Production MMcf/d Production By Play Marcellus Shale drilling driving growth 1,800 1,600 1,400 Marcellus Huron Other 1,200 1, Began horizontal drilling E 7

8 Bcfe Reserves By Play Proved Reserve Growth 12,000 Upper Devonian Other 10,000 Huron Marcellus 8, , , , Tcfe 3P reserves (as of December 31, 2014) Huron ,000 4,000 5,220 5, ,475 1,062 6, ,316 5,956 8,284 Marcellus ,000 2,879 3,414 4, Tcfe Total Resource Potential 8

9 Marcellus Play Near term development focused in four areas Central PA Southwestern PA Northern WV (Dry) 600,000 EQT acres 86% NRI / 80% HBP 28% wet 23.3 Tcfe 3P 31 Tcfe total resource potential 140 wells in 2015 Northern WV (Wet) EQT acreage 9

10 Marcellus Play Southwestern PA Oliver West Pad 7 wells 3,986 Avg. Lateral Length per well 61.7 Bcfe Total Pad EUR 140,000 EQT acres 1,560 locations 281 wells online* 79 wells in ,400 laterals 89 acre spacing 11.3 Bcfe EUR / well 2,088 Mcfe EUR / ft. of lateral $5.7 MM / well Kevech Pad 6 wells 2,970 Avg. Lateral Length per well 54.6 Bcfe Total Pad EUR Gallagher Pad 11 wells 4,667 Avg. Lateral Length per well Bcfe Total Pad EUR Tharpe Pad 10 wells 6,275 Avg. Lateral Length per well Bcfe Total Pad EUR Scotts Run Pad 8 wells 5,814 Avg. Lateral Length per well Bcfe Total Pad EUR EQT acreage Producing pads *As of 06/30/

11 Marcellus Play Northern West Virginia Wet Gas Area 90,000 EQT acres BIG 190 Pad 8 wells 5,657 Avg. Lateral Length per well Bcfe Total Pad EUR 940 locations 196 wells online* 45 wells in ,400 laterals 94 acre spacing PEN 16 Pad 5 wells 3,562 Avg. Lateral Length per well 39 Bcfe Total Pad EUR 11.0 Bcfe EUR / well 2,043 Mcfe EUR / ft. of lateral* $5.7 MM / well SMI 27 Pad 7 wells 6,084 Avg. Lateral Length per well Bcfe Total Pad EUR EQT acreage Producing pads *As of 06/30/

12 Marcellus Play Central Pennsylvania 80,000 EQT acres 620 locations 75 wells online* 9 wells in ,400 laterals 124 acre spacing 7.4 Bcfe EUR / well 1,375 Mcfe EUR / ft. of lateral $5.7 MM / well 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 Gibson Pad 2 wells 6,373 Avg. Lateral Length per well 15.8 Bcfe Total Pad EUR EQT acreage Producing pads *As of 06/30/

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

14 Marcellus Economics IRR - Blended Marcellus Development Areas 400% 350% 300% PRICE ATAX IRR $ % $ % $ % $ % Wellhead After OpEx After Tax 250% 200% 150% 100% 50% 0% $2.50 $3.00 $3.50 $4.00 See appendix for IRR by development area Realized Price 14

15 Dry Utica / Point Pleasant Potential Targeting deep, high pressure rock beneath existing development areas 400,000 EQT acres 3,000 locations 3 wells in 2015 ~13,000 deep 5,400 lateral $12.5 $14.5 MM / well Scotts Run ,221 treated interval 24 hr. IP: 72.9 MMcf 22.6 MMcf / ,641 psi flowing casing pressure 0.95 pore pressure gradient Second Greene County Well spud August 17, 2015 Pettit ,400 vertical depth 4,000-4,500 lateral Wetzel County well planned for September ,700 vertical depth 3,000-3,500 lateral 15

16 EQT RICE CHK SWN COG UPL NFG PXD RRC XCO NBL AR CNX XEC NFX SM STR CXO QEP EOG EGN MDU WLL $/Mcfe CNX AR COG EQT RRC NFG RICE SWN SM XCO XEC UPL EOG WLL CXO NBL QEP NFX CHK EGN MDU $/Mcfe Industry Leading Cost Structure $7 $6 $5 3-year F&D (all sources) Mean = $2.66 $4 $3 $0.73 $2 $1 $0 For the three years ended 12/31/2014 $4 $3 Per Unit Operating Expenses Mean = $1.69 $2 $0.47 $1 $0 Year ended 12/31/

17 EQT Corporation Midstream Overview Consolidated Transmission & Storage* 3.5 Bcf/d current capacity 47 Bcf gas storage capacity Gathering* 2 Bcf/d capacity Formed MLP in 2012 (NYSE: EQM) $600 $500 $400 $300 $200 EQT Corporation Adjusted EQT Midstream EBITDA** EQT Midstream EQT Midstream Partners, LP Production Sales Volumes (Bcfe) $100 $0 EQT Production sales drive EQT Midstream EBITDA growth E*** *As of 12/31/2014 **Excludes Big Sandy and Langley in ; see Non-GAAP Reconciliation in the appendix ***Pro-forma reflecting full-year impact of Northern West Virginia Marcellus Gathering System acquisition

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 Allegheny Valley Connector Tioga 65 MMcf/d Applegate 150 MMcf/d Longhorn 130 MMcf/d Terra 80 MMcf/d 18

19 EQT GP Holdings, LP (NYSE: EQGP) EQT owns 90% LP interest of EQGP EQGP owns in EQM 30% limited partner interest 2% general partner interest incentive distribution rights EQGP Price per Unit Value of EQGP Units held by EQT ($MM) $22 $5,273 $35 $23 $5,513 $36 $24 $5,753 $38 $25 $5,993 $39 $26 $6,232 $41 Value per EQT share 19

20 EQT Midstream Partners, LP (NYSE: EQM) 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 20

21 EQT Midstream Partners, LP Growth Projects 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 Q in-service JV with NextEra Energy, WGL Midstream, and Vega Energy Partners 2 Bcf/d capacity commitments 20-year term 21

22 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 22

23 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 23

24 Investment Summary 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 24

25 Appendix 25

26 Mbbls $/Mcf Liquids Volume Growth and Marcellus Impact Liquids Volume Growth Marcellus Liquids Price Impact (1200 Btu Gas) 10,000 9,000 $6.00 NGLs (1.6 Gal/Mcf) Btu Premium NYMEX 8,000 $5.00 7,000 6,000 $4.00 $3.66 $3.66 5,000 4,000 $3.00 $0.61 $0.48 $0.13 3,000 2,000 1,000 $2.00 $1.00 $3.05 $ F $0.00 Not Processed Processed Includes natural gas liquids and oil 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 $

27 $B Capital Investment Summary $1.6 $1.9 $ $1.2 $ F Midstream Production Distribution Excludes acquisitions and EQT Midstream Partners, LP 27

28 Marcellus Play Acres Within Each Core Development Area 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 EUR (Mcfe) / Lateral Foot Total Net Acres Total Net Undeveloped Acres Locations¹ Southwestern PA 2, , ,000 1,560 Northern WV - Wet 1 2,043 90,000 70, Northern WV - Dry² 1,741 33,000 27, Central PA 3 1,375 80,000 69, , ,000 3,420 1 Based on 5,400 laterals with lateral spacing estimates ranging from 500 to 1,000 2 EQT holds approximately 50,000 acres in the northern WV dry area near-term development focused on 33,000 acres 3 EQT holds approximately 160,000 acres in central PA near-term development is focused on 80,000 acres Type curve and well cost data posted on under investor relations 28

29 Daily Production (MCFED) Marcellus Play Type Curves by Area 5,400 lateral 17,000 16,000 15,000 14,000 13,000 Central PA Northern WV - Wet Northern WV - Dry Southwestern PA 12,000 11,000 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1, Time in Months (First 100 Months Represented) Type curve and well cost data posted on under investor relations 29

30 Marcellus Economics IRR Southwestern PA 600% 500% 400% PRICE ATAX IRR $ % $ % $ % $ % Wellhead After OpEx After Tax 300% 200% 100% 0% $2.50 $3.00 $3.50 $4.00 Realized Price 30

31 Marcellus Economics IRR Northern WV Wet Gas Area 400% 350% 300% 250% GAS PRICE (/MMbtu) Wellhead After OpEx After Tax NGL PRICE ($/bbl) $15.00 $20.00 $25.00 $ % 19% 25% $ % 35% 42% $ % 56% 65% $ % 81% 93% 200% 150% 100% 50% 0% $2.50 $3.00 $3.50 $4.00 Realized Price 31

32 Marcellus Economics IRR Central PA 140% 120% 100% PRICE ATAX IRR $ % $ % $ % $ % Wellhead After OpEx After Tax 80% 60% 40% 20% 0% $2.50 $3.00 $3.50 $4.00 Realized Price 32

33 Marcellus Economics IRR Northern WV Dry Gas Area 140% 120% 100% PRICE ATAX IRR $2.50 7% $ % $ % $ % Wellhead After OpEx After Tax 80% 60% 40% 20% 0% $2.50 $3.00 $3.50 $4.00 Realized Price 33

34 Scotts Run: Utica Well Update Rate and Pressure vs. Time Record Utica IP of 22.6 MMcf / ,221 Lateral Length 24 Hour Test Period IP: 72.9 MMcfd 7 Day Test Period Average: 27 MMcfd with 9,563 CFP Shut in for production tie in *Updated as of 09/24/

35 Scotts Run: Utica Well Results Cumulative Production vs. Time *Updated as of 09/24/

36 Upper Devonian Play Developed in conjunction with Marcellus 170,000 EQT acres 1,560 locations 36 wells online* 24 wells in ,300 laterals 109 acre spacing 8.7 Bcfe EUR / well 1,388 Mcfe EUR / ft. of lateral $5.9 MM / well Upper Devonian development area EQT acreage *As of 06/30/

37 Daily Production (MCFED) Upper Devonian Play Type Curve 6,300 lateral 11,000 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1, Time in Months (First 100 Months Represented) Type curve and well cost data posted on under investor relations 37

38 Upper Devonian IRR 200% 180% 160% 140% PRICE ATAX IRR $ % $ % $ % $ % Wellhead After OpEx After Tax 120% 100% 80% 60% 40% 20% 0% $2.50 $3.00 $3.50 $4.00 Realized Price 38

39 Marcellus Capacity MDth/D 2,500 2,000 1,500 EQT Capacity & Firm Sales FIRM SALES (SHORT-TERM) FIRM SALES (LONG-TERM) FIRM MIDWEST Market Mix 2015E 2016E TETCO M % 19-21% TETCO M % 31-33% TCO 9-10% 9-10% Midwest 9-10% 23-25% NYMEX 14-16% 12-14% FIRM GULF 1, FIRM NORTHEAST - Q Q Q

40 Ample Financial Flexibility to Execute Business Plan EQT Debt ratings Moody s Standard & Poor s Fitch Long-term debt Baa3 BBB BBB- Outlook Stable Stable Stable Strong balance sheet ($ 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 Net debt / capital Manageable debt maturities* 9% * Excludes EQT Midstream Partners 40

41 Risk Management Hedging 2015** 2016*** 2017*** Fixed Price Total Volume (Bcf) Average Price per Mcf (NYMEX)* $ 3.97 $ 4.00 $ 3.84 Collars Total Volume (Bcf) 19 7 Average Floor Price per Mcf (NYMEX)* $ 4.55 $ $ 3.15 Average Cap Price per Mcf (NYMEX)* $ 7.21 $ $ 4.03 *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. 41

42 Price Reconciliation Three Months Ended June 30, Six Months Ended June 30, in thousands (unless noted) 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) $ $ $ $ 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, , Sales volume (Mbbls) Net price ($/Bbl) $ $ $ $ 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, , , ,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 ($/Mcf) (b) Cash settled basis swaps (not designated as hedges) ($/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) 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 (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. 42

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, , , ,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 $

44 Per Unit Operating Expenses UNIT COSTS Three Months Ended Six Months Ended June 30, June 30, Production segment costs: ($/Mcfe) LOE $ 0.12 $ 0.14 $ 0.12 $ 0.14 Production taxes SG&A $ 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 $ 0.32 $ 0.37 $ 0.31 $ 0.35 Total ($/Mcfe) $ 0.74 $ 0.96 $ 0.78 $

45 Appendix Non-GAAP Reconciliation EQT Corporation Adjusted EQT Midstream EBITDA (millions) Midstream operating income $179 $417 $237 $329 $384 Add: depreciation and amortization Less: gains on dispositions Less: Big Sandy and Langley Adjusted Midstream EBITDA $210 $257 $302 $384 $464 45