Analyst Presentation - EQT Investor Center

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