Rice Energy Investor Presentation - August 11, 2014

1 www.riceenergy.com
Second Quarter 2014 Investor Presentation
August 11, 2014

COMPANY TOTAL
OHIO
PENNSYLVANIA
~127,000 net acres in Appalachia
 280 MMcf/d net June production from 55 wells
 61 operated wells in progress
 1,033 net risked locations
 Average horizontal rigs for 2014: 3
~51,000 net acres, <1% developed
 1 producing Utica well (Bigfoot 9H)
 10 operated Utica wells in progress
 246 net risked Utica locations
~76,000 net acres, <5% developed
 54 producing wells (51 Marcellus, 3 Upper Devonian)
 51 operated Marcellus wells in progress
 526 net risked Marcellus locations
 261 net risked Upper Devonian locations
__________________________
Note: Approximately 55,000 net acres in the Marcellus Shale is also prospective for the Geneseo (Upper Devonian) Shale. The Upper Devonian and the Marcellus Shale are stacked formations within the same geographic footprint. See slide entitled “Additional
Disclosures” on detail regarding Rice’s methodology for the calculation of net unrisked and risked locations
Rice Energy – Concentrated Core Position
RICE FT & MIDSTREAM
FT: ~1 Bcf/d firm capacity contracted, 70% to Gulf Coast
and Midwest markets
Midstream: YE2015 throughput capacity of ~ 4.5 Bcf/d

43,978
75,834
46,700
50,77290,678
Q4 2013 Q2 2014
Marcellus Utica
126,606
De-risk production growth, neutralize basis volatility, maximize cash margins
Substantial Growth to Low-Risk Drilling Inventory
Production Growth from High Rate of Return Projects
Securing Additional Access to Premium Markets
Net Core Acreage
325
526
233
246558
772
Q4 2013 Q2 2014
Marcellus Utica
Net Risked Locations
174
262
Q4 2013 Q2 2014
Net Producing Lateral Feet (000s)
154
241
Q4 2013 Q2 2014
Net Production (MMcf/d)
IPO Current
Appalachia Non-Appalachia
756,000
918,000
671,000
591,000
165,000 247,000
2016 Firm Transport
Marcellus development on point + exciting initial results from the Utica
36,000 net acres added, 100% within existing areas of operations
Delivering on Our Plan Since IPO
Accomplishments Since IPO
Increased production by ~60% since year-end 2013
- Turned online 14 Marcellus wells, avg ~8,000’ hz, 30 day avg ~ 13 MMcf/d
Drilled the biggest well in the Utica
- Bigfoot 9H tested at 42 MMcf/d @ 5850 psi
- Producing into sales above type curve
Meaningfully added to our core acreage position
- Leased ~14,000 net acres + acquired 22,000 net acres (~90% PA, ~10% OH)
Secured add’l firm transport to premium markets
- Added 275,000 dth/d with access to Gulf Coast, Midwest and Canadian markets
Invested in our midstream to grow our bottom line
- Acquired Momentum Marcellus gathering system for $110MM
- Constructing 1.0 bcf/d Marcellus header system with FT to Gulf Coast
Basis Exposure (2015-2016)
36%
64%
2015
47%
53%
2016
(1)
__________________________
1. Includes volumes in excess of firm transportation. Non-Appalachian exposure includes TCO

 Disciplined approach to increasing core acreage is transformative to our low risk, high return inventory
– Our asset value is not static and will continue to grow
 By the end of 2014, we expect to have added ~50,000 net acres through organic leasing (~28,000) and the Greene County Acquisition (22,000)
Core Acreage Growth Since 2011
Proven Ability to Grow Core Position

5.3
2.1
4.8
1.1
2.8
0
100
200
300
400
500
600
700
0% 20% 40% 60% 80% 100% 120% 140%
Net Unrisked Drilling Locations
Single Well Pre-Tax IRR %
Deep Inventory of High Returning Projects
Ohio
Utica Dry
Ohio
Utica Wet
Marcellus
Western Greene
Marcellus
Geneseo
Bubble Size indicates net potential reserves, Tcf
 Marcellus: 750 net unrisked drilling locations with 60-110% IRR; type curve de-risked by 50+ producing Marcellus wells
 Ohio Utica: 339 net unrisked drilling locations with 70-120% IRR; first Utica well, Bigfoot 9H, tracking above budgeted EURs
 Upper Devonian: 406 net unrisked drilling locations with 20-30% IRR
 PA Utica: To be determined
16 Tcf of net undeveloped potential reserves – Average 86% IRR to develop 13.3 Tcf from Marcellus and Utica
IRR difference driven by
historical gathering fee

Pennsylvania Assets

AU2 Pad – 2 Wells
Avg 180 Day IP: 8.8 MMcf/d
Avg Lateral Ft: 5,921’
Allegheny
Washington
Greene
Rice Energy AcreageRice Energy AcreageRice Energy Acreage
X-Man Pad – 2 Wells
Thunder 2 Pad – 2 Wells
Lusk Pad – 2 Wells
Brova 1H
Lateral Ft: 3,552’
Big Daddy Pad – 2 Wells
Hulk Pad – 3 Wells
Mono 4H
5.7 Bcf produced in 18 months
Lateral Ft: 6,233’
Whipkey 1H
Avg 180 Day IP:10.5 MMcf/d
Wayne Pad – 4 Wells
Avg 180 Day IP:11.1 MMcf/d
Amigos Pad – 3 Wells
 Acreage: 75,834 net acres in the southwestern core
(100% operated)
– 80% held by production or does not expire until
2017+
 Inventory: 787 total net risked identified drilling
locations, 526 in the Marcellus and 261 in the Upper
Devonian
 Operations: Well results from 51 producing
horizontal Marcellus wells as of June 30, 2014
 51 additional Marcellus wells currently in
progress
Marcellus Overview
_________________________
1. Figures represent pro forma impact from Greene County Acquisition.
Marcellus Well ResultsSummary (1)
 Sustained prolific production rates over a 6-month period
Marcellus Well Results To Date
Wells Turned Avg. Lateral Flow Rates (MMcf/d) D&C
Year(s) To Sales Length 0-90 0-120 0-180 ($/Ft)
2010-2011 6 3,281 5.7 5.8 5.8 2,377$
2012 9 5,731 9.2 9.7 9.6 1,663$
2013 22 6,286 11.2 11.2 10.9 1,469$
1Q 2014 4 6,691 12.7 12.2 11.1 1,348$
2Q 2014 10 8,452 12.9 NA NA 1,243$
Total 51 6,291 10.4 10.2 9.9 1,556$
* Flow rates based on wells with available history
Producing Pad
Pad in Progress

0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
- 200 400 600 800 1,000 1,200 1,400 1,600 1,800
Unmatched Well Performance
__________________________
1. Data for Rice Energy based on actuals through 7/31/14, peer data based on Pennsylvania Department of Environmental Protection production reports through December 31, 2013.
Rice’s drilling and completion techniques have yielded greater production profile per well, versus our peers
Washington & Greene Counties Cumulative Production vs. Time (1)
Cumulative Production (Bcfe)
Days Online
Average 90-Day IP, MarcellusDrilling Proficiency, Marcellus
MMcf/d
5.7
9.2
11.2
12.7 12.9
2010-2011 2012 2013 1Q14 2Q14
3,281
5,731
6,286
6,691
8,452
15.8
7.6
5.8
4.5 4.5
–
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
18.0
–
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
2010-2011 2012 2013 1Q14 2Q14
Avg. Lateral Ft. Avg. Hz. Drilling Days
Rice Washington County
Rice Greene County
Rice Geneseo
Peer Marcellus

__________________________
1. See slide entitled “Additional Disclosures” on detail regarding Rice’s methodology for the calculation of net unrisked and risked locations.
2. Terms being finalized. Historical gathering and compression rate of $0.45/Mmbtu and $0.12/Mmbtu.
We have closed on our previously announced acquisition of 22,000 net acres in the core the SW PA Marcellus
Greene County Acquisition Summary
Rice Pro Forma Acreage MapTransaction Profile
Acreage Summary
 22,000 net acres, 100% operated, average 82% NRI
 ~70% acreage is either HBP or expires in 2017+
Marcellus – 22,000 net acres
 ~20 MMcf/d net from 7 producing wells; 5 wells in progress
 152 risked / 190 unrisked net drilling locations (1), avg ~7,000’ lateral
 1,080-1,100 Btu/Scf
 Reserve profile similar to Rice’s Marcellus wells in SW PA
 Commence pad-drilling in first half of 2015
Utica – 14,000 net acres
 Expecting 1,020-1,040 Btu/Scf
 Initial test in 1H 2015
Geneseo (Upper Devonian) – 18,500 net acres
 135 unrisked net drilling locations (1), avg ~7,000’ lateral
 Expecting 1080-1100 Btu/Scf
 Initial test in 2016
Midstream
 Acreage dedicated to Access Midstream
 No processing needed
Key Terms/Dates
 Closed on 8/1/14 Rice Acreage
Western Greene County Acquisition

($2.0)
–
$2.0
$4.0
$6.0
$8.0
$10.0
$12.0
$14.0
–
20%
40%
60%
80%
100%
120%
140%
160%
180%
200%
$3.00 $3.50 $4.00 $4.50 $5.00
IRR NPV-10
__________________________
Note: Production data through 7/21/14, data normalized to 5,900’ lateral (average lateral length of Rice’s seven producing horizontal wells in western Greene County, PA).
Rice Well Performance, Western Greene Resource Potential & NAV
Whipkey Pad
Amigos Pad
Acquisition of a De-risked, High-Return Marcellus Position
Resource Risked Unrisked
Net Locations 152 190
Value ($mm)
Single-Well PV-10 (at $4 HHUB) $6.1 $6.1
Undeveloped Acreage Value $927 $1,159
PDP Value $75 $75
Total Value Potential $1,002 $1,234
Purchase Price $336 $336
Single Well PV-10 ($MM) and IRR
7%
26%
$0.7
$2.7
$6.1
$9.6
$13.0
58%
107%
180%
Trans Energy
2.0 BCFE/1000’
Chesapeake
Vantage
2.2 BCF/1000’
22,000 Acre
Acquisition
Rice has had considerable success from its development on trend and in close proximity to the acquired acreage.
0.0
1.0
2.0
3.0
4.0
5.0
0 100 200 300 400 500
Bcf
Days
Whipkey and Amigos
Pads
5.0
4.0
1-Year

Rice Acreage
Deep Utica Potential in Pennsylvania
 Porosity in southeast OH extends into southwest PA
– Belmont  Washington
– Monroe  Greene
 Thick, high pressure and high porosity Utica section in southwest PA
at depths between 12,000-13,000’ TVD
– Industry tests underway in SW PA from multiple operators
 We plan to spud our first PA Utica well in early 2015
– To be located on our recently acquired acreage in western Greene County
East
EQT
Preparing
Range
In Progress
Rice (PA)
Permitting
West
OH WV
RICE: ~50k acres
in central Belmont
40+ MMcf/d IP
1050-1150 BTU
RICE: ~15k acres
in western Greene
2015 Test
1020-1040 BTU
12,000 – 13,000’9500’7500’5000’ 6000’
County
0%
6%
12%
Porosity
Peer Avg
20-40 MMcfe/d
1150-1250 BTU
Peer Avg
5-15 MMcfe/d IP
1250-1350 BTU
MuskingumFairfield Guernsey Belmont Ohio/Marshall Washington / Greene
10,500’Depth
PA
Point Pleasant Core

Net Unrisked Locations 560
NRI Hz Ft. Inventory 2.7mm ft.
PV-10 ($mm) $ 8.5
IRR 104 %
Undiscounted Payback 1.0 yrs
D&C ($mm) $ 8.0
Type Curve Assumptions
120-Day IP (MMcf/d) Pre-Processed 13.4
Bcf / 1000' 1.94
Average Lateral Length 6,000
NGL Yield (Bbls / MMcf) -
Gas Mmbtu (Pre-Processed) 1,050
Gas Shrink 0 %
Gross EUR (Bcfe, Post-Processing) 11.6
% Gas 100 %
0
2
4
6
8
10
12
14
16
0.0 yrs 0.5 yrs 1.0 yrs 1.5 yrs 2.0 yrs 2.5 yrs 3.0 yrs
MMcf/d
Actual Production - Historical Average NSAI - 6,000' Lateral
Type Well Economics(2)
1.94 Bcf / 1,000’ Type Curve (1)
IRR Sensitivity (3)
30%
61%
104%
162%
236%
52%
77% 135%
169%
$3.00 $3.50 $4.00 $4.50 $5.00
0%
50%
100%
150%
200%
250%
NYMEX ($ / MMBtu)
Rice’s Marcellus Shale Type Curve
___________________________
1. Represents gross type curve. Actual production is normalized to 6,000’ laterals. Normalized production excludes six wells; five due to suboptimal spacing to offset producing wells and one well excluded because majority of lateral was drilling in suboptimal zone
(second Marcellus well in Company’s history). Data has been adjusted to reflect only producing days.
2. Based on $4.00/MMBtu and 100% WI. Net horizontal feet calculation based on net revenue interest assuming a 18.5% average royalty interest in the Marcellus. Excludes Greene County Acquisition. Includes 190 unrisked locations from Greene County
acquisition. Based on historical gathering and compression fees, single well PV-10 of $6.1mm and single well IRR of 58%.
3. IRR is net to Rice’s ownership interest. Hedged IRR assumes 50% of production hedged at $4.00/MMBtu in the first year and 25% of production hedged at $4.00/MMBtu in the second year.
All wells are produced on restricted choke program
Hedged IRRUnhedged IRR
750
3.7mm ft

Ohio Assets

__________________________
1. Data per RigData as of August 6, 2014.
Growth and Development
 The Utica play as a whole has contracted to the
Southern Utica Core, which has delivered some of
the highest volume shale wells in North America
 Rice controls 50,772 acres concentrated in the heart
of the core in Belmont County, surrounded on all
sides by robust results
 Rice has partnered with one of the most active and
proven operators in the play, Gulfport Energy
(NYSE: GPOR)
– Gulfport and Rice’s acreage positions are very
complementary, leading to substantial
efficiency gains with extended laterals
Utica Rigs Over Time (1)
The Southern Utica Core has become the most active region in the Appalachian Basin
Infrastructure Build-out
 Active build-out of midstream infrastructure to support
production in the Utica
 Take-away capacity out of the Appalachian Basin will
continue to improve
 Rice’s production is expected to be substantially all dry
gas and enables multiple take-away options
November 2012 August 2014
Utica
Fairway
Marcellus
Fairway
Marcellus
Core
Utica
Core
Total Rigs: 49 Rigs in Core: 38 Belmont Rigs: 8
Utica
Fairway
Industry Rigs
Rice Acreage Position
Marcellus
Fairway
Marcellus
Core
Utica
Core
Total Rigs: 33 Rigs in Core: 6 Belmont Rigs: 0
Utica: The Newest Premier Shale Play

 Very consistent and predictable well results clearly define Utica Core in the southern portion of the play
 Wells in Belmont and Monroe have routinely tested > 30 MMcf/d
 Rice’s first well in Belmont, Bigfoot 9H, tested at a stabilized rate of 42 MMcf/d
 Currently producing at a restricted rate of 14 MMcf/d
 Rice Energy controls 50,772 net acres in the center of Belmont County.
 Industry getting very strong results in WV panhandle. Pennsylvania delineation is underway from peers__________________________
Note: Initial production rates are based on operator announcements and public filings.
Gulfport: Shugert 1-2H
3 BCF in 309 Days
(10 MMcf/d avg.)
Belmont
Rice: 1 well
Bigfoot 9H
IP: 42 Mmcfe/d
676 Mmcfe in 49 Days
(14 MMcf/d avg.)
Rice: 2 wells
Blue Thunder Pad
Completing
AR: Gary 2H
2.4 BCF in 157 Days
(15 MMcf/d avg.)
Rice’s acreage is surrounded by the largest producing wells in the Utica
Rice: 5 wells
Digger Pads
Hz Drilling
Industry Results Confirm our Position in the Utica Core
Monroe
Gulfport Irons 1-4H
1.5 BCF in 106 Days
(14 MMcf/d avg.)
MHR Stadler A
184 Mmcf in 8 Days
(23 MMcf/d avg.)
XTO Kaldor 1H
1.2 BCF in 110 Days
(11 MMcf/d avg.)
Rice: 3 Wells
Mohawk Warrior Pad
Tophole Drilling
ECR Tippens
1.3 BCF in 93 Days
(14 MMcf/d avg.)
Gulfport: Stutzman
2.7 BCF in 259 Days
(10 MMcf/d avg.)
20 – 40 Mmcfe
10-20 Mmcfe
< 10 Mmcfe
> 40 Mmcfe
Chevron 1 Well
IP: 20+ Mmcfed
Planned / In Progress
Noble
Guernsey
Harrison
Marshall
Wetzel
Rice Acreage
IP Rates Sized and Color Coded
20 – 40 Mmcfe
10-20 Mmcfe
< 10 Mmcfe
> 40 Mmcfe
Planned / In Progress

Bigfoot 9H Flowing Pressures – Why It’s a Big Deal
Wellhead pressure is the leading indicator of sustainability of initial flow rates. Utica pressure regime suggests our 1.5-2.0
MMcf/d initial flow rate could be sustainable for up to 14 months, approximately 1-8 months longer than our budgeted
Utica type curve
Flow rate decline when
wellhead psi = line psi
Line pressure (750-1500 psi)
FlowRate,Mcf/d
Budget Type Curve
WellheadPressure,psi
Bigfoot Flow Rate Projection
1 Year
Cumulative
5.1 Bcf
3.8 Bcf
4.9 Bcf
18 Month
Cumulative
7.3 Bcf
Bigfoot 9H Actual
Days
Bigfoot 9H is in the heart of our Belmont County position and representative
of the production potential from our remaining drilling locations
Flat Period
Cumulative
5.9 Bcf
Flow rate decline when
wellhead psi = line psi
4.7 Bcf
6.0 Bcf

Belmont + Monroe Counties: The Utica Outliers
Early production results in Belmont and Monroe significantly outperforming the Utica as a whole
-
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
- 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200 1,300 1,400 1,500
CumulativeProduction(Mcfe)
Days Online
Belmont Monroe Other Utica Susquehanna, PA (Marcellus)
 Rice believes Belmont + Monroe could be as potent as leading Marcellus counties
 Rice is set for significant growth with its 50,000 acres in the center of Belmont County Ohio
__________________________
Note: Production data per Ohio Department of Natural Resources.

 Offset operator results mirror Rice’s internal geologic model
– Core Features: Strong Point Pleasant porosity, impermeable Upper Utica cap, highly overpressured
– Essentially 100% of Rice acreage is located in a concentrated area with these characteristics
 Data from initial Rice-operated wells in Belmont County very encouraging:
 Porosity > 14% in our target interval. Strongest in the play.
• First three horizontal wells drilled had 100% of the lateral geosteered within a 4’ sweet spot
 Impermeable Upper Utica cap. Important for fracture containment during completions
 Severely overpressured
• Pressure Gradient > 0.8 psi/ft. Calculated bottomhole pressure > 8000 psi
North South
6 MMcfe2 MMcfe 8 MMcfe 12 MMcfe 30 MMcfe
0%
6%
Rice Belmont
Leasehold
Porosity
12%
__________________________
Note: Initial production rates are based on operator announcements and public filings.
20 MMcfe1 MMcfe Pending Results
Utica
Point Pleasant Core
Rice Energy controls ~50,772 net acres in the heart of the high porosity Point Pleasant core in Belmont County
CRAWFORD MERCERERIE BEAVER COLUMBIANA CARROLL JEFFERSON BELMONT MONROE WASHINGTON ATHENSMERCER WASHINGTON
Point Pleasant Core
Belmont + Monroe Counties
30+ MMcfe/d
20-30 MMcfe/d
10-20 MMcfe/d
5-10 MMcfe/d
0-5 MMcfe/d
High Volume Wells Predicted by Geologic Model
30-40 MMcfe/d
20-30 MMcfe/d
10-20 MMcfe/d
5-10 MMcfe/d
0-5 MMcfe/d
>40 MMcfe/d

55
45
28
19
28
10
6
0
10
20
30
40
50
60
70
0
200,000
400,000
600,000
1
3
5
7
9
11
13
15
17
19
21
23
25
27
29
31
33
35
37
39
Utica Learning Curve Update
Systematically reducing drilling days/costs while maintaining precision wells
Improved Gas
Control Procedures
Improved Mud
Properties
Improved Bit
Selection
Remainder of Delineation Program
• Fit-for-Purpose Deep Tophole Rig (June)
• More aggressive bit selection
• Deep casing elimination trial
• Fit-for-Purpose Horizontal Rig (June)
• Reduction of discretionary science
• Pad drilling (2H 2014)
Initial Observations from Utica Development
1. Drilling
– Utica is extremely brittle, highly charged with gas, and consistent across acreage.
– Very calm geologic environment leading to 100% lateral placement in 4’ sweet spot
2. Completions
– Formation is highly receptive to Rice’s aggressive frac design.
– First 100 stages pumped: 100% of sand placed in the ground with no issues
3. Production
– Smooth and predictable production profile. 100% uptime on first well through two months
4. Landowners + Community
– Very supportive. Maintaining open communication with planning
Lateral Length
Well Name
Lateral Targeting Proficiency
Completion Proficiency
# Sand pumped per stage
Blue Thunder 10H: 9000’ Lateral
Bigfoot 9H: 40 Stage Frac
5 wells off two adjacent pads to be completed and turned to sales together
“Tandem Pads”
Year End 2014 Goal: < 30 Days for 9000’ Laterals

NRI Hz Ft. Inventory 2.1mm ft.
PV-10 ($mm) $ 13.4
IRR 70 %
D&C ($mm) $ 14.0
120-Day IP (MMcf/d) Pre-Processed 17.1
Bcf / 1000' 2.25
NGL Yield (Bbls / MMcf) -
Gas Shrink 0 %
% Gas 100 %
Utica Dry – Type Well Economics (1) Utica Dry – IRR Sensitivity (2)
___________________________
1. Based on $4.00/MMBtu and 100% WI. Net horizontal feet calculation based on net revenue interest assuming a 20% average royalty interest in the Utica.
2. IRR is net to Rice’s ownership interest. Hedged IRR assumes 50% of production hedged at $4.00/MMBtu in the first year and 25% of production hedged at $4.00/MMBtu in the second year.
21% 41%
70%
108%
155%
33%
51% 91%
115%
$3.00 $3.50 $4.00 $4.50 $5.00
0%
50%
100%
150%
200%
NYMEX ($ / MMBtu)
Utica Wet – Type Well Economics (1) Utica Wet – IRR Sensitivity (2)
57%
85%
119%
160%
210%
78%
98% 142%
166%
$3.00 $3.50 $4.00 $4.50 $5.00
0%
50%
100%
150%
200%
250%
NYMEX ($ / MMBtu)
Utica Single-Well Economics
NRI HzFt. Inventory 0.5mm ft.
PV-10 ($mm) $ 19.6
IRR 119 %
D&C ($mm) $ 8.0
120-DayIP (MMcf/d) Pre-Processed 15.2
Bcf / 1000' 2.00
NGL Yield (Bbls / MMcf) 40
Gas Shrink 15 %
% Gas 78 %
Bigfoot 9H production performance indicates significant upside potential to our single-well economics. We will update
EURs, type curves and single-well economics in January 2015

Midstream Assets

Midstream Overview
Washington
ColumbiaGas(TCO)
NationalFuelGasSupply(NFGS)
Committed to operating our gas gathering assets to maximize transportation potential via 1 Bcf/d of firm capacity with
access to premium US markets. Through YE 2014, RICE will have invested $475 million in midstream infrastructure with 4.5
Bcf/d of outlet capacity in the cores of the Marcellus and Utica shales
Rockies Express
 Firm Capacity: 175 Mdth/d
 In-service date: Summer 2015
Texas Eastern (TETCO)
 Firm Capacity: ~540 Mdth/d
OH Water System
 Withdrawal Capacity: 5 MMgpd
 Expected Savings: $500k/well
Dominion Transmission
 In-service
PA Water System
 Withdrawal Capacity: 5 MMgpd
 Expected Savings: $500k/well
 In-service date: 1H15
Columbia (TCO)
 In-service date: In-service
Dominion East Ohio
 In-service
Texas Eastern (TETCO)
 In-service date: 4Q14
ET Rover
 Firm Capacity: 100 Mdth/d
Allegheny
Marshall
Belmont
Monroe
Harrison
Jefferson
Brooke
Greene
Ohio

Gulfport (negotiating)
 Dedicated Acreage: ~17,000 gross
 AMI: ~60,000 acres
Midstream Recent Developments
Summary of 3rd Party Opportunities
We have entered into a letter of intent with Gulfport Energy to provide midstream services for a
predominantly dry gas area covering approximately 65% of Gulfport’s acreage within our area of mutual
interest (AMI)
EQT
 Dedicated Acreage:
~17,000 gross
Antero
 Dedicated Acreage: ~4,000
gross
Range
 Johnson Pad
dedicated

TETCO
TCO
DTIDEO
REX
ET Rover
–
200
400
600
800
1,000
1,200
7/1/14 7/1/15 7/1/16 7/1/17 7/1/18 7/1/19 7/1/20
BBtu/d
Firm Transportation and Firm Sales Portfolio
For production growth assurance and net realized pricing, firm capacity is creating differentiation amongst Appalachian producers. Rice
Energy was early in identifying and securing its basin-leading portfolio of firm capacity.
 Expect ~100% of 2015 production and substantial majority of 2016 production to be protected by FT and FS
Firm Transport De-risks Production Growth
__________________________
1. Average for remaining 2014.
Average FT & FS Portfolio (Bbtu/d)
2014 2015 2016 2017 2018 2019 2020
453 811 918 958 1,003 985 938
Recently Acquired ET Rover Capacity:
100,000 MMBTU/D of capacity, 15 year contract,
$0.80/MMBTU demand charge, expected in-
service July 2017
(1)

46% 39% 53% 64% 53%
54%
61%
47%
36%
47%
($0.74) ($0.86)
($0.60)
($0.46)
($0.49)
($1.00)
($0.90)
($0.80)
($0.70)
($0.60)
($0.50)
($0.40)
($0.30)
($0.20)
($0.10)
$0.00
0%
20%
40%
60%
80%
100%
2Q14 3Q14 4Q14 2015 Average 2016 Average
Differential to NYMEX
($/MMbtu)Basis Exposure
Non-Appalachia Appalachia Weighted Average Basis
Quarterly Basis Exposure
Southwest Appalachia basis exposure is significantly reduced by 4Q14 and over 60% of 2015 volumes will access attractive Gulf Coast,
Midwest and TCO markets
Long-Haul Firm Transport Improves Realized Pricing
__________________________
1. Non-Appalachia includes TCO, Gulf Coast, and Midwest exposure.
(1)
Nov. 14 - TETCO
ELA Capacity online
 In November 2014, we begin shipping 270,000 MMbtu/d from TETCO to East Louisiana, thereby shifting a significant amount of production to premium Gulf Coast
pricing and significantly improving our overall average expected basis differential

$3.88
$3.50
$2.94$0.67
$0.16 $0.13 $0.56
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
NYMEX Strip
(7/1-12/31)
Less:
Weighted
Avg. Basis
Impact
Plus: 1,050
BTU
Gas Uplift
Plus: NYMEX
&
Basis
Hedges
Realized
Price
Less: G&T
Expense
Net
Price
$/MMBtu
30%
20%
21%
16%
13%
11%
35%
51%
0% 1%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2014 2015
M2 Dom S TCO Gulf Coast Midwest
$0.56 $0.60
$0.68 $0.49
$1.23
$1.09
$-
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
$1.40
7/1/14 - 12/31/14 2015
$/MMBtu
FT+FS Basis
(17%)
(12%)
(35%)
(30%)
(25%)
(20%)
(15%)
(10%)
(5%)
0%
5%
2014 2015% of NYMEX
TCO M2 Dom S
Gulf Coast Midwest Weighted Average
Rice’s firm transportation and sales contracts provides basis and pricing diversification
Firm Transportation, Firm Sales and Basis (cont’d)
Basis Exposure (1)
(7/1 - 12/31)
__________________________
1. These amounts include approximately 115,000 MMBtu/d of firm sales contracted with a third party through October 2017, subject to annual renewal.
2. NYMEX and basis strips as of 7/24/14.
Volume Weighted Basis Impact (1) (2)
Estimated 7/1-12/31/14 Realized Price Bridge (2)
52%
exposed to
M2 and
Dom S
37% exposed
to M2 and
Dom S
All-In G&T Expense + Basis (assuming NYMEX strip) (2)
Assuming Strip Prices
(-17% to NYMEX)
(7/1 - 12/31)
$0.67
17%

Financial Overview

Beta Acq. PF
($ in millions) 6/30/14 Adj. 6/30/14
Cash $472 ($311) $161
1st Lien Rev. Credit Fac. -- -- --
Long Term Debt
Senior Unsecured Notes 900 -- 900
Other Debt 1 -- 1
Total Debt $901 $901
Book Equity $1,190 -- $1,190
Total Capitalization $2,092 $2,092
Liquidity
Borrowing Base $385 $40 $425
Less: Amount Drawn -- --
Less: Letters of Credit (6/30) (72) (72)
Plus: Cash 472 ($311) 161
Liquidity $786 $515
2Q 2014 Snapshot
2Q14 Summary
 Net production of 241 MMcfe/d, 84% and 15% increase over 2Q13
and 1Q14 volumes, respectively
 June net production of 280 MMcfe/d
 10 Marcellus wells turned to sales with an average lateral length of
~8,400 ft. that produced 132 MMcf/d gross in the month of June
 Increased Pennsylvania leasehold position to 75,834 net acres,
including ~22,000 completed Greene County acquisition and
increased Ohio leasehold position to 50,772 net acres
RICE HAS MAINTAINED OPERATIONAL EXCELLENCE AND LIQUIDITY; CONTINUES TO BUILD AND DELINEATE CORE POSITION
___________________________
1. Beta Acquisition Adjustment for cash payment post 6/30/14
2. Management estimate. Borrowing base redetermination set for October 2014.
Capitalization and Liquidity
2Q14 Summary
Net Daily Production (MMcfe/d) 241
Net Daily Production (BBtu/d) 1,050 253
Henry Hub ($/MMBtu) $4.58
Less: Basis Differential (0.74)
Plus: BTU Uplift 0.19
Plus: Other Revenue 0.09
Realized Pricing ($/Mcfe) - pre-hedges $4.12
Realized Pricing ($/Mcfe) - post-hedges $3.68
Operating Metrics
E&P Revenue $4.12
Plus: Hedge Gain/(Loss) (0.45)
Less: LOE & Taxes (0.34)
Less: Gathering/Transportion (0.42)
Less: Cash G&A (0.68)
Plus/Less: Other Income / (Expense) 0.05
EBITDAX ($/Mcfe) $2.29
(1)
(2)

Update to 2014 Guidance
__________________________
Note: Pro forma for ASR & Greene County acquisitions.
Rice has updated 2014E guidance to better reflect management’s current outlook
 Total net production range has tightened due to greater visibility of pad turn-to-sales timing
 Drilling and completions capital of $570 mm reflecting timing adjustments to our drilling schedule
 Lease operating expense is trending lower as Marcellus shifts to “development mode”
 SG&A has increased as a result staying ahead of our prolific production growth and an increased build-out of our midstream group
FY2014 Income Statement & Capital Expenditure Guidance Update
Updated 2014E
Low High
Income Statement Guidance
Total Net Production (MMcfe/d) 260 295
% Dry Gas 100%
Heat Content 1050
Lease Operating Expense ($/Mcfe) ($0.35) ($0.30)
Gathering & Transportation ($/Mcfe) (0.55) (0.45)
Production Taxes & Impact Fees ($/Mcfe) (0.03) (0.02)
Cash G&A ($ mm) $65 $60
Net Wells Turned to Sales Updated 2014E
Marcellus 34
Utica 5
Total 39
Capital Expenditure Guidance ($ mm)
D&C $570
Midstream 265
Land 385
Total ($ mm) $1,220

Commodity Hedging Summary
 We employ financial instruments (primarily swaps and
costless collars) to mitigate commodity price risk
 Assures a base level of cash flow to reinvest in growth
 Typically target hedging 50% of forecasted production
for up to two years out
 Add incremental hedges opportunistically beyond two
years
 Utilize our bank group as counterparties to avoid cash
collateral and margin calls
__________________________
1. Hedges as of 5/1/14.
Hedge Book (1)Strategy
60-80% of 2014
Production Guidance Hedged
7/1-
YE2014 2015 2016 2017
NYMEX Henry Hub Contract Summary
Natural Gas Swaps
Volume Hedged (Bbtu/d) 164 92 148 60
Weighted Average Swap Price ($/MMBtu) $4.12 $4.16 $4.20 $4.24
Collars
Volume Hedged (Bbtu/d) 10 139 -- --
Weighted Average Floor Price ($/MMBtu) $3.00 $3.96 -- --
Weighted Average Ceiling Price ($/MMBtu) $5.80 $4.65 -- --
Deferred Puts
Volume Hedged (Bbtu/d) 50 -- -- --
Put Price ($/MMBTU) $4.55 -- -- --
Put Premium ($/MMBTU) $0.45 -- -- --
Total Volume (BBtu/d) 224 231 148 60
Weighted Average Floor ($/Mmbtu) $4.06 $4.04 $4.20 $4.24
% Swap 73% 40% 100% 100%
Basis Contract Summary
TCO
Volume (BBtu/d) 47 37 17 --
Swap Price ($/MMbtu) ($0.27) ($0.42) ($0.42) --
Dominion South
Volume (BBtu/d) 8 25 21 --
Swap Price ($/MMbtu) ($0.79) ($0.79) ($0.79) --

Why Invest in Rice?
100% of Leasehold in Core of Marcellus and Utica100% of Leasehold in Core of Marcellus and Utica
Owned and Operated Gathering and Water Midstream
Infrastructure Supports Our Upstream Operations
Owned and Operated Gathering and Water Midstream
Infrastructure Supports Our Upstream Operations
Differentiated Technical Approach Has Led to Industry Leading Well ResultsDifferentiated Technical Approach Has Led to Industry Leading Well Results
Conservative Financial and Hedging Approach to Protect Downside and
Lock-In Attractive Returns
Conservative Financial and Hedging Approach to Protect Downside and
Lock-In Attractive Returns
Nimble and Incentivized Management and Technical TeamsNimble and Incentivized Management and Technical Teams
Top-Tier Growth With Attractive Risk-Adjusted Return ProfileTop-Tier Growth With Attractive Risk-Adjusted Return Profile
Firm Transportation Contracts De-risk Production Growth,
Ensure Takeaway and Limit Appalachian Basis Exposure
Firm Transportation Contracts De-risk Production Growth,
Ensure Takeaway and Limit Appalachian Basis Exposure

Appendix

1
17 22
28 44 47
70
89
131 128
154
209
241
3 5 13 22 28 35
55 58
84
110
173 177
208
275
319
-
50
100
150
200
250
300
350
4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q
Net Daily Production Gross Daily Production
1,127
893 870
1,058
826 878
675 621 658 638 702
537 454 434
1,437
1,423 1,437 1,188
1,000 999
763 927 844 878 797
828 895 809
2,564
2,315 2,307 2,246
1,826 1,877
1,438
1,549 1,502 1,515 1,500
1,365 1,348
1,243
$-
$500
$1,000
$1,500
$2,000
$2,500
$3,000
Drilling Cost per Foot Completion Cost per Foot
2
17 17 23 30 45 65
80
114
150
174
224
251
342
1 3 5 5 7 8
11
15 17
23
29
33
40
44
55
-
10
20
30
40
50
60
-
50
100
150
200
250
300
350
400
Horizontal Feet Horizontal Wells
| 2013 |
Established Track Record of Drilling Proficiency
Producing Horizontal Feet and Wells (Gross) Average Daily Production
MMcf/dFeet (‘000)
Wells
Average Lateral Length (2) Average PA Drilling & Completion Cost Per Lateral Foot
Proven track record of growing production, reducing costs and improving drilling efficiency
NA (1)
_______________________
1. No wells brought online in Q3 2011.
2. Well data based on IP date.
| 2011 | | 2012 | 20142010
| 2011 | | 2012 | | 2013 | 20142010
| 2011 | | 2012 | | 2013 | 20142010
# Rigs 2 2 2 2 2 2 2 2 2 2 3 4 4 3 2
2,444 3,281
5,731
6,286
6,691
8,452
24.4
13.3
7.6
5.8
4.5 4.5
–
5
10
15
20
25
30
–
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
2010 2011 2012 2013 1Q14 2Q14
DrillingDays
LateralLength(feet)
Avg. Lateral Ft. Avg. Hz. Drilling Days

374
152 193
53
560
190
270
69
104%
58%
70%
119%
0%
20%
40%
60%
80%
100%
120%
140%
–
100
200
300
400
500
600
Marcellus W Greene Utica Dry Utica Wet
IRR
NetLocations
Risked Locations Unrisked Locations IRR
 Marcellus Inventory: 12+ Years, weighted
average single well return of ~92%
– Type curve de-risked by historical production
 Utica Inventory: 15+ Years, weighted average
single well return of 78%
– First Utica well, Bigfoot 9H, tracking above
expectations
Difference
driven by
historical
gathering fee
Deep Inventory of High Returning Projects
___________________________
Note:. Net horizontal feet calculation based on net revenue interest assuming a 18.5% average royalty interest in the Marcellus and 20.0% average royalty interest in the Utica. See slide entitled “Additional Disclosures” on detail regarding Rice’s methodology for the
calculation of net unrisked and risked locations
1. Economics based on $4.00/Mmbtu and 100% WI.
2. Acquired acreage dedicated to Access Midstream Partners. Historical gathering fee of $0.45/mmbtu and historical compression fee of $0.12/mmbtu. Rice currently in negotiations with Access to determine terms of new gathering agreement.
(2)
W. Greene Utica Utica
Marcellus Acq. Dry Wet
Pre-TaxNPV10 ($MM) $8.5 $6.1 $13.4 $19.6
Pre-TaxIRR 104% 58% 70% 119%
Net F&D ($/mcf) $0.84 $0.76 $0.80 $0.81
Net Risked Locations 374 152 193 53
Net Unrisked Locations 560 190 270 69
Undiscounted Unrisked Value ($MM) $4,763 $1,159 $3,617 $1,352
Unrisked NRI HZ Ft Inventory (mmft) 2.7 1.1 2.1 0.5
Type Curve Assumptoins
120-Day IP (MMcf/d) Pre-Processed 13.4 15.6 17.1 15.2
Bcf/1,000' 1.94 1.94 2.25 2.00
Average Lateral Length (Ft) 6,000 7,000 9,700 9,700
NGL Yield (Bbls/MMcf) – – – 40.0
Modeled BTU 1,050-1,100 1,090 1,080 1,200
Shrink – – – 15%
Gross EUR (Bcfe) 11.6 13.6 21.8 21.1
Well Cost ($MM) $8.0 $8.4 $14.0 $14.0
Historical Gathering + Compression Fee ($/MMBTU) – $0.57 – –

2Q 2014 Adjusted EBITDA Reconciliation
__________________________
Note: Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net
income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; depreciation, depletion and amortization; amortization of deferred financing costs; equity in (income) loss of our joint ventures; derivative fair value (gain) loss,
excluding net cash receipts on settled derivative instruments; non-cash compensation expense; (gain) loss from sale of interest in gas properties; (gain) loss on acquisition; (gain) loss on extinguishment of debt; write-off of deferred financing costs; and exploration
expenses. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP. Gives pro forma effect to (i) our initial public offering and the completion of the corporate
reorganization in connection with our initial public offering and (ii) the consummation of our acquisition of the remaining 50% interest in our Marcellus joint venture from Alpha Natural Resources, Inc., each of which was completed on January 29, 2014, as if such
transactions had been completed on the first day of the period presented.
1. The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end
of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDAX on a cash basis during the period the derivatives
settled.
2. Represents gain incurred on the purchase of the remaining 50% interest in our Marcellus joint venture.
Three Months Ended Six Months Ended
($ in thousands) June 30, 2014 June 30, 2014
Adjusted EBITDAX reconciliation to net income (loss):
Net income (loss) $(7,917) $121,538
Interest expense 15,941 22,983
Depreciation, depletion and amortization 32,552 58,059
Amortization of deferred financing costs 532 1,021
Amortization of intangible assets 340 340
Equity in loss of joint ventures -- 2,656
Derivative fair value (gain) loss (1)
11,198 31,578
Net cash receipts on settled derivative instruments (1)
(9,795) (20,953)
Gain on purchase of Marcellus joint venture (2)
-- (203,579)
Non-cash stock compensation expense 1,125 1,216
Non-cash incentive unit expense 1,474 75,276
Income tax (benefit) expense (4,593) 4,782
Loss on extinguishment of debt 3,001 3,144
Write-off of deferred financing costs 6,060 6,896
Exploration expenses 473 959
Adjusted EBITDAX $50,391 $105,916

Cautionary Statements
FORWARD-LOOKING STATEMENTS
This presentation and the oral statements made in connection therewith may contain “forward looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. All statements, other than statements of historical fact, regarding Rice Energy’s strategy, future operations, financial position, estimated revenues and income/losses,
projected costs, prospects, plans and objectives of management are forward-looking statements. These statements often include the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,”
“project” and similar expressions intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based
on Rice Energy’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Rice Energy assumes no
obligation to and does not intend to update any forward looking statements included herein. Rice Energy cautions you that these forward-looking statements are subject to all of the risks and uncertainties,
most of which are difficult to predict and many of which are beyond their control, incident to the exploration for and development, production, gathering and sale of natural gas, natural gas liquids and oil.
These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks,
regulatory changes, the uncertainty inherent in estimating natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the
other risks described under “Risk Factors” in Rice Energy’s Form 10-K filed on March 21, 2014 and other filings with the Securities and Exchange Commission. Should one or more of these risks or
uncertainties occur, or should underlying assumptions prove incorrect, Rice Energy’s actual results and plans could differ materially from those expressed in any forward-looking statements.
This presentation has been prepared by Rice Energy and includes market data and other statistical information from sources believed by Rice Energy to be reliable, including independent industry
publications, government publications or other published independent sources. Some data are also based on Rice Energy’s good faith estimates, which are derived from its review of internal sources as
well as the independent sources described above. Although Rice Energy believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and
completeness.
Certain of Rice Energy's wells are named after superheroes and monster trucks, some of which may be trademarked. Despite their size and strength, Rice Energy's wells are in no manner affiliated with
such superheroes or monster trucks.
Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas
resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
NON-PROVEN OIL AND GAS RESERVES
The SEC permits oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing economic and operating conditions and certain probable and possible reserves that meet the SEC’s definition for such terms. We
may use certain broader terms such as EUR (estimated ultimate recovery of resources), and we may use other descriptions of volumes of potentially recoverable hydrocarbon resources throughout this
presentation that the SEC does not permit to be included in SEC filings. These broader classifications do not constitute reserves as defined by the SEC, and we do not attempt to distinguish these
classifications from probable or possible reserves as defined by SEC guidelines.
Our estimates of EURs have been prepared by our independent reserve engineers. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and
accordingly are subject to substantially greater risk of being actually realized, particularly in areas or zones where there has been limited or no drilling history. We include these estimates to demonstrate
what we believe to be the potential for future drilling and production by the company. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. In
addition, we have made no commitment to drill all of the drilling locations which have been attributed to these quantities. Ultimate recoveries will be dependent upon numerous factors including actual
encountered geological conditions, the impact of future oil and gas pricing, exploration and development costs, and our future drilling decisions and budgets based upon our future evaluation of risk, returns
and the availability of capital and, in many areas, the outcome of negotiation of drilling arrangements with holders of adjacent or fractional interest leases. Estimates of resource potential and other figures
may change significantly as development of our properties provide additional data and therefore actual quantities that may ultimately be recovered will likely differ from these estimates.
Our forecast and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells, the undertaking and outcome of future drilling
activity and activity that may be affected by significant commodity price declines or drilling cost increases.

Determination of Identified Drilling Locations as of June 30, 2014 pro forma for ASR buy-in (closed 1/29/14) and Greene County acquisition (closed 8/1/14)
Our gross (net) identified drilling locations are those drilling locations identified by management based on the following criteria:
Drillable Locations – These are mapped locations that our Vice President of Exploration & Geology has deemed to have a high likelihood as being drilled
or are currently in development but have not yet commenced production. With respect to our Pennsylvania acreage, pro forma for the ASR buy-in and the
Greene County acquisition, we had 330 gross (301 net) pro forma drillable Marcellus locations and 134 gross (117 net) pro forma drillable Upper Devonian
locations. With respect to our Ohio acreage, we had 636 gross (191 net) drillable Utica locations, all of which are located within the contract areas covered
by our Development Agreement and AMI Agreement with Gulfport.
Estimated Locations – These remaining estimated locations are calculated by taking our total acreage, less acreage that is producing or included in
drillable locations, and dividing such amount by our expected well spacing to arrive at our unrisked estimated locations which is then multiplied by a risking
factor. For our existing Marcellus acreage position and acreage acquired through the ASR buy-in, we assume these Marcellus locations have 6,000 foot
laterals and 600 foot spacing between Marcellus wells which yields approximately 80 acre spacing. For the Greene County acquisition, we assume these
Marcellus locations have 7,000 foot laterals and 600 foot spacing between Marcellus wells which yields approximately 100 acre spacing. We assume these
Upper Devonian locations have 6,000 foot laterals and 1,000 foot spacing between Upper Devonian wells which yields approximately 140 acre spacing. We
assume Utica locations have 8,000 foot laterals and 600 foot spacing between Utica wells which yields approximately 110 acre spacing.
With respect to our Pennsylvania acreage, we multiply our unrisked estimated Marcellus and Upper Devonian locations by a risking factor of 50% to arrive
at total risked estimated locations. As a result, we had 233 gross (225 net) pro forma estimated risked Marcellus locations and 148 gross (144 net) pro
forma estimated risked Upper Devonian locations. With respect to our Ohio acreage, we multiply our unrisked estimated locations by a risking factor of
approximately 37% to arrive at total risked estimated locations. We then apply our assumed working interest for such location, calculated by applying the
impact of assumed unitization on the underlying working interest as well as, in the case of locations within the AMI with Gulfport, the applicable participating
interest. As a result, we had 139 gross (55 net) estimated risked Utica locations. Estimated locations include ununitized locations that have been risked
(50% in the Marcellus, 37% in the Utica) to take into account the risk of forming drilling units.
Risked Locations – Consist of Drillable Locations and Risked Estimated Locations. We assume 563 gross (526 net) risked Marcellus locations. We
assume 282 gross (261 net) risked Upper Devonian locations. We assume 775 gross (246 net) risked Utica locations.
Unrisked Locations – Consist of Drillable Locations and Unrisked Estimated Locations. We assume 797 gross (750 net) unrisked Marcellus locations. We
assume 430 gross (406 net) unrisked Upper Devonian locations. We assume 1,011 gross (339 net) unrisked Utica locations.
Additional Disclosures

Rice Energy Investor Presentation - August 11, 2014

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