1. business and industrial
2. energy
3. natural gas

1
3Q14 Supplemental Slides
November 12, 2014
www.riceenergy.com
Proficient Operator with Concentrated, Core Assets
COMPANY TOTAL (1)
~136,500 net acres in Appalachia
 ~1,100 net undeveloped locations
 288 MMcfe/d net Sept. production from 63 net wells
 51 gross (40 net) operated wells in progress
Marcellus Core
PENNSYLVANIA
~82,700 net acres, <5% developed
 490 net undeveloped Marcellus locations
 271 net undeveloped Upper Devonian locations
 61 net producing wells (58 Marcellus, 3 Upper Devonian)
 36 gross (30 net) operated Marcellus wells in progress
Utica Core
OHIO
~53,800 net acres, <1% developed
 333 net undeveloped Utica locations
 3 gross (2 net) net producing Utica wells
 15 gross (10 net) operated Utica wells in progress
RICE FT & MIDSTREAM
FT: ~1.3 MMdth/d (1.2 Bcf/d)(2) firm capacity, ~60% to Gulf
Coast and Midwest markets by Q1’15  80% by Q4’17
Midstream: 6.7 MMDth/d (6.4 Bcf/d) (2) gas gathering capacity by YE 2015
__________________________
(1) Net undeveloped locations as of 9/30/14. 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 locations.
(2) Conversion of Dth to Mcf assumes 1,050 Btu factor
2
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Third Quarter 2014 Highlights
 Turned 5 Pennsylvania Marcellus wells to sales
Execution is Driving
Industry–Leading Growth
– Average lateral length of ~8,200 ft. & currently producing 11.8 MMcf/d
 Initiated production from two Blue Thunder Ohio Utica wells
– Average lateral length of 9,000 ft. & currently producing 16 MMcf/d
 Bigfoot continues to produce ~14 MMcf/d
 Added 10,000 net acres to our core Marcellus and Utica positions
 Commissioned gathering line from Washington Co. to TETCO on 10/31
 TETCO TEAM South project in-service in September (ahead of schedule)
Developing Midstream
Advantage
Enhancing Liquidity to Provide
Additional Financial Flexibility
– 270,000 Dth/d to Gulf Coast improves realized pricing; sold our
September capacity for $9.7MM, or $1.20/Dth (net of FT charge)
 Acquired 320,000 Dth/d on TETCO’s Access South project with firm path
to Gulf Coast markets and expected in-service date of November 2017
 1.3 MMDth/d (1.2 Bcf/d) FT + FS
 Completed 7.5MM share equity offering for ~$196MM net proceeds to
fund western Greene County acreage acquisition
 Increased borrowing base to $550MM in October, providing pro forma
liquidity of ~$615MM as of September 30,2014
 Positioned to fund 2015 capital program with no RICE equity offerings
3
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Third Quarter 2014 Financial Summary
Solid third quarter results supported by well capitalized balance sheet and ample liquidity
Financial Summary(1)
Capitalization and Liquidity
 Adjusted EBITDAX of $53.4MM
 Third quarter net production of 247 MMcfe/d; 93% increase
above prior year period
 Achieved 288 MMcfe/d in Sept. 2014; 129% higher than Sept.
2013 production and 65% above YE13 exit rate
– 65% 3Q14 production sold into local Appalachian markets,
narrows to ~50% in Q4 2014
 Borrowing base increased to $550MM from $385MM,
resulting in pro forma liquidity of $615MM as of 09/30/14
 Completed equity offering of 7.5MM primary shares
resulting in $196MM net proceeds
Operating Statistics
Capitalization and Pro Forma Liquidity at 9/30/2014
3Q 2014
Actual
Net Daily Production (MMcfe/d)
Net Daily Production (BBtu/d)
247
260
Henry Hub ($/MMBtu)
Less: Basis Differential
Plus: BTU Uplift
Realized Pricing ($/Mcfe) - pre-hedges
Plus: FT Sales, Net
Adjusted Realized Pricing ($/Mcfe) - pre-hedges
Adjusted Realized Pricing ($/Mcfe) - post-hedges
Operating Metrics
E&P Revenue (Including FT Capacity Sales, Net)
Plus: Hedge Gain/(Loss)
Less: LOE & Taxes
Less: Gathering/Transportion
Less: Cash G&A
Plus/Less: Other Income / (Expense)
EBITDAX ($/Mcfe)
$3.94
(1.11)
0.14
$2.97
0.43
$3.40
$3.41
$3.40
Actual
$78
$0
($6)
($10)
($10)
$1
$53
$/Mcfe
$3.41
$3.40
0.01
(0.25)
(0.42)
(0.46)
0.06
$2.35
($ in millions)
Cash
PF
9/30/14
$132
$--
$132
1st Lien Rev. Credit Fac.
--
--
--
Long Term Debt
Senior Unsecured Notes
Other Debt
Total Debt
900
1
$901
---
900
1
$901
Shareholders Equity
Total Capitalization
$1,413
$2,314
--
$1,413
$2,314
Liquidity
Borrowing Base
Less: Amount Drawn
Less: Letters of Credit
Plus: Cash
Liquidity
$385
-(67)
132
$450
$165
$550
-(67)
132
$615
__________________________
(1) References to prior year period production throughout this presentation is pro forma for our acquisition of the remaining 50% interest in our Marcellus JV from Alpha Natural Resources, Inc. on January 29, 2014
4
Base
Adj.
9/30/14
$--
www.riceenergy.com
Established Track Record of Drilling Proficiency
Average Net Daily Production
MMcfe/d
241
250
Average Lateral Length v. Horizontal Drilling Days(1)
Feet
247
10,000
209
200
150
4,000
47
50
2012
2013
PA
1Q14
OH
2Q14
0
3Q14
4.5
2012
2013
OH
4.6
4.1
1Q14
2Q14
3Q14
Avg. Marcellus Hz. Drilling Days
18
16
14
12
10
8
6
4
2
–
Average Drilling & Completion Cost Per Lateral Foot(1)
$/Foot
Wells IP
40
3,500
35
3,000
30
2,500
25
$3,241
$2,377
2,000
20
7
10
2010-2011
2012
$1,924
$1,476
$1,349
$1,254
$1,247
1,000
21
10
$1,660
1,500
34
15
0
2010-2011
PA
Net Operated Wells Turned To Sales
5
5.8
2,000
8
2010-2011
7.6
3,281
8,163
9,000
6,957
6,691
6,286
5,731
6,000
127
8,452
15.8
8,000
100
0
Days
500
2013
0
2014E
_______________________
1.
Operated.
5
2010-2011
2012
2013
PA
OH
1Q14
2Q14
3Q14
www.riceenergy.com
Strong Execution Drives Consistent Marcellus Results
Marcellus Pads in Progress
Operational Highlights
 Turned online 5 wells from Brova Pad
– Average laterals of ~8,200’
Pollock North 1 Pad – 4 Wells
Avg. Lateral Ft: 3,800’
Status: WOPC
– Currently producing 11.8 MMcfe/d
 Turned online 17 Marcellus wells (15 net) in 4Q14
– October: 8 wells, average ~7,400’ lateral
– Mid-November: 9 wells, average 7,300’ lateral
 36 gross (30 net) operated Marcellus wells in progress(1)
– Average ~6,800’ lateral
Flow Rates (MMcf/d)
0-90
91-180 181-360
5.7
6.0
4.4
9.2
10.0
6.8
11.2
10.6
8.3
12.7
9.4
NA
12.9
NA
NA
NA
NA
NA
D&C
($/Ft)
$ 2,377
$ 1,663
$ 1,476
$ 1,349
$ 1,254
$ 1,247
Total
10.6
$ 1,533
56
6,458
9.7
6.9
Shotski – 1 Well
Avg. Lateral Ft: 4,000’
Status: Permitted
Iron Man Southwest Pad – 2 Wells
Avg. Lateral Ft: 7,500’
Status: Topholes Drilled
Wolverine Pad – 4 Wells
Avg. Lateral Ft: 8,000’
Status: Construction
Washington
Captain Jack– 6 Wells
Avg. Lateral Ft: 7,500’
Status: Tophole Drilling
Jacobs North Pad – 6 Wells
Avg. Lateral Ft: 4,400’
Status: Waiting on Completions
Greene
Marcellus Well Results To Date
Wells Turned Avg. Lateral
Period
To Sales
Length (Ft)
2010-2011
6
3,281
2012
9
5,731
2013
22
6,286
Q1 2014
4
6,691
Q2 2014
10
8,452
Q3 2014
5
8,163
Swagler Pad – 3 Wells
Avg. Lateral Ft: 6,500’
Status: In Sales
Mama Bear Pad – 5 Wells
Avg. Lateral Ft: 6,000’
Status: WOPC
Waterboy – 4 Wells
Avg. Lateral Ft: 9,000’
Status: Permitting
– 15 wells in completions phase, 21 wells in drilling phase
– Each pad is connected to or within 5 miles of Rice’s
gathering systems
Big Daddy Shaw Pad – 5 Wells
Avg. Lateral Ft: 7,900’
Status: In Sales
Mad Dog North Pad- 5 Wells
Avg. Lateral Ft: 9,700’
Status: Topholes Drilled
Zorro South Pad – 5 Wells
Avg. Lateral Ft: 9,300’
Status: Horizontal Drilling
PLHC North Pad – 9 Wells
Avg. Lateral Ft: 7,300’
Status: In Sales
Briggs Pad – 1 Well
Avg. Lateral Ft: 6,400’
Status: Permitting
* Flow Rates based on wells with available history
Behm Pad – 3 Wells
Avg. Lateral Ft: 7,500’
Status: Tophole Drilling
Rice Energy Acreage
Permitting/Constructing
Drilling
Completing
In Sales
_______________________
1.
Wells in Progress excludes wells in the Permitting/Constructing category.
6
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Marcellus Type Curve Economics
750’ Type Well Versus Historical Production (MMcf/d per 1,000’)
MMcf/d per 1,000’
Updating type curve to better reflect
historical production and management’s
choke program going forward. Results in
higher PV-10 per well and comparable
IRRs to previous type curve (NSAI)
2.5
2.0
1.5
1.0
0.5
–
0.5
–
1.0
1.5
2.0
2.5
750' Avg. Historical Production
Updated Assumptions and Economics
Type Well and Costs
Lateral Length
EUR (Bcf / 1,000)
EUR (Bcf)
Initial Choke (MMcf/d per 1,000')
120-Day Avg IP (MMcf/d)
D&C per Lateral ($ per foot)
Royalty
LT Basis Pricing (% of NYMEX) (1)
9.0%
Gas Firm Transportation ($/mcf) (NRI) (1)
LOE ($/mcf) (NRI)
$0.67
$0.29
Gathering and Compression ($/mcf) (NRI) (2)
Heat Content
–
1,050
Inventory (including W. Greene)
Net Undeveloped Locations
NRI Undeveloped Horizontal Feet (mm ft.)
Economics (3)
PV-10 (Single Well)
IRR (Single Well)
Payback (Months)
__________________________
1.
2.
3.
RMP Midstream Fees
No
Yes
7,000
2.0
13.9
1.85
12.6
$1,250
18.0%
Gathering and compression fee economics (green line)
reflect the impact to our single well returns pro forma
for our potential MLP (Rice Midstream Partners)
203%
147%
150%
101%
64%
$0.47
35%
50%
$3.00
Marcellus 750'
147%
101%
134%
89%
64%
34%
15%
8%
–
$2.50
$7.9
64%
17
Years Online 4.0
750’ Marcellus – IRR Sensitivity
100%
490
2.8
$11.3
101%
13
200%
3.5
750 Type Well
IRR
250%
3.0
54%
27%
$3.50
$4.00
Marcellus 750' (Pro Forma MLP)
$4.50
$5.00
NYMEX
W. Greene Marcellus 750'
Long-term basis assumption based on strip pricing and Rice’s 1.3 MMDth/d firm transportation and firm sales portfolio. Firm transportation expense based on weighted average FT expense for all FT projects signed to date.
Gathering ($0.30/dth on working interest gas) and compression ($0.07/dth for 1 stage of compression on working interest gas) expenses represent fees paid to Rice’s midstream affiliates. Expenses shown on a per mcf basis and on net revenue interest gas.
Economics based on 18% royalty and $4.00 NYMEX gas prices.
7
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Marcellus Value Enhancement Project – 500’ Spacing
Economic Comparison
• Tested 500’ foot inter-lateral spacing since Q4 2013
• In order to generate a higher PV-10 than a 750’ spaced well, we
need to decrease 500’ well costs by 10% while maintaining a
similar production profile to historical 500’ wells
• With this goal in in mind, our team has achieved this cost
reduction initiative on our last three 500’ spaced pads and
now we’ll observe the production profile for the next 6-12
months
• While we’re collecting 500’ data, 2015 development will be at
750’ spacing
EUR (Bcf)
Initial Choke (MMcf/d per 1,000')
120 Day IP Rate (MMcf/d)
D&C ($ / lateral ft)
PV-10 ($mm)
Acres/Well
Wells per Unit
PV-10 / Unit ($mm)
PV-10 (10% lower costs for 500' Wells)
Spacing Economics
750
500
% diff
13.9
11.6
(17% )
1.85
1.65
(11% )
12.6
11.2
(11% )
$1,250
$1,250
–
$11.3
$7.9
(30% )
121
80
(33% )
3.0
4.0
33%
$33.9
$31.7
(7%)
$33.9
$35.2
4%
Economics exclude midstream fees
500’ Spaced Historical Production Versus 750’ Type Well and Historical Production
MMcf/d per 1,000’
2.5
2.0
1.5
1.0
0.5
–
–
0.5
1.0
500' Avg. Historical Production
1.5
2.0
750' Avg. Historical Production
8
2.5
3.0
500 Type Well
3.5
4.0
750 Type Well
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Utica Development Concentrated in the Core
Map of Operated Utica Development
Operational Highlights
 Rice’s first three Utica wells have been three of the
most prolific US shale wells developed
 Bigfoot 9H (94% WI)
– ~2.0 Bcfe produced in first five months online
Bounty Hunter– 4 Wells
Avg. Lat. Length: 9,000
Status: Under Construction
Thrasher– 5 Wells
Avg. Lat. Length: 9,000
Status: Permitting
Iron Warrior– 5 Wells
Avg. Lat. Length: 8,500
Status: Under Construction
Blue Thunder – 2 Wells
Avg. Lat Length: 9,000’
Status: In Sales @ 16 MMcfe/d each
Bigfoot 9H – 1 Well
Lat. Length: 7,000’
Status: In Sales @ 14 MMcfe/d
Harrison
– Producing 14 MMcf/d on choke
Son Uva Digger– 3 Wells
Avg. Lat. Length: 9,000’
Status: Horizontal Drilling
– Expect flat production for 9+ months
– ~1090 Btu/scf
 Blue Thunder 10H and 12H (67% WI)
– 9,000’ laterals @ 500 ft. inter-lateral spacing
– Producing 16 MMcf/d per well
Krazy Train– 2 Wells
Avg. Lat. Length: 10,000’
Status: TopholeGuernsey
Drilling
Gold Digger– 2 Wells
Avg. Lat. Length: 9,000’
Status: Waiting on Completion
Belmont
Razin Kane– 3 Wells
Avg. Lat. Length: 8,500’
Status: Constructed
Mohawk Warrior– 3 Wells
Avg. Lat. Length: 12,000’
Status: Tophole Drilling
– Expect flat production for 9+ months
– ~1090 Btu/scf
 2014-2015 development concentrated within 5 mile
radius in central Belmont County, OH
 15 operated Utica wells currently in progress(1)
– Average ~9,900’ laterals, 55% WI
Marshall
Noble
Monroe
Madusa– 3 Wells
Avg. Lat. Length: 9,400’
Status: Constructed
Dragons Breath– 4 Wells
Avg. Lat. Length: 9,700’
Status: Constructed
Wetzel
– 5 wells to be frac’d in Q4 2014
Thunderstruck– 5 Wells
Avg. Lat. Length: 9,400’
Status: Tophole Drilling
 24 operated Utica wells in pad/permit phase
– Average 9,000’ laterals, 60% WI
Rice Energy Acreage
Permitting/Constructing
Drilling
In Sales
= 20+ Mmcfe/d IP
_______________________
1.
Wells in Progress excludes wells in the Permitting/Constructing category.
9
Rice PA Utica Test (Permitting)
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Utica Production and Pressures Update
•
•
Bigfoot 9H (7,000’ lateral) continues to produce steadily 14 MMcf/d @ 11 psi/d FCP decline.
Blue Thunder 10H and 12H (9,000’ laterals) were turned to sales in September and have stabilized at 16 MMcfd/d @ 13 psi/d
FCP decline
18,000
1 Year
Cumulative
5.1 Bcf
Wellhead Pressure, psi
Flow Rate, Mcf/d
16,000
Bigfoot Flow Rate Projection
14,000
Flat Period
Cumulative
6.1 Bcf
18 Month
Cumulative
7.3 Bcf
12,000
10,000
4.9 Bcf
Bigfoot 9H – 7,000’ lateral
8,000
Flow rate decline when
wellhead psi = line psi
Blue Thunder 10H/12H – 9,000’ laterals
6.4 Bcf
6,000
4,000
2,000
Line pressure (750-1500 psi)
0
0
30
60
90
120
150
180
210
240
270
Days
10
300
330
360
390
420
450
480
510
540
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Utica Type Curve Economics
Type Well Versus Historical Production (MMcf/d per 1,000’)
MMcf/d per 1,000’
2.5
Updating type curve based on initial
production results from Bigfoot and Blue
Thunder pads. Flat period increased
from 6 months to 9 months.
2.0
1.5
1.0
0.5
–
–
0.5
1.0
1.5
2.0
Utica Type Well
Updated Assumptions and Economics
Rice OH Entity
Midstream Fees
No
Yes
8,000
2.5
20.0
1.87
14.5
$1,500
20.0%
Type Well and Costs
Lateral Length
EUR (Bcf / 1,000)
EUR (Bcf)
Initial Choke (MMcf/d per 1,000')
120-Day Avg IP (MMcf/d)
D&C per Lateral ($ per foot)
Royalty
LT Basis Pricing (% of NYMEX) (1)
9.0%
Gas Firm Transportation ($/mcf) (NRI) (1)
LOE ($/mcf) (NRI)
$0.70
$0.30
Gathering and Compression ($/mcf) (NRI)
Heat Content
Inventory
Net Undeveloped Locations
NRI Undeveloped Horizontal Feet (mm ft.)
(2)
–
3
333
2.1
2.5
3.0
4.0
Years Online
Utica Avg. Historical Production
IRR Sensitivity
IRR
180%
160%
140%
Gathering and compression fee economics (green line) reflect
the impact of paying fees to RICE’s OH midstream entity
which will in turn result in equivalent midstream EBITDA
170%
125%
120%
123%
100%
87%
80%
60%
$0.50
3.5
20%
–
$2.50
55%
56%
40%
31%
32%
12%
13%
$3.00
86%
$3.50
$4.00
$4.50
$5.00
Economics (3)
NYMEX
PV-10 (Single Well)
$15.0
$10.1
Utica Dry
Utica Dry (Gathering and Compression Fees)
IRR (Single Well)
87%
55%
Payback (Months)
14
19
__________________________
1.
Long-term basis assumption based on strip pricing and Rice’s 1.3 MMDth/d firm transportation and firm sales portfolio. Firm transportation expense based on weighted average FT expense for all FT projects signed to date.
2.
Gathering ($0.30/dth on working interest gas) and compression ($0.07/dth for 1 stage of compression on working interest gas) expenses represent fees paid to Rice’s midstream affiliates. Expenses shown on a per mcf basis and on net revenue interest gas.
3.
Economics based on 18% royalty and $4.00 NYMEX gas prices.
11
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Midstream Update
FT portfolio includes 1.3 MMDth/d (1.2 Bcf/d) of firm capacity to premium US markets, including recently added 320 MDth/d
on TETCO’s Access South project with firm path to the Gulf Coast and estimated in-service date of November 2017(1).
Firm Capacity: ~30 MDth/d
In-service date: Online
Harrison
ET Rover



Firm Capacity: 100 MDth/d
In-service date: Summer 2017
Market: Dawn, ON
Brooke



Ohio
Belmont
Firm Capacity: 175 MDth/d
In-service date: Summer 2015
Markets: Gulf Coast, Midwest
Allegheny
Columbia (TCO)




Throughput Capacity: 4.1 MMDth/d
In-service date: Online
PA Water System

Washington


OH Gas Gathering System


Firm Capacity: ~200 MDth/d
In-service date: Online
Westside Expansion: 50 MDth/d
In-service date: November 2014
PA Gas Gathering System


Rockies Express
Columbia Gas (TCO)


National Fuel
Gas Supply
(NFGS)
Jefferson
Dominion East Ohio
Direct-Connect Capacity: 8.9
MMGPD
Expected Savings: $500k/well
In-service date: YE2015
Throughput Capacity: 2.6 MMDth/d
In-service date: YE2015
Texas Eastern (TETCO)


Marshall
Monroe
OH Water System



Direct-Connect Capacity: 16.5 MMGPD
Expected Savings: $500k/well
In-service date: YE2015
Rice Legend
Gas Gathering Line
Greene

Dominion Transmission



Wetzel
Firm Capacity: ~90 MDth/d
In-service date: Online

Team South
 Firm Capacity: 270 MDth/d
 In-service date: September 2014
Union Town to Gas City
 Firm Capacity: 86.5 MDth/d
 In-service date: November 2015
Open
 Firm Capacity: 50 MDth/d
 In-service date: November 2015
Access South
 Firm Capacity: 320 MDth/d
 In-service date: November 2017
Markets: Gulf Coast, Midwest
Water System
_______________________
Conversion of Dth to Mcf assumes 1,050 Btu factor.
1.
12
www.riceenergy.com
Long-Haul Firm Transport Improves Realized Pricing
On November 1st, we began shipping 270 MMDth/d to the Gulf Coast and over 55% of 2015 volumes will access attractive nonAppalachian markets
Quarterly Basis Exposure
Nov. 1 - TETCO
ELA Capacity online
Basis Exposure
Differential to NYMEX
($/MMbtu)
$0.00
100%
90%
18%
24%
19%
20%
19%
($0.20)
80%
70%
60%
21%
46%
4%
50%
20%
($0.69)
16%
30%
11%
($0.53)
7%
44%
40%
2015 Average
2016 Average
($1.00)
11%
($1.11)
3Q14
4Q14
Gulf Coast
2014 Average
TCO
Midwest
TETCO M2
13
($0.60)
($0.80)
34%
10%
0%
($0.56)
11%
33%
($0.86)
35%
($0.40)
38%
26%
40%
23%
Dominion South
($1.20)
Average Basis
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Inventory of High Returning Projects
Inventory and Returns Summary (2)
Updated Inventory
Net Acreage (1)
Acreage Risking
Assumed Inter-Well Spacing
Avg. Lateral Length
Implied Acreage Spacing
Undeveloped Net Locations
Undeveloped NRI Hz Feet (mm ft.)
60,713
20%
750
7,000
121
351
2.0
21,913
20%
750
7,000
121
139
0.8
Utica
Dry
43,626
10%
750
8,000
138
283
1.8
350
Undeveloped Net Locations
Marcellus
W. Greene
Acquisition
400
Utica
Wet
101%
300
113%
Difference driven
by historical
gathering fee
100%
87%
80%
250
200
150
60%
54%
351
120%
283
Single Well IRR
• We have updated our methodology for estimating RICE’s drilling
inventory to account for our leasing program and development plans
• Marcellus: Updated net location estimate slightly lower than
previously disclosed risked estimates (526490 in Marcellus) but
total horizontal feet inventory roughly in-line in part due to longer
laterals
• Utica: Updated net location estimate and total horizontal feet
inventory materially higher than previous risked estimates due to
decreased unitization risking (246  333)
40%
100
7,699
10%
750
8,000
138
50
0.3
139
50
–
Type Curve Assumptions
20%
50
Marcellus
Marcellus
W. Greene
Utica Dry
0%
Utica Wet
Net Locations
IRR (Excl Midstream Fees)
Utica
Utica
W. Greene
Dry
Wet
120-Day IP (MMcf/d) Pre-Processed
12.6
12.6
14.5
13.1
Bcf / 1,000'
1.98
1.98
2.50
2.20
7,000
7,000
8,000
8,000
–
–
–
40.0
1,050
1,090
1,080
1,200
–
–
–
15%
Gross EUR (Bcfe)
13.9
13.9
20.0
19.2
Well Cost ($mm)
$8.8
$8.8
$12.0
$12.0
Gathering and Compression Fees (NRI)
$0.47
$0.76
$0.50
$0.56
Gathering and Compression Fees (WI)
$0.37
$0.57
$0.37
$0.37
Avg. Lateral Length (Ft)
NGL Yield (BBls/MMcf)
Modeled BTU
Shrink
__________________________
1.
Excludes ~2,500 net acres in Guernsey and Harrison counties in OH.
2.
Economics based on 18% royalty in the Marcellus and 20% in the Utica and $4.00 NYMEX gas prices. Long-term basis assumption of 9% of NYMEX based on strip pricing and firm transportation cost ($0.52/dth WI) based on Rice’s 1.3 MMDth/d firm
transportation and firm sales portfolio. Firm transportation expense based on weighted average FT expense for all FT projects signed to date.
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Appendix
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Post-MLP Organizational and Credit Structure
Rice Energy Inc.
NYSE: RICE
Rice Energy
Appalachia LLC
DE
Rice Midstream
Holdings LLC
Rice E&P
Subsidiaries
IDRs
& LP
Interests
Rice Midstream
Management LLC
Public
Unitholders
% LP interest
E&P Credit Group
Non-economic
GP Interest
OH Gathering
PA Water
OH Water
% LP interest
Rice Midstream Partners LP
NYSE: RMP
Retained Midstream Credit Group
PA Gathering
MLP Credit Group
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Commodity Hedging Summary
Strategy
 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
 Our hedging program helps underpin cash
flow used to fund our capital investments.
Over half of Q4 2014 production is hedged
at a weighted average price of $4.09/MMBtu
Hedge Book (1)
NYMEX Henry Hub Contract Summary
10/1YE2014
2015
2016
2017
Natural Gas Swaps
Volume Hedged (Bbtu/d)
Weighted Average Swap Price ($/MMBtu)
173
$4.15
166
$4.09
214
$4.14
60
$4.24
Collars
Volume Hedged (BBtu/d)
Weighted Average Floor Price ($/MMBtu)
Weighted Average Ceiling Price ($/MMBtu)
10
$3.00
$5.80
139
$3.96
$4.65
----
----
Deferred Puts
Volume Hedged (BBtu/d)
Put Price ($/MMBTU)
Put Premium ($/MMBTU)
50
$4.55
0.45
----
----
----
Total Volume (BBtu/d)
Weighted Average Floor ($/MMbtu)
% Swap
233
$4.09
74%
305
$4.03
54%
214
$4.14
100%
60
$4.24
100%
TCO
Volume (BBtu/d)
Swap Price ($/MMBtu)
43
($0.34)
37
($0.42)
17
($0.42)
-–
Dominion South
Volume (BBtu/d)
Swap Price ($/MMBtu)
17
($0.79)
25
($0.79)
21
($0.79)
-–
Basis Contract Summary
__________________________
1.
Hedges as of 11/11/14.
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3Q 2014 Adjusted EBITDA Reconciliation
($ in thousands)
Adjusted EBITDAX reconciliation to net income (loss):
Net income (loss)
Interest expense
Depreciation, depletion and amortization
Amortization of deferred financing costs
Amortization of intangible assets
Equity in loss of joint ventures
Three Months Ended
Nine Months Ended
September 30, 2014
September 30, 2014
$
$
Derivative fair value (gain) loss (1)
Net cash receipts on settled derivative instruments (1)
Gain on purchase of Marcellus joint venture
Acquisition expense
Non-cash stock compensation expense
Non-cash incentive unit expense
Income tax expense
Loss on extinguishment of debt
Write-off of deferred financing costs
(2)
Exploration expenses
Adjusted EBITDAX
$
(6,862)
15,754
33,853
707
408
--
114,675
38,737
91,912
1,728
748
2,656
(36,935)
(5,357)
171
(20,782)
-2,246
2,058
26,418
14,005
790
--
(203,579)
2,246
3,274
101,695
18,787
3,934
6,896
747
53,361
1,706
159,276
$
__________________________
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.
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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.
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.
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.
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Additional Disclosures
Determination of Identified Drilling Locations as of September 30, 2014
Net undeveloped locations are calculated by taking our total net acreage and multiplying such amount by a risking factor
which is then divided by our expected well spacing. We then subtract net producing wells to arrive at undeveloped net drilling
locations
Undeveloped Net Marcellus Locations: We assume these locations have 7,000 foot laterals and 750 foot spacing between
wells which yields approximately 121 acre spacing. In the Marcellus, we apply a 20% risking factor to our net acreage to
account for inefficient unitization and the risk associated with our inability to force pool in Pennsylvania. As of 9/30/14, Rice
had 60,713 net acres in the Marcellus which results in 351 undeveloped net locations
Undeveloped Net Western Greene County Locations: We assume these locations have 7,000 foot laterals and 750 foot
spacing between wells which yields approximately 121 acre spacing. In Western Greene County, we apply a 20% risking
factor to our net acreage to account for inefficient unitization and the risk associated with our inability to force pool in
Pennsylvania. As of 9/30/14, Rice had 21,913 net acres in Western Greene County which results in 139 undeveloped net
locations
Undeveloped Net Upper Devonian Locations: We assume these locations have 7,000 foot laterals and 1,000 foot spacing
between wells which yields approximately 161 acre spacing. In the Upper Devonian, we apply a 20% risking factor to our net
acreage to account for inefficient unitization and the risk associated with our inability to force pool in Pennsylvania. As of
9/30/14, Rice had 55,000 net acres prospective for the Upper Devonian which results in 271 undeveloped net locations
Undeveloped Net Utica Locations: We assume these locations have 8,000 foot laterals and 750 foot spacing between
wells which yields approximately 138 acre spacing. In the Utica, we apply a 10% risking factor to our net acreage to account
for inefficient unitization. As of 9/30/14, Rice had 51,324 net acres prospective for the Utica in Ohio which results in 333
undeveloped net locations. This excludes ~2,500 net acres in Guernsey and Harrison Counties in Ohio
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