Scotia Howard Weil Energy Conference 2017
Forward Looking Statements
This presentation contains certain “forward-looking statements” within the meaning of federal securities laws, including within the meaning of the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 that are not limited to historical facts, but reflect Range’s current beliefs, expectations or intentions regarding future events. Words such as “may,” “will,” “could,”
“should,” “expect,” ““plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” and similar expressions are intended to identify such forwardlooking statements. The statements in this presentation that are not historical statements, and any other statements regarding Range’s future expectations, beliefs, plans, objectives, financial
conditions, assumptions or future events or performance that are not historical facts, are forward-looking statements within the meaning of the federal securities laws.
All statements, except for statements of historical fact, made in this presentation regarding activities, events or developments the Company expects, believes or anticipates
will or may occur in the future, such as those regarding merger integration, future well costs, expected asset sales, well productivity, future liquidity and financial resilience,
anticipated exports and related financial impact, NGL market supply and demand, improving commodity fundamentals and pricing, future capital efficiencies, future
shareholder value, emerging plays, capital spending, anticipated drilling and completion activity, acreage prospectivity, expected pipeline utilization and future guidance
information are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of
1934, as amended. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however,
management's assumptions and Range's future performance are subject to a wide range of business risks and uncertainties and there is no assurance that these goals and
projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements. Further information on risks
and uncertainties is available in Range's filings with the Securities and Exchange Commission ("SEC"), which are incorporated by reference. Range undertakes no obligation
to publicly update or revise any forward-looking statements.
The SEC permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are 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 as well as the option to disclose probable
and possible reserves. Range has elected not to disclose the Company’s probable and possible reserves in its filings with the SEC. Range uses certain broader terms such
as "resource potential,” “unrisked resource potential,” "unproved resource potential" or "upside" or other descriptions of volumes of resources potentially recoverable through
additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC's guidelines. Range has not attempted to distinguish
probable and possible reserves from these broader classifications. The SEC’s rules prohibit us from including in filings with the SEC these broader classifications of
reserves. 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 actually being realized. Unproved resource potential refers to Range's internal estimates of hydrocarbon quantities that may be potentially discovered through
exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers. Unproved resource potential does not
constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System and does not include proved reserves. Area wide
unproven resource potential has not been fully risked by Range's management. “EUR,” or estimated ultimate recovery, refers to our management’s estimates of hydrocarbon
quantities that may be recovered from a well completed as a producer in the area. These quantities may not necessarily constitute or represent reserves within the meaning of
the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules. Actual quantities that may be recovered from
Range's interests could differ substantially. Factors affecting ultimate recovery include the scope of Range's drilling program, which will be directly affected by the availability
of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory
approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling results, including geological and mechanical factors affecting recovery
rates and other factors. Estimates of resource potential may change significantly as development of our resource plays provides additional data.
In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing
wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. Investors are urged
to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com or by written request to 100
Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this Form 10-K on the SEC’s website at www.sec.gov or by calling the SEC at 1-800-SEC0330.
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Range Overview
Market Snapshot
NYSE Symbol:
Market Cap (a):
Net Debt (b):
Enterprise Value:
RRC
$6.7B
$3.8B
$10.5B
Overview
• 2016 Year-End Proved Reserves of 12.1 Tcfe
~Net Surface Acreage(d)
• 2016 Production Per Day of 1,542 Mmcfe
SW Marcellus (PA):
515,000
• Resource Potential of ~100 Tcfe (c)
N. Louisiana: (e)
220,000
• 2017 Production YoY Growth of 33-35%
NE Marcellus (PA):
95,000
(a) As of 3/23/2017 (b) As of 12/31/2016 (c) Does not include resource potential from the Utica (d) As of December 31, 2016 – does not include legacy NW PA and Midcontinent acreage
(e) Includes acreage purchase option
3
Recent Investor Discussions
Investor Concerns Reflected in Curve
• Growth of Marcellus/Utica natural gas
production expected to fill pipelines
• Associated gas production from the Permian
• Haynesville and other plays returning back
to growth
Range Thoughts
• Not enough rigs running in Northeast to fill
pipelines given producers cash flow at
current price levels
• ~55% of US natural gas production areas
are declining. The remaining 45% is
growing (Permian, Marcellus, Utica,
Haynesville, Scoop/Stack)
• Declines could offset growth in 2017
Natural Gas Strip Pricing
• Associated gas numbers are aggressive,
and even if correct infrastructure could limit
growth (recent WAHA basis blowout
evidences this risk)
$4.50
$4.00
$3.50
$3.00
• Core areas are limited (sweet spot
exhaustion)
$2.00
Apr-17
Aug-17
Dec-17
Apr-18
Aug-18
Dec-18
Apr-19
Aug-19
Dec-19
Apr-20
Aug-20
Dec-20
Apr-21
Aug-21
Dec-21
Apr-22
Aug-22
Dec-22
Apr-23
Aug-23
Dec-23
Apr-24
Aug-24
Dec-24
Apr-25
Aug-25
Dec-25
Apr-26
Aug-26
Dec-26
Apr-27
Aug-27
Dec-27
Apr-28
Aug-28
Dec-28
$2.50
Today
6 Months Ago
1 Year Ago
• Demand growth will continue and could
surprise to the upside
Bottomline: We are optimistic on natural gas macro, but even in a lower
for longer gas environment, Range’s Depth of Core Inventory and
Strong Unhedged Recycle Ratio are Differentiators
4
High Quality Acreage Position - Appalachia Assets
• ~1.5 million net effective acres (a) in SW PA
leads to decades of drilling inventory
• Gas In Place (GIP) analysis shows the
greatest potential is in Southwest
Pennsylvania
• Low risk and highly repeatable project
inventory
Gas In Place
For All Zones
• Near-term focus on Marcellus development
in Southwest PA
• Significant inventory of existing pads
enhances future development
Upper
Devonian
Stacked Pay and Existing
Pads Allow for Multiple
Development Opportunities
Marcellus
Utica/Point
Pleasant
* Map acreage as of January 2016; outlined townships hold 2,000 or more acres (a) Includes stacked pay
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High Quality Acreage Position – Southwest Appalachia
PA
• Longer laterals and existing pads in 2017
provide low-risk efficiency gains
OH
• Increased optionality due to quality of
acreage position, gathering system,
available locations and existing pads
WV
Over 200
Existing
Pads
• Majority of existing pads are in the liquidsrich areas (map to the right)
Southwest Marcellus Economics
Dry
Wet
Super-Rich
EUR
22.3 Bcf
24.6 Bcfe
20.4 Bcfe
EUR/1,000
ft. lateral
2.5 Bcf
3.0 Bcfe
2.4 Bcfe
Well Cost
$6.1 MM
$6.8 MM
$7.3 MM
Cost/1,000
ft. lateral
$690 K
$820 K
$856 K
Lateral
Length
8,850 ft.
8,300 ft.
8,500 ft.
IRR* - $3.00
75%
55%
52%
IRR at Strip
as of
12/30/2016
100+%
56%
51%
Wet and Super-Rich economics are greater than or
equal to Dry gas economics when developed on
existing pads utilizing existing gathering infrastructure
* For flat pricing natural gas case, oil price assumed to be $50/bbl for 2017, $60/bbl for 2018 then $65/bbl to life with no escalation
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5.0
$1.00
4.5
$0.90
4.0
$0.80
3.5
$0.70
3.0
$0.60
2.5
$0.50
2.0
$0.40
1.5
$0.30
1.0
$0.20
0.5
$0.10
0.0
$0.00
EUR/ft
F&D ($/Mcfe)
EUR/ft (Mcfe)
Range Has Highest EUR/Ft and Lowest F&D Costs In SW Appalachia
F&D ($/Mcfe)
Source: Scotia Howard Weil Appalachian Energy: Conference Edition Fact Book 2017. Published March 2017
7
Range Has Lowest Break-Even in SW Appalachia
Operator Specific Breakeven Calculations
$4.50
$4.00
$3.50
$3.00
$2.50
$2.43
$2.00
$1.50
$1.00
$0.50
$-
Lowest Break-Even Cost in SW Appalachia Also Demonstrates the Quality of
Range’s Appalachian Asset Base
Source: RS Energy Group Marcellus Shale Basin Update February 15, 2017
8
Deep Core Inventory in Appalachia
• Range’s inventory of high-return locations
provides for years of efficient growth
Range’s Estimated Inventory Count
5,000
• Range has 4,700 identified locations in the
core of the Marcellus
• In addition, Range has 2,800 locations in the
Upper Devonian
4,700
4,500
4,000
3,500
2,800
3,000
2,500
2,000
1,500
• Locations do not include ~400,000 acres
prospective for the Utica
1,000
500
0
• Thousands of locations are on existing pads
which bolsters economics compared to peers
Marcellus
Upper Devonian
Note: Marcellus and Upper Devonian location count assumes 8k ft. laterals
9
Range Ranks #1 in SW Appalachia Years to Peak Production
Years to Peak Production
25
20
15
10
5
0
COG
RRC
EQT
AR
RICE
CHK
SWN
GPOR
ECR
Range’s Years to Peak Production Demonstrates Both Asset
Quality and Depth of Inventory
Source: Heikkinen Energy Advisors
10
High Quality Acreage Position – North Louisiana
• ~220,000(a) net acres of stacked pay potential in
North Louisiana
• Currently focused on Upper Red with optionality for
additional targets
• Lowered well costs in Terryville to $7.7 million from
$8.7 million at acquisition date
• Acreage favorably located near growing Gulf Coast
demand center with ample infrastructure to grow
development
• Will continue to methodically test extension areas
N. Louisiana Economics
EUR
17.5 Bcfe
11.8 Bcfe
EUR/1,000 ft.
lateral
2.3 Bcfe
1.6 Bcfe
Well Cost
$7.7 MM
$7.7 MM
Cost/1,000 ft.
lateral
$1,027 K
$1,027 K
Lateral Length
7,500 ft.
7,500 ft.
IRR* - $3.00
100+%
36%
IRR at Strip as of
12/30/16
100+%
40%
Lower Cotton Valley – Overpressured
Terryville Upper Red Terryville Lower Red
(a) Includes acreage purchase option
* For flat pricing natural gas case, oil price assumed to be $50/bbl for 2017, $60/bbl for 2018 then $65/bbl to life with no escalation
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North Louisiana Improvements Since Merger
Acquisition
Assumptions
May 2016
Current
Expectations
March 2017
$8.7 million
$7.7 million
~100 ft.
~25-40 ft.
Upper Red IRR at $3.00
64%
100+%
Lower Red IRR at $3.00
-
36%
Acreage value
Encouraging initial
tests could de-risk
additional acreage
Terryville Well Cost
Targeting Interval
Extension Areas
Improvements Increase Rates of Return and Location Counts
12
Differential Improvements Driving Margin Expansion
NGL as a % of WTI
Natural Gas Differential(a)
$-
Condensate Differential
30%
$-
$(0.10)
$(0.20)
$(0.30)
25%
26%
28%30%
$(5.00)$(6.00)
$(3.00)
$(6.00)
$(0.30)
$(9.13)
$(0.45)
$(0.40)
$(0.50)
20%
$(9.00)
22%
$(0.52)
$(12.00)
$(0.60)
2015
2016
2017E (b)
Expecting Continued Improvements Into 2018
• Gulf Expansion Phase 1 came
on line two weeks early in
October which moves ~150
Mmcf/d from local Appalachian
markets to the Gulf Coast
• Expect a significant 2017
corporate improvement given
North Louisiana gas is expected
to receive near NYMEX pricing
• Further improvements expected
in 2018 as additional projects
come on line
$(14.93)
$(15.00)
15%
2015
2016
2017E
2015
2016
2017E
Expecting Continued Improvements Into 2018
• Only producer with capacity on
the Mariner East 1 project to
Marcus Hook
• North Louisiana NGL’s sold
FOB processing plant and
receive Mont Belvieu related
pricing
• Higher ethane and propane
demand anticipated in 2018
from petrochemical sector and
exports
• Initiated new marketing
agreements in 2H16 which
improves Marcellus condensate
realizations
• Expect a significant 2017
corporate improvement given a
full year of new Marcellus
agreements and North
Louisiana condensate that
receives near NYMEX pricing
* All differential estimates based on 2/17/17 strip pricing (a) NG estimate includes basis hedges. (b) Assumes no uplift from Rover pipeline in 2017
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Unhedged Recycle Ratio Supported by Improving Margins and High Quality Rock
• Margin improvement expected in 2017 and
beyond due to improved pricing across all
products and a low cost structure
Margin Improvement Expected
45%
40%
Unhedged Cash Margin
• Range’s 2016 PUD development costs are
Industry leading
• Range’s recycle ratio is near head of class
among oil or gas producers
35%
30%
25%
20%
15%
10%
5%
• At 2017 strip pricing, Range’s recycle ratio
is ~2.8x demonstrating rock quality,
improved differentials across all products
and a low cost structure
0%
2015A
1Q16-3Q16A
4Q16A
2017E(a)
YE16 PUD Development Costs per Mcfe
$1.40
Recycle Ratio per Mcfe: (Margin Divided by F&D)
All-In Cash Costs (1Q17 Expected)
Adjusted Margin
Expected Future Development Cost for PUD Reserves
Unhedged Recycle Ratio
$1.20
$
2.98
1.78
~$1.20
0.42
~2.8x
PUD Development Costs per Mcfe
Pre-Hedge Price (2017 Strip as of 3/23/2017)
$1.00
$0.80
$0.60
$0.42
$0.40
$0.20
$-
RRC
Peer 1
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
Peer 7
Peers include AR. CHK, COG, ECR, EQT, GPOR, RICE. From 10k reserve disclosures
(a) Based on midpoint of cost and differential guidance at strip pricing as of 3/23/2017, NYMEX gas price of $3.27 and WTI price of $49.59
14
Range’s Recycle Ratio Near Head of Class
EBITDA 2017E Recycle Ratio (Median F&D)
5.00x
4.50x
4.00x
3.50x
3.00x
2.50x
2.00x
1.50x
1.00x
0.50x
DNR
SWN
WLL
HES
DVN
PDCE
APC
APA
SM
QEP
EPE
NFX
MRO
CRZO
ECR
PXD
XEC
OXY
EOG
WPX
CXO
RICE
NBL
EQT
EGN
AR
LPI
RSPP
PE
CLR
OAS
RRC
COG
FANG
0.00x
Range Ranks Well Compared to Both Oil and Gas Peers
Source: BMO Capital Markets 2016 U.S E&P F&D Survey Published on 3/7/2017
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Why Invest in Range?
Long Inventory of Core Locations in the Two Most Economic Gas Plays
in the U.S.
•
Range discovered the Marcellus in 2004 and leased SWPA core acreage
•
Highest normalized EUR’s in SWPA reflect quality of acreage position
•
North Louisiana provides additional low-cost inventory, advantaged margins and
geographic diversity
Expanding Margins Drive Cash Flow Growth
•
Improved pricing differentials across all products in 2017
•
Low unit cost structure bolstered by existing infrastructure
•
North Louisiana production receives favorable Gulf Coast pricing
Peer Leading F&D Costs Underpin Profitability
•
Recycle Ratio ~2.8x at 2017 strip pricing (a)
(a) 2017 strip pricing as of 3/23/2017
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