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MarketScreener Homepage  >  Equities  >  Nyse  >  Range Resources    RRC

RANGE RESOURCES

(RRC)
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Range Resources : J.P. Morgan Global High Yield & Leveraged Finance Conference

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02/24/2020 | 07:57am EDT

J.P. Morgan Global High Yield &

Leveraged Finance Conference 2020

Forward Looking Statements

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 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), including its most recent Annual Report on Form 10-

  1. Unless required by law, Range undertakes no obligation to publicly update or revise any forward-looking statements to reflect circumstances or events after the date they are made.

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 its 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.comor 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.govor by calling the SEC at 1-800-SEC- 0330.

2

Range - At a Glance

Unmatched Southwest Appalachia Inventory

  • Approximately one half million net acres provide decades of low-risk drilling inventory
  • Contiguous position allows for efficient operations and long-lateral development
  • Peer-leadingwell costs and productivity underpin top-tier recycle ratio
  • Proved Reserves of 18.2 Tcfe at YE2019 - SEC PV-10 of over 2.4x total debt

Sustainable Free Cash Flow

  • Peer-leadingwell costs + Shallow base decline = Low maintenance capital requirements
  • Low maintenance capital requirements support free cash flow through the cycles
  • Cost structure improvements enhance margins and durability of free cash flow
  • Disciplined spending evidenced by consecutive years of spending below original budget

Leader on Sustainability and Environmental Practices

  • Reduced environmental impact and enhanced profitability through:
    • Water recycling and logistics
    • Long-lateraldevelopment
    • Electric-poweredfracturing fleet
    • Innovative facility designs
    • Robust LDAR program
  1. SEC PV-10 assumes $2.58/Mmbtu NYMEX natural gas and $55.73/bbl WTI

3

Unmatched Inventory in Southwest Appalachia

~3,700 undrilled core Marcellus wells(a) provide decades of low-risk drilling opportunities

Marcellusresource potential(b)

  • 40 Tcf of natural gas
  • 3 billion barrels of NGLs
  • 149 million barrels of condensate

Significant inventory of highly prolific Utica wells extends Range's dry gas opportunity

Existing natural gas and NGL infrastructure de-risks future development

Contiguous acreage position provides for operational efficiencies and industry leading well costs:

  • Long-lateraldevelopment
  • Efficient water handling and long-term infrastructure utilization

Range acreage outlined in green

  1. Estimates as of YE2018; based on production history from ~1,000 Range-drilled wells. Includes ~300 locations not shown on map. Based on 10,000 ft lateral length
  2. As of YE2018. Does not include over 18 Tcfe in proved reserves.

4

Value of Year-End 2019 ProvedReserves - Over 2.4x Total Debt

Proved Developed

9.9 Tcfe

Proved Undeveloped

8.3 Tcfe

Included in SEC Reserves

  • Only 5 years of development activity
  • Proved Developed reserves of 9.9 Tcfe
  • Proved Undeveloped reserves of 8.3 Tcfe
  • Approximately 440 Marcellus locations

Reserve Value Ignores Resource Potential

Resource Potential

~100 Tcfe

  • Resource Potential of ~100 Tcfe
  • Over 3,000 undrilled core Marcellus wells, or over 40 years of inventory at current drilling pace
  • Potential from ~400,000 net acres of both core Utica and Upper Devonian

Reserve History

  • PUD Development Costs consistently better than Appalachia peers
  • Positive performance revisions to reserves each year for the last decade

During 2019, Range Opportunistically Repurchased over $200 Million

of Senior Notes Principal

Note: SEC PV-10 assumes $2.58/Mmbtu NYMEX natural gas and $55.73/bbl WTI

5

Capital Efficiency Driven by Peer-Leading Well Costs & Decline Rate

$1,400 $1,200 $1,000 $800 $600 $400 $200 $0

Well Costs per Lateral Foot

2020 Decline Rate

40%

35%

30%

25%

20%

15%

10%

5%

RRC

RRC Peer 1 Peer 2

Peer 3

Peer 4

Peer 5

Peer 6

0%

2020

2019

RRC

Peer 2

Peer 1

Peer 4

Peer 3

Peer 5

Peer 6

D&C Capex per Mcfepd Reflects Relative Capital Efficiency

2018

First 3 Quarters 2019

$606

$550

$553

$511

$453

$377

$380

$394

$338

$306

$278

$301

$259

$239

Peer 4

RRC

Peer 1

Peer 6

Peer 3

Peer 2

Peer 5

RRC

Peer 4

Peer 2

Peer 3

Peer 6

Peer 1

Peer 5

Peer-Leading Development Costs & Decline Rate Drive

Lowest Development Costs per Unit of Production in Appalachia

Note: Peers include AR, CNX, COG, EQT, GPOR and SWN. Peer estimates from company filings, presentations, transcripts, guidance and Range estimates. SWN estimates for 2018 represent Appalachia production and capital expenditures only.

6

Cash Recycle Ratio Shows Quality and Durability of Asset Base

250%

200%

150%

100%

50%

0%

Appalachia Gas Peer

Oil Peer

Source: MKM Partners. "Energy/Exploration & Production Outlook". June 2019. Cash Recycle Ratio = Cash Operating Margin divided by Capital Intensity. Companies shown include APC, AR, CHK, CLR, CNX, COG, CRZO, CXO, DVN, ECA, EOG, EQT, GPOR, HES, HPR, LPI, MRO, MTDR, MUR, PDCE, PXD, SM, SRCI, SWN, WLL, WPX and XEC.

7

Maintenance Capital Drives Free Cash Flow Through the Cycles

Sustainable

Shallow

Free Cash

Base Decline

Low

Maintenance

Capital

Shallow Base Decline Driven by:

  • Core Marcellus position
  • 10+ years of drilling history in Marcellus provides solid base of low-decline wells
  • Infrastructure built to maximize returns, not peak initial rates
  • 2020 base decline rate of ~20% is sustainable, even with modest growth in base production
  • Shallow base decline, coupled with efficient operations allows for low maintenance capital

Low Maintenance Capital Supports Sustainable Free Cash Flow

  • Minimum capital requirements to maintain existing production levels compared to peers
  • Generating free cash flow is priority in capital allocation process
  • Free cash flow is durable given Range's multi-decade core Marcellus inventory

8

Improving Cost Structure Enhances Cash Flow & Margin Growth

Cash Operating Costs ($ per mcfe)

$2.20 $2.10 $2.00 $1.90 $1.80 $1.70 $1.60 $1.50 $1.40 $1.30 $1.20

Over Half of Targeted

Savings Have Already

Been Achieved

4Q18

1Q19

2Q19

3Q19

4Q19

4Q23

(Original Target)

TGP&C

LOE

Production Taxes

Cash G&A

Interest

Q4 2019 Unit Costs Expected to Be <$2.00 per Mcfe

9

Leading in Sustainability and Environmental Practices

Environmental Responsibility Highlights

Range is actively

Ranked second among

Range's water sharing

working to achieve zero

top producers on water

program is recycling

net emissions across

management

153% of its own and

its operations

and corporate

offset producers water

environmental policies1

1 Rankings according to "Disclosing the Facts 2019: Transparency and Risk in Water & Chemicals Management for Hydraulic Fracturing Operations"

10

Natural Gas Demand - Increases 21 Bcf/d in Next 5 Years

2019-2024 Demand Outlook

  • Total demand growth of +21 Bcf/d through 2024 from LNG and Mexican exports, industrial and electric power demand growth
  • LNG export capacity to increase by mid-2020 to 10 Bcf/d from projects under-construction
  • Second Wave LNG Projects could add another +10 Bcf/d of exports by 2025
  • Continued coal (currently ~30% of power stack) and nuclear retirements (~20% of power stack)

U.S. LNG Export Demand Outlook

  • Second Wave of U.S. LNG Projects has started, with 5.1 Bcf/d already under- construction and another +5 Bcf/d likely to FID in 2019-2020
  • Over 30 Bcf/d of Second-Wave LNG projects have been proposed
  • Futures prices support additional LNG exports
  • Range forecasts U.S. LNG export capacity to reach ~13 Bcf/d in 2022 and ~18 Bcf/d by late 2023-early 2024

U.S. LNG Export Terminal Capacity (Bcf/d)

22

20

Port Arthur

FERC Approved and/or

Magnolia LNG

18

>70% long-term offtake

signed. Potential Next

Freeport T4

16

Wave Projects.

Cameron T4-T5

14

Under Construction

Golden Pass T1-T3

Sabine Pass T6

12

or In-Service

Calcasieu Pass

10

Corpus Christi T3

Freeport T1-T3

8

Cameron T1-T3

6

Corpus Christi T1-T2

4

Cove Point

Elba Island

2

Sabine Pass T1-T5

0

12/16

12/17

12/18

12/19

12/20

12/21

12/22

12/23

12/24

Source: EIA, LNG Operator announcements

Futures Market Indicates LNG Arb is OPEN

8.00

7.50

7.00

6.50

6.00 $/MMbtu 5.50 5.00

4.50

4.00

3.50

3.00

Nov-19

Nov-20

Nov-21

Nov-22

Nov-23

Nov-24

EU Gas (NBP) $/MMBtu

USGC Delivered Full Cost to EU

USGC Variable Cost to EU

Bloomberg prices as of 10/21/19.

11

Natural Gas Supply - Base Decline & Capital Discipline

Base Declines Offset Current Activity

  • Average U.S. decline rate of 26% equates to ~27 Bcf/d of new gas required each year to simply hold production flat
  • After drawing down DUCs, industry growth should slow meaningfully into 2H2020 and 2021 if strip prices hold

Producer Discipline Materially Impacts Supply Forecast

  • Industry spending being limited to cash flow in 2019 and beyond
  • Consensus 4Q-4Q growth forecast now just ~4% (0.8 Bcf/d) for Appalachia peer group, significantly improving gas macro for late 2020 and 2021
  • Minimal Appalachia growth expected at current strip pricing and ~50 rigs
  • Private Equity-backed operators may shift to a free cash flow model as traditional exit strategies become challenged (IPO, corporate M&A, etc.)

Associated Gas Growth Not Capable

of Offsetting Dry Gas Decline and

Expected Demand Growth

U.S. Natural Gas Base Decline Rate

Source: RS Energy

12

NGL Macro Improving

New Export Infrastructure 2019-2020

Range's Ability to Export Provides Price Diversity

2019 export capacity to increase by ~400

MBPD and by ~650 MBPD in 2020 versus EIA

gas plant LPG supply of 2,559 MBPD in

September 2019.

U.S. waterborne export capacity increases

equivalent to over 40% of U.S. LPG supply,

which should tighten balances going forward

Local Northeast propane differentials have

Ethane Price Diversity

Mont

Belvieu

Oil-Linked

Propane & Butane

Northeast /

Mont Belvieu

narrowed since start up of Mariner East 2

Storage & Supply

  • Export-adjustedstorage days of supply 18% below the five-year average as end of November
  • NGL supply growth to slow in 2020 with decreasing U.S. crude and natural gas supply growth.

New Demand

  • Indian LPG import terminal expansions under- construction/planned of 350 MBPD in 2020-25
  • In 2020, 5 PDH plants scheduled to start up in China with combined capacity of 115 MBPD propane demand
  • Relative economics support use of LPG over naphtha for international steam crackers

Gas-Linked

Exports

Note: Represents Appalachia only. Pie chart represents annual average. Range has the ability to increase domestic sales in winter months when local prices are strong.

International Price Strength Versus Mont Belvieu

gallon)

$0.35

$0.30

per($

$0.25

Arb

$0.20

$0.10

Propane

International

$0.15

$0.05

$0.00 ($0.05)

1/5/2018

2/5/2018

3/5/2018

4/5/2018

5/5/2018

6/5/2018

7/5/2018

8/5/2018

9/5/2018

10/5/2018

11/5/2018

12/5/2018

1/5/2019

2/5/2019

3/5/2019

4/5/2019

5/5/2019

6/5/2019

7/5/2019

8/5/2019

9/5/2019

10/5/2019

11/5/2019

12/5/2019

Note: Calculated as front-month European C3 price (ARA), less shipping costs from the U.S. Gulf Coast to Europe (ARA), relative to Mont Belvieu C3 price

13

Range is Positioned Well for Low Commodity Prices

Self-Funded Business Model

  • Flexible capital program as all of Range's firm transportation commitments have been met
  • Shallow base decline supports low maintenance capital requirement
  • Low maintenance capital and high capital efficiency promote free cash flow generation through the cycles
  • Marcellus inventory enables multi-decade, sustainable free cash flow profile

Liquidity Profile

  • Ample liquidity given sustainable free cash flow profile
  • Over $1 billion in debt reduction since mid-2018
  • Credit facility unanimously ratified in March 2019
  • $4+ billion max conforming borrowing base
  • Elected Commitment increased from $2.0 billion to $2.4 billion in October 2019
  • Revolver borrowings expected to be reduced via potential asset sales and free cash flow generation

Note: Revolver borrowings as of 9/30/19.

Significant Liquidity Profile

$4,500

$4,000

$3,500

Max Conforming

$3,000

Millionsin

$2,000

Borrowing Base

$2,500

$

$1,500

$1,000

Elected Commitment

$500

Revolver Borrowings

$0

Borrowings

Credit Facility

Staggered Bond Maturity Profile

$3,000

$2,500

Millionsin$

$2,000

$1,500

$1,000

$653

$749

$750

$550

$500

$72

$-

2019

2020

2021

2022

2023

2024

2025

2026

Range Notes

14

Appendix

Peer-Leading Capital Efficiency

Range's Estimated 2020 Capital Efficiency Remains Consistent With Prior Year,

Versus Some Peers Who May Rely on One-Time DUC Drawdowns.

$500 $450 $400 $350 $300

Implied D&C Maintenance Capital per Mcfepd

$384

$387

$388

$302

$325

DUCs?

DUCs?

$260

$250 $200 $150

RRC

Peer 1

Peer 2

2018

2019

2020

Peer 4

Peer 3

Peer 5

3-Year Average

2016

2017

2018

2019E

2020E

4Q Production (Mmcfepd)

1,854

2,170

2,260(a)

2,340

2,300(c)

Decline Rate from Prior Year 4Q

24%

23%

20%

20%

4Q-4Q Base Decline (Mmcfepd)

449

508

452

468

4Q-4Q Growth (Mmcfepd)

316

110(b)

135(b)

-40

Total Production Added (Mmcfepd)

765

617

587

428

D&C Costs Incurred ($ millions)

$1,180

$836

$665

$500

D&C Capex per Mcfepd Added

$1,542

$1,354

$1,133

$1,168

Implied D&C Maintenance Capital

$692

$688

$512

$547

Implied D&C Maintenance Capital per Mcfepd

$373

$317

$227

$234

Note: Southwest Appalachia peers include AR, CNX, EQT, GPOR and SWN. Peer estimates based on Company disclosures and Consensus estimates as of 12/31/19. (a) Includes 10 Bcfe of curtailments in 4Q18 from third-party processing downtime. (b) Pro forma asset sales. (c) Illustrative example based on full-year 2020 guidance. Does not represent quarterly guidance.

16

D&C Capex per Mcfepd Reflects Relative Capital Efficiency

2018 Quarterly Summary

1Q18

$192

$152 $139

$124

$128

$104

$84

2Q18

$177

$165

$151

$152

$156

$118

$82

3Q18

$180 $171

$137

$117 $108

$97 $84

4Q18

$157

$113

$101 $93

$74 $61

$41

2019 Quarterly Summary

1Q19

$202

2Q19

3Q19

4Q19E

$169

$159

$139

$117

$123

$123

$119

$93

$94

$91

$92

$94

$92

$91

$92

$98

$89

$86

$80

$83

$79

$79

$72

$66

$47

$37

$53

Note: Peers include AR, CNX, COG, EQT, GPOR and SWN. Peer estimates from company filings, presentations, transcripts, guidance and Range estimates. SWN estimates for 2018 represent Appalachia production and capital expenditures only. 4Q19 estimates based on FactSet Consensus as of 12/31/19.

17

Appalachia Assets - Stacked Pay

  • ~1.5 million net effective acres(a) in PA leads to decades of drilling inventory
  • Gas In Place analysis shows the greatest potential is in Southwest Pennsylvania
  • Approximately 1,000 producing Marcellus wells demonstrate high quality, consistent results across Range's position
  • Near-termactivity led by Core Marcellusdevelopment in Southwest PA
  • Range's Utica wells continue to produce strongly and our most recent well continues to be one of the best in the play
  • Adequate takeaway capacity in Southwest
    PA

Stacked Pay and Existing

Pads Allow for Multiple

Development Opportunities

(a) Assumes stacked pay opportunities in Marcellus, Utica and Upper Devonian

Gas In Place

For All Zones

Upper

Devonian

Marcellus

Utica/Point

Pleasant

18

Targeting / Downspacing Production Results

Normalized Mmcfe/Day per 1,000 ft.

3,000

2,500

2,000

1,500

1,000

500

-

Optimized targeting shows ~50% increase in cumulative production after 1,300 days

No detrimental production impact seen on the original wells

0

200

400

600

800

1000

1200

1400

AVERAGE ORIGINAL TARGETING

AVERAGE OPTIMIZED TARGETING

19

Return to Existing Pads - Marcellus

100,000

Drilled

10,000

Wells - 2015

(MCFD)Gas

Additional 3 wells

1,000

Future

Wellhead

100

Locations

Drilled

10

Wells - 2014

1

Mar-14

Oct-14

May-15

Dec-15Jul-16Mar-17Oct-17

May-18

Dec-18

Wellhead Gas

Ability to target our best areas with significant cost savings

20

Significant Utica Resource

  • Range has drilled three Utica wells
  • Range's third well appears to be one of the best dry gas Utica wells in the basin (next slide)
  • Continued improvement in well performance due to higher sand concentration and improved targeting
  • 400,000 net acres in SW PA prospective

The Industry Continues to Delineate the Utica around Range's Acreage

Note: Townships where Range holds ~2,000+ or more acres are shown outlined above

21

Utica Wells - Wellhead Pressure vs. Cumulative Production

Range's DMC Properties well one of the best in the Utica

22

Innovative NGL Marketing Agreements Enhance Pricing

  • First-moveron Appalachian NGL exports to Europe via ethane sales to INEOS using Mariner East capacity
  • Range's propane has been sold internationally since 2016 through
    Marcus Hook, with option to sell into premium NE winter markets
  • Mariner West ethane sent to Nova Chemical (Canada)
  • ATEX moves Appalachia ethane to the Gulf Coast (Mont Belvieu)

Marcus

Hook

Range NGL Transport

20,000

Mont

Belvieu

15,000

Bbls/d

10,000

5,000

0

Mariner East

Mariner East

Atex Ethane Mariner West

Propane

Ethane

Ethane

(a)

(a) FOB Houston Plant

23

High Quality Reserve Base

  • Proved reserves of 18.2 Tcfe as of year end 2019
  • Future development costs for proved undeveloped reserves are estimated to be $0.35 per Mcfe at YE2019

Total Proved Reserves (Tcfe)

20

18

16

14

12

10

8

6

4

2

0

2019 SEC PV10 of $7.6 billion

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

Positive Performance Revisions for Last Decade Indicate Quality of Reserves

24

Natural Gas & NGL Macro Outlook

Natural Gas - 35% of the U.S. Generation Mix in 2018

Growing Market Share in Power Gen.

  • Gas power demand grew by 11 Bcf/d from 2009-2018, while coal declined 11 Bcf/d(a) and renewables grew 5.3 Bcf/d(a)

Market Share Growth Should Continue

  • 25 Bcf/d of coal generation remains to be displaced, or ~27% of U.S. Power Generation Mix
  • 53 GW of coal plant capacity retired from
    2013-2018, and another 36 GW of plant retirements have already been announced for 2019-2024
    • More retirement announcements expected to occur in coming months/years
  • Planned nuclear retirements also remove large base-load of power generation
  • New gas-fired reciprocating engines being added to balance grid instability issues created by renewables

(a) Assumes 7x Heat Rate for gas equivalence

U.S. Power Generation by Source(a)

40

35

Equivalent

30

35%

25%

34%

33%

32%

25

30%

28%

28%

Day

20

23%

24%

21%

perBcf

15

10

10%

10%

8%

7%

7%

5

3%

4%

6%

4%

5%

5%

0

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

Coal

Gas

Nuclear

Hydro

Solar+Wind

Other

Source: EIA

Announced Coal & Nuclear Reactor Retirements

(MW)Retirements

16,000

5.0

Displacementequivalent)(Bcf/d

14,000

4.0

12,000

10,000

3.0

8,000

6,000

2.0

4,000

1.0

2,000

0

0.0

2019

2020

2021

2022

2023

2024

2025

Coal

Nuclear

Cumulative Displacement

Source: EIA

26

Shale Efficiency Gains Are Slowing

Oil Basins

  • Limited Tier-1 runway left in Williston, Mid- Con, DJ Basin and Eagle Ford as cores are believed to have been heavily drilled
  • Up-spacingacross several plays reduces core inventory life
  • Efficiency gains from lateral length and proppant intensity now seeing diminishing returns versus three years ago
  • Parent-childissues becoming more prevalent as child wells produce materially less than parent wells

Haynesville

  • Well productivity in the Haynesville appears to have plateaued
  • Runway for current productivity may be limited given current pace of development in the play and that the core is known to be small
  • Private operators may be forced to reduce growth as traditional exit strategies have become challenged

6-Month Daily Oil Production per 1,000 Lateral Ft.

Source: Cowen and Company, Enverus

Haynesville Production per 1,000 Lateral Ft.

Source: RS Energy

27

Dry Gas Basin Break-Evens Suggest Higher Prices

Supply Growth Needed from Dry Gas Basins

  • EIA forecasts 6.7 Bcf/d of 2019-2024 supply growth from outside of Northeast (mostly associated gas)
  • Demand growth forecast of +21 Bcf/d from 2019-2024 will require growth from dry gas basins to balance market

Higher-Than-Strip Prices Will Be Needed to Support Dry Gas Basin Growth

  • Northeast PA will face constraints given current lack of infrastructure
  • Dry gas basins likely require >$3/Mmbtu natural gas to support sustainable growth

Industry Break-Evens Above Current NYMEX Futures Curve

NYMEX Gas $/mcf

$5.00

$4.50

$4.00

$3.50

$3.00

$2.50

$2.00

$1.50

$1.00

$0.50

$0.00

$2.43

$4.30

$3.75

$3.32

$3.33

$3.37

$3.40

$3.07

Marcellus - NE PA Marcellus - SW

Marcellus - WV

Marcellus - SW Marcellus - Upper

Utica - Dry Gas Utica - Wet Gas

Marcellus -

PA Dry

Dry

PA - Wet

Marcellus

Ohio

Central PA

Source: J.P. Morgan. Break-evens assume 25% pre-taxfull-cycle rate of return to account for corporate G&A, interest expense and acreage costs.

28

L48 Dry Gas Production Growth Slowing

U.S. L48 Pipeline Flows (Bcf/d)

94

92

90

88

86

84

82

80

78

76

74

72

70

68

1-Jan

1-Feb1-Mar1-Apr1-May1-Jun

1-Jul

1-Aug1-Sep1-Oct

1-Nov1-Dec

Source: Platts

2017

2018

2019

29

LNG Growth Expected to Continue

U.S. LNG Export Terminal Capacity (Bcf/d)

22

20

FERC Approved and/or

18

>70% long-term offtake

signed. Potential Next

16

Wave Projects.

14

Under Construction

12

or In-Service

10

Freeport T1-T3

8

Cameron T1-T3

6

Corpus Christi T1-T2

4

Cove Point

Elba Island

2

Sabine Pass T1-T5

0

12/16

12/17

12/18

12/19

12/20

12/21

12/22

12/23

Source: Operator Estimates

Second Wave FIDs & Potential

Port Arthur

Magnolia LNG

Freeport T4

Cameron T4-T5

Golden Pass T1-T3

Sabine Pass T6

Calcasieu Pass

Corpus Christi T3

12/24

30

U.S. Natural Gas Exports to Mexico Making New Highs

U.S Natural Gas Exports to Mexico (Bcf/d)

6.5

6.0

5.5

5.0

4.5

4.0

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0.0

10/5/2014

10/5/2015

10/5/2016

4/5/2017

7/5/2017

10/5/2017

1/5/2018

4/5/2018

7/5/2018

10/5/2018

1/5/2019

4/5/2019

7/5/2019

10/5/2019

1/5/2014

4/5/2014

7/5/2014

1/5/2015

4/5/2015

7/5/2015

1/5/2016

4/5/2016

7/5/2016

1/5/2017

Source: Bloomberg

31

NGL Macro Outlook

NGL Demand

  • IEA forecasts LPG (propane and butane) and ethane to be the fastest growing global oil products over medium and long term
  • Demand growth driven primarily by petrochemical feedstock demand and residential demand in developing countries
  • U.S. waterborne export capacity increases in 2019 equivalent to ~15% of U.S. LPG supply, which should tighten balances going forward

U.S. Export Bottleneck Relieved

  • 2019 saw the addition of ~400 MBPD of new export capacity
  • 2020 is scheduled to add another 650 MBPD of new LPG export capacity
  • This doesn't include new ethane and ethylene export capacity additions in 2019 and 2020.

2017-2040 Change in Global Oil Product Demand by Scenario

Source: IEA World Energy Outlook 2018 (NPS = New Policy Scenario, SDS = Sustainable Development Scenario)

U.S. LPG Export Capacity (MMBL/D) Set to Increase

2.50

2.00

1.50

1.00

0.50

0.00

2017

2018

2019

2020

2021

Enterprise

- Houston

Targa - Galena Park

Sunoco - Mariner South

Phillips 66 - Freeport

Enlink - Riverside

Buckeye - Corpus Christi

DCP - Chesapeake

Sunoco - Marcus Hook

Petrogas - Ferndale

Source: Operator Estimates

32

Global LPG Demand Forecast Absorbs Growing U.S. Exports

Global LPG S&D Waterfall (MBL/D)

11,200

11,000

10,800

10,600

10,400

~1.2

10,200

MMBPD

10,000

9,800

9,600

9,400

9,200

2018 Demand

ResCom + Industry

PDH

Ethylene

2023 Demand

Non-U.S. Supply Call on U.S. Supply

+Autogas + Other

  • U.S. LPG Export Capacity to expand by 1,050 MBL/D (78%) by end 2020.
  • Global LPG demand grew ~4.5% 2013-18, and is forecast to grow ~3% 2018-23, driven by ~700 MBL/D of PDH and Ethylene plants under-construction or post-FID.
  • ResComm (~51% of demand in 2018) is driven by continued adoption rates in China, India, Indonesia and others for those without access to electricity.
  • Indian LPG import terminal expansions under-construction/planned of 350 MBL/D in 2020-2025
  • Relative economics support use of LPG over naphtha for international steam crackers. In an oversupply case, converting just 10% of the global naphtha ethylene cracking fleet would absorb a further 600 MBL/D of LPG.
  • Call on U.S. Supply is 1,200 MBL/D 2018-23, versus consultant supply growth forecasts of ~750 MLB/D.

Source: EIA, Energy Aspects, Genscape, IEA

33

Financial Detail

Well-Structured, Resilient Balance Sheet

  • $4+ billion max conforming borrowing base

($3B elected borrowing base, $2.4B committed)

  • Simple capital structure
  • Near-termcash flow protected with hedges
  • Ample cushion on financial covenants(a)
    • Interest coverage ratio(b) of ~5.0x versus covenant of at least 2.5x
    • Current ratio(c) of ~4.8x versus covenant of at least 1.0x
    • Asset coverage test(d) of ~2.6x versus covenant of at least 1.5x

Capital Structure(e)

(millions)

3Q19

Bank Debt

$

411

Senior Notes

2,725

Senior Sub Notes

49

Debt

3,186

Debt to Capitalization

43%

Debt/TTM EBITDAX

3.25x

Net Debt/Proved Developed Reserves ($/mcf)

Debt/Proved Developed Reserves

$0.90

$0.80

$0.70

$0.60

$0.50

$0.40

$0.30

$0.20

$0.10

$0.00

2013

2014

2015

2016

2017

2018

RRC

Peer Average

Note: Peer average includes AR, CHK, CNX, COG, EQT, GPOR and SWN.

Debt Maturity Schedule(e)

$3,000

$3 Billion Borrowing Base

Significant Liquidity

$2,500

$2.4 Billion Bank Commitment

Potential of ~$2.3 billion

Millions)in($

$2,000

$1,500

$1,000

$653

$749

$750

$550

$411

$500

$72

$-

2019

2020

2021

2022

2023

2023

2024

2025

2026

Range Notes

Senior Secured Revolving Credit Facility

Interest Rate

5.75%

5.2%(f)

5.0%

4.875%

9.25%

  1. As of 9/30/19 (b) Excludes non-cash interest expense (c) Calculated as (Current assets excluding derivatives + unused revolver capacity) / (current liabilities excluding derivatives) (d) Defined as PV-9 of reserves divided by total debt (e) As of 9/30/19, pro forma notes offering, tender offer and buyback program announcements (f) Weighted-average interest rate of 2022 notes

35

Natural Gas & NGL Hedging Status

Time Period

Volumes Hedged

Average Hedge Prices

(Mmbtu/day)

($/Mmbtu)

4Q19 Swaps

1,421,739

$2.82

1Q20 Swaps

1,007,253

$2.68

Natural Gas1

2Q20 Swaps

1,010,000

$2.62

(Henry Hub)

3Q20 Swaps

1,010,000

$2.62

4Q20 Swaps

976,848

$2.63

FY21 Swaps

50,000

$2.62

Time Period

Volumes Hedged

Average Hedge Prices

(bbls/day)

($/gal)

Propane (C3)

4Q19 Swaps

5,723

$0.54

Normal Butane (NC4)

4Q19 Swaps

4,804

$0.66

Normal Butane (NC4)

1Q20 Swaps

659

$0.73

Isobutane (iC4)

4Q19 Swaps

337

$0.78

Natural Gasoline (C5)

4Q19 Swaps

6,005

$1.29

Natural Gasoline (C5)

1Q20 Swaps

4,297

$1.21

*As of 12/31/19

  1. Range also sold natural gas call swaptions of 140,000 Mmbtu/d for March-December 2020, and 100,000 Mmbtu/d for calendar 2021 at average strike prices of $2.53 and $2.69 per Mmbtu, respectively.

36

Oil Hedging Status

Time Period

Volumes Hedged

Average Hedge Prices

(bbl/day)

($/bbl)

4Q19 Collars

1,000

$63 x 73

4Q19 Swaps

9,168

$56.11

1Q20 Swaps

9,000

$58.62

Oil (WTI)1

2Q20 Swaps

9,000

$58.18

3Q20 Swaps

8,500

$58.15

4Q20 Swaps

5,500

$58.00

FY21 Swaps

1,000

$55.00

*As of 12/31/19

  1. Range also sold WTI calls of 500 Bbls/d for 2Q-3Q 2020 at a strike price of $59 per Bbl and WTI call swaptions of 3,000 Bbls/d for calendar 2021 at an average strike price of $56.50 per Bbl.

37

Contact Information

Range Resources Corporation

100 Throckmorton St., Suite 1200

Fort Worth, Texas 76102

Laith Sando, Vice President - Investor Relations

  1. 869-4267
    lsando@rangeresources.com

Michael Freeman, Director - Investor Relations & Hedging

  1. 869-4264
    mfreeman@rangeresources.com

John Durham, Senior Financial Analyst

  1. 869-1538
    jdurham@rangeresources.com

www.rangeresources.com

38

Disclaimer

Range Resources Corporation published this content on 24 February 2020 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 24 February 2020 12:56:14 UTC

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