Company Presentation

July 26, 2021

2

Forward Looking Statements

All statements, except for statements of historical fact, made in this presentation regarding activities, events or developments the Companyexpects, believes or anticipates will or may occur in the future are forward-looking statements within the meaning of Section 27A of the SecuritiesAct of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements are based on assumptionsand estimates that management believes are reasonable based on currently available information; however, management's assumptions andRange's future performance are subject to a wide range of business risks and uncertainties and there is no assurance that these goals andprojections 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 itsmost recent Annual Report on Form 10-K. 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 andengineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic andoperating conditions as well as the option to disclose probable and possible reserves. Range has elected not to disclose its probable andpossible 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 orrecovery techniques that may include probable and possible reserves as defined by the SEC's guidelines. Range has not attempted to distinguishprobable and possible reserves from these broader classifications. The SEC’s rules prohibit us from including in filings with the SEC thesebroader classifications of reserves. These estimates are by their nature more speculative than estimates of proved, probable and possiblereserves and accordingly are subject to substantially greater risk of actually being realized. Unproved resource potential refers to Range's internalestimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recoverytechniques and have not been reviewed by independent engineers. Unproved resource potential does not constitute reserves within the meaningof the Society of Petroleum Engineer's Petroleum Resource Management System and does not include proved reserves. Area wide unprovenresource potential has not been fully risked by Range's management. “EUR”, or estimated ultimate recovery, refers to our management’sestimates of hydrocarbon quantities that may be recovered from a well completed as a producer in the area. These quantities may not necessarilyconstitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or theSEC’s oil and natural gas disclosure rules. Actual quantities that may be recovered from Range's interests could differ substantially. Factorsaffecting ultimate recovery include the scope of Range's drilling program, which will be directly affected by the availability of capital, drilling andproduction 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 andmechanical factors affecting recovery rates and other factors. Estimates of resource potential may change significantly as development of ourresource plays provides additional data.

In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of productiondecline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity pricedeclines or drilling cost increases. Investors are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, availablefrom our website at www.rangeresources.com or by written request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You canalso obtain this Form 10-K on the SEC’s website at www.sec.gov or by calling the SEC at 1-800-SEC-0330.

3

Pennsylvania

• Top 10 U.S. Producer of Natural Gas & NGLs

• Top NGL Exporter Among Independent E&Ps

• Pioneered Marcellus Shale in 2004

• Most Capital Efficient Operator in Appalachia

• Longest Core Inventory Life in Appalachia

• Upstream Leader in Environmental Practices

Range – Who We Are

4

Range – At a Glance

Focus on Free Cash Flow▪ Peer-leading well costs and base decline rate drive low sustaining capital requirements

▪ Cost structure improvements and marketing strategies have reduced breakeven price

▪ Low sustaining capital requirements and breakeven support significant and durable free cash flow generation at strip pricing

Unmatched Appalachian Inventory▪ Approximately one-half million net acres provide decades of low-risk drilling inventory

▪ Contiguous position allows for efficient operations and long-lateral development

▪ Proved Reserves of 17.2 Tcfe at YE2020 – PV-10 of over $22 per share, net of debt(a)

Upstream Leader on Environmental Practices and Safety▪ Targeting net zero direct GHG emissions by 2025

▪ Reduced environmental impact and enhanced profitability through:

▪ Emissions monitoring and responsibly sourced natural gas (RSG) certification project

▪ Water recycling and logistics

▪ Long-lateral development and innovative facility designs

▪ Electric-powered fracturing fleet

▪ Robust Leak Detection and Remediation (LDAR) program

Management Incentives Aligned to Support Free Cash Flow, Corporate Returns,

Balance Sheet Strength & Environmental Leadership

(a) Assumes natural gas price of $2.75/mmbtu and oil price of $50/bbl

5

Delivering on Strategic Objectives

✓ Most Capital Efficient Operator in Appalachia(a)

• 2018-2020 D&C Capex of ~$280 per Mcfepd versus peer average of ~$385 per Mcfepd

• Delivered on operational plans while spending under budget for three consecutive years

✓ Enhanced Margins Through Cost Improvements & Marketing Strategies• 2020 cash unit costs of $1.85/mcfe improved $0.33, or ~15% since end of 2018

• Increased exports improved NGL realizations versus Mont Belvieu by over $3.50 per barrel in 2020 versus 2018

✓ Strengthened Balance Sheet & Maturity Profiles• Reduced absolute debt for three consecutive years

• Approximately $750 million(b) senior notes due by end of 2023 could be retired via expected free cash flow at strip pricing

• Current liquidity of over $1.9 billion(b) expanding via free cash flow

✓ Successful Emissions Reduction & Water Recycling Programs• Lowest emissions intensity within U.S. upstream sector

• Recycled 148% of produced water in 2020 through Range’s water recycling and sharing program

(a) Calculated as D&C Capital Expenditures divided by Mcfe per day of Production. See slide 7 for details. (b) As of 6/30/21

6

2021 Outlook

All-In Capital Budget of $425 Million or Less▪ Production to be maintained at ~2.15 Bcfe per day

▪ 2021 activity sets up capital efficient 2022 development plan

Absolute Debt Expected to Be Reduced for Fourth Consecutive Year via Free Cash Flow

Significant EBITDA and Cash Flow Growth Forecasted at Strip Pricing(a)

▪ NGL realizations expected to exceed $30 per barrel, or $5 per mcfe, in 2H 2021

Leverage Expected to Decline Considerably in 2021 and Beyond▪ Calculated leverage of below 2.5x at YE2021 based on strip pricing(a)

▪ Leverage forecasted to decline below 2x in early 2022 based on strip pricing(a)

Maintain Strong Environmental & Safety Practices▪ Continue to recycle all of Range’s produced water, in addition to third party water

▪ Implemented new software that further improves safety, enhances efficiency, and reduces truck traffic and emissions

▪ Targeting net zero direct GHG emissions by 2025

(a) Assumes strip pricing as of 7/19/21

7

$0

$100

$200

$300

$400

$500

$600

$700

RRC Peer 4 Peer 1 Peer 2 Peer 3 Peer 5

2018 2019 2020

Peer-Leading Capital Efficiency

Note: Peers include AR, CNX, COG, EQT and SWN. Peer estimates from company filings, presentations, transcripts, guidance

and Range estimates. SWN estimates for 2018 represent Appalachia production and capital expenditures only.

3-Year Average

$280

$375 $376 $383

$481

$310

Well Costs per Lateral Foot Decline Rate

D&C Capex per Mcfepd Reflects Relative Capital Efficiency

Peer-Leading Development Costs & Decline Rate Drive

Lowest Development Costs per Unit of Production in Appalachia

$0

$100

$200

$300

$400

$500

$600

$700

$800

$900

$1,000

RRC Peer 1 Peer 3 Peer 5 Peer 2 Peer 40%

5%

10%

15%

20%

25%

30%

35%

RRC Peer 1 Peer 4 Peer 2 Peer 3 Peer 5

8

Low Maintenance Capital Requirement

(a) Assumes 10,000 ft. laterals (b) Assumes constant DUC inventory

J F M A M J J A S O N D

Appalachia production:

~2.15 Bcfe/d

Ending production:

~1.74 Bcfe/d

1st year recoveries(a) for SW PA wells:

• Super Rich = 2.93 Bcfe gross (2.33 Bcfe net)

• Wet = 3.77 Bcfe gross (3.00 Bcfe net)

• Dry = 4.17 Bcf gross (3.31 Bcf net)

Average: ~2.88 Bcfe net per well

Well Costs(a) for SW PA:

• Super Rich: $6.57 million

• Wet: $6.21 million

• Dry: $5.49 million

Average: ~$6.1 million cost per well

~19% Base Decline

Production to Replace:

~82 Bcfe

Additional Considerations(b)

• Non-D&C investment: ~$25 million annually

• Typical operating adjustments:

• Ethane flexibility

• TIL allocation (wet vs. dry)

• Timing of TILs

• Maintenance, weather, etc.

~$425 million All-In Maintenance Capital

Simple Calculation(b)

• Average well contributes ~1.44 Bcfe net in calendar

year if brought on mid-year under perfect conditions

• Production can be held flat with ~57 wells

57 wells x 1.44 Bcfe recovery = ~82 Bcfe

• ~57 wells x ~$6.1mm average well cost = ~$350mm

~$350 million D&C Maintenance Capital

9

Sustainable Cost Reductions:

• Extending average lateral length

• Fuel savings from electric fracturing

fleet

• Utilizing recycled water from Range

and surrounding operators

• Self-sourcing sand

• Increasing feet drilled per rig day

• Frac efficiency (increasing stages per

day per crew)

• Reducing facilities costs

$200

$300

$400

$500

$600

$700

$800

$900

$1,000

2018 2019 2020

An

nu

al C

apit

al E

xpe

nd

itu

res

($ m

illio

n)

Budget Actual

Well Cost Reductions Enhance Capital Efficiency

Efficiency Gains Have Driven Range’s Best-In-Class Well Costs Even Lower…

…Leading to Three Consecutive Years of Spending Below Budget

Annual Capital Expenditures Reduced

>50% Since 2018, While Appalachia

Production Has Grown +10%

2018: $31 million under budget

2019: $28 million under budget

2020: $109 million under original budget

• Original budget of $520 million

• Budget reduced to $430 million in March

• Budget reduced again to $415 million in

October, due to efficiency gains

• Actual 2020 spending of $411 million

$500

$525

$550

$575

$600

$625

$650

$675

$700

$725

$750

2019 Plan Drilling &Operational

Completion WaterRecycling,Facilities &Well Mix

2020 Plan Drilling &Completion

WaterRecycling &

Service Costs

2021 Plan

All

-In

We

ll C

ost

s p

er L

ate

ral

Foo

t

10

Considerable Progress in Reducing Unit Costs

Direct Operating Expense

Cash G&A Production Taxes

Direct Operating Expense (LOE)

▪ Declined $0.06 per mcfe, or ~35%, from 2018 to 2020 due to Range’s water management and recycling program, as well as divestment of higher cost assets

Cash G&A

▪ Declined $0.04 per mcfe, or ~20%, from 2018 to 2020

▪ Headcount reduced ~33% from 2018 to 2020 following asset sales and workforce assessment

Production Taxes

▪ Declined $0.03 per mcfe, or ~50%, from 2018 to 2020 due to divestment of higher cost assets

$0.00

$0.02

$0.04

$0.06

$0.08

$0.10

$0.12

$0.14

$0.16

$0.18

2018 2019 2020 2021E

LOE

pe

r Mcf

e

$0.00

$0.01

$0.02

$0.03

$0.04

$0.05

$0.06

$0.07

2018 2019 2020 2021E

Pro

du

ctio

n T

axe

s p

er

Mcf

e

$100

$110

$120

$130

$140

$150

$160

2018 2019 2020 2021E

An

nu

al C

ash

G&

A ($

mil

lio

ns)

Note: 2021E figures represent midpoint of annual guidance

11

-$300

-$250

-$200

-$150

-$100

-$50

$0

2022E 2023E 2024E 2025E 2030E

$ m

illio

ns

Annual GP&T Improvement Versus 2021

Contractual Decline Range's Election

$1.20

$1.30

$1.40

$1.50

2021E 2022E 2023E 2024E 2025E

GP

&T

per

Mcf

e

Unit Cost Improvement to Continue

Gathering Costs to Decline

▪ Certain contracts in Appalachia are structured such that Range’s fees decline annually, while capacity remains the same

▪ Contractual savings continue through 2030 and beyond for the same capacity

Transportation Optionality

▪ Range has the option to renew certain contracts or let them expire, depending upon economics

Gathering & Transport Contracts Structured to Decline

GP&T Improves as Contractual Costs Decline

(a) Assumes maintenance capital, flat NGL prices in 2022+, and the renewal of transportation contracts

GP&T Is Expected to Decline

Over the Coming Years.

Contractual Declines Continue

Through 2030 and Beyond.

(a)

12

NGL Margins & Price Uplift Expanding

NGL Margins Expanding with Rising Prices

Liquids Price Uplift Drives Premium Realizations to NYMEX

NGL Margins Reach Multi-Year High• Range’s NGL realizations increased over

$11.50/bbl in 1H 2021 vs. 2020

• NGL margins increased over $10/bbl in 1H

2021 vs. 2020, net of price-linked processing

• NGL prices and margins expected to increase

further in 2H 2021, assuming strip pricing(a)

Margin Uplift Increases Cash Flow• NGL prices rising in 2021 by ~$14/bbl(a) versus

2020 results in ~$500 million incremental

revenue and ~$400 million cash flow

Liquids Production Driving

Premium Realizations• Range’s average 1H 2021 realization

was over $0.45 above NYMEX gas

• Range’s realizations compare favorably

versus dry gas peers, who typically

realize prices below NYMEX gas

Condensate Provides Further Uplift • Range’s average 1H 2021 condensate

realization of over $53/bbl equates to

nearly $9 per mcfe

$0

$5

$10

$15

$20

$25

$30

1H 2019 2H 2019 1H 2020 2H 2020 1H 2021

$ p

er B

arre

l

NGL GP&T Pre-Hedge NGL Margin Pre-Hedge NGL Realization

-$0.30

-$0.15

$0.00

$0.15

$0.30

$0.45

$0.60

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

1H 2019 2H 2019 1H 2020 2H 2020 1H 2021

RR

C R

ea

lizatio

n v

s. NY

ME

X H

HLiq

uid

s R

ealiz

atio

n ($

/mcf

e)

Liquids Realization ($/mcfe) RRC Realization ($/mcfe) vs NYMEX HH

Note: Figures based off pre-hedge realizations (a) Assumes strip pricing as of 7/19/21

13

Oil-Linked

Gas-Linked

Mont Belvieu

Ethane Diversification

Exports

Northeast

Propane & Butane

Range’s Strong NGL Realizations Driven by Exports

Differentiated NGL Sales Arrangements

▪ Range exports a larger percentage of propane and butane than any U.S. independent

▪ Ability to extract additional ethane based on relative economics

Ability to Export Boosting Realizations

▪ Range’s differential to Mont Belvieu has improved considerably, driven by increased exports

▪ Range expects international price arbs to support continued exports

▪ Realizations expected to improve significantly in 2021 and beyond versus 2020

Note: Pie charts represent annual average. Range has the ability to increase domestic sales in winter months when local prices are strong.

NGL Prices Have Significantly Increased

Ability to Export Provides Price Diversification

NGL Differential Improving With Increased Exports

Source: Bloomberg. (a) Based on average NGL barrel composition of 53% ethane, 27% propane, 7% normal

butane, 4% isobutane and 9% natural gasoline.

(a)

(a)

$5

$10

$15

$20

$25

$30

$35

Mo

nt

Be

lvie

u N

GL

Pri

ce (

$/b

bl)

($4.00)

($3.00)

($2.00)

($1.00)

$0.00

$1.00

$2.00

$3.00

2018 2019 2020 2021E

Dif

fere

nti

al to

Mo

nt

Be

lvie

u ($

/bb

l)

14

-$0.75

-$0.25

$0.25

$0.75

$1.25

$1.75

$2.25

$2.75

$3.25

-$0.75

-$0.25

$0.25

$0.75

$1.25

$1.75

$2.25

$2.75

$3.25

RRC Peer 1 Peer 2 Peer 3 Peer 4

LOE GP&T Cash G&A Prod Taxes Interest Capex/mcfe Differential Breakeven

Lowest Breakeven Among SW Appalachia E&Ps

Source: Company press releases, presentations and guidance. Peers include AR, Ascent, EQT and SWN. Differential calculated as

average realized unhedged price per mcfe versus NYMEX natural gas from 2018 through 2Q 2021.

Best-in-Class Sustaining Capital Requirements

▪ Lowest well costs and base decline rate in Appalachia drive lowest maintenance capital requirements per mcfe

Competitive Cost Structure

▪ Range has the lowest normalized cost structure among wet gas peers

▪ Processing costs more than offset by higher realized prices from liquids sales

▪ Range expects its cost structure to continue to improve, even under a zero-growth scenario

Strong Price Realizations versus NYMEX

▪ Range’s unhedged realized price per mcfe is typically above NYMEX natural gas price

▪ Strong realizations driven by liquids price uplift and competitive marketing strategies

▪ Dry gas peers typically realize prices below NYMEX natural gas, increasing breakeven price requirements

Liquids Price Uplift Improves Breakeven

Range’s Low Corporate Breakeven & Multi-Decade Core Inventory Drive

Highly-Competitive, Sustainable Free Cash Flow

Breakeven NYMEX Natural Gas Price

$2.20

$2.25

$2.30

$2.35

$2.40

$2.45

$2.50

RRC Peer 1 Peer 2 Peer 3 Peer 4

15

Rapid De-Leveraging at Strip Prices

(a) Prices shown for 2021 and 2022 outlooks approximate strip, including the impact of hedges, as of 7/19/2021. NGL benchmark

represents Mont Belvieu prices, based on Range’s NGL barrel weighting of 53% ethane, 27% propane, 7% normal butane, 4% isobutane

and 9% natural gasoline.

2021 Outlook(a) ($3.25 NG / $64 WTI / $27.50 NGL)

▪ Free cash flow drives fourth consecutive year of absolute debt reduction

▪ Significant EBITDAX growth versus 2020 driven by higher natural gas and NGL prices

▪ Forecasted leverage declines to <2.5x by year end

2022 Outlook(a) ($3.25 NG / $62 WTI / $25 NGL)

▪ EBITDAX grows further in 2022, despite backwardation in futures pricing, driven by improvements in GP&T expense and Range’s favorable hedge position

▪ Forecasted leverage improves to <2x in early 2022 at strip pricing

Range Is Positioned to Return Capital to Shareholders in Near Future

▪ Cumulative free cash flow at strip pricing totals approximately $1 billion in 2021 and 2022

▪ Achieving long-term balance sheet targets positions Range to potentially return capital to shareholders

Significant EBITDAX Growth

At Strip Prices, Range Expects to Generate Significant Free Cash Flow.

Long-Term Balance Sheet Targets Can Be Met in Near Future.

Free Cash Flow Strengthens Balance Sheet

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2020 2021 Outlook 2022 Outlook

EBIT

DA

X ($

mill

ion

s)

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

2020 2021 Outlook 2022 Outlook

Net D

ebt / EB

ITDA

X

Ne

t D

eb

t ($

mill

ion

s)

Year-End Net Debt Year-End Leverage

16

Unmatched Position in Southwest Appalachia

Significant Marcellus Inventory(a)

▪ ~460,000 Net Acres in Southwest Pennsylvania

▪ ~3,100 Undrilled Marcellus Wells

• 2,600 liquids rich well inventory

• 500 dry gas well inventory

Repeatable Capital Efficiency▪ Range estimates ~2,000 undrilled Marcellus

locations remain with EURs greater than 2.0 Bcfeper 1,000 foot of lateral

▪ In addition, over 1,000 down-spaced Marcellus locations

▪ Additional potential from Utica & Upper Devonian

Range acreage

outlined in green

(a) Estimates as of YE2020; includes anticipated down-spacing activity. Based on 10,000 ft lateral length. (b) Source:

Enverus. Peers include AR, CNX, COG, EQT and SWN. Based on estimated inventory below $40 WTI and $2.25 Henry Hub.

Longest Core Inventory Life in Appalachia(b)

0

2

4

6

8

10

12

14

16

18

Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 RRC

Ye

ars

of I

nve

nto

ry

17

Proved Developed

Proved Undeveloped

Resource Potential

Value of Year-End 2020 Proved Reserves

Included in SEC Reserves▪ By rule, only 5 years of development activity

▪ Proved Developed reserves of 9.8 Tcfe

▪ Proved Undeveloped (PUD) reserves of 7.4 Tcfe

▪ Includes ~360 Marcellus PUD locations

Reserve Value Ignores Resource

Potential▪ Approximately 2,700 undrilled Marcellus wells not

classified as reserves

▪ Potential from ~400,000 net acres of both core

Utica and Upper Devonian

Reserve History▪ PUD Development Costs consistently improving

▪ Positive performance revisions to reserves each

year for the last decade

~100 Tcfe

9.8 Tcfe

7.4 Tcfe

PV-10 of $8.6 Billion Equates to Over $22/share, Net of Debt @ $2.75 NG / $50 Oil

PV-10 Increases to $10.7 Billion, or Over $30/share, Net of Debt @ $3 NG / $60 Oil

18

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2.2

Marcellus Utica Montney

No

rmal

ized

EU

R (B

cfe

per

1,0

00 ft

.)

2014 2015 2016 2017 2018 2019 2020

Shale Oil Recoveries Already Declining

Range to Benefit as Peers Exhaust Core Inventory

Declining Recoveries per Foot in Most Shale Basins Demonstrate Core Exhaustion

▪ Declining well productivity is evident in both shale oil and natural gas basins

▪ Parent-child issues becoming more prevalent

▪ Up-spacing reduces core inventory life

Industry Inventory Is Limited & Concentrated

▪ The cores of U.S. shale basins are known

▪ Most remaining core inventory is concentrated within portfolios of a small group of producers

▪ Companies with the longest core inventory life, such as Range, should benefit as other operators exhaust their core inventories

Peer Productivity Declining in Appalachia & Montney

Haynesville Productivity Has Also Plateaued

Source: Bernstein, Enverus. (a) Represents data through July 2020

11.3

11.5 (1.7%) 11.6 (0.3%)

11.3 (-2.5%) 11.2 (-0.6%)

10.0

10.2

10.4

10.6

10.8

11.0

11.2

11.4

11.6

11.8

2016 2017 2018 2019 2020

Bb

l pe

r ft

.

Total Oil Production per Foot in First 6 Months (YOY Change %)

While Several Peers Are Demonstrating

Core Exhaustion, Range’s Recoveries

Per Foot Have Been Consistent.

(a)

2020: -8%

Below Peak

2020: -26%

Below Peak2020: -25%

Below Peak

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2.2

2014 2015 2016 2017 2018 2019 2020

Bcf

e p

er 1

,000

ft.

Haynesville Normalized EURs

(a)

19

Natural Gas Macro Has Significantly Improved

Supply Growth Minimal Despite Rising Prices

U.S. Exports Are at Record Highs Gas Retaining Market Share at Higher Prices

Natural Gas Supply Has Been Stable

▪ EIA forecasts modest supply growth of ~1.4 Bcf/d exit-to-exit in 2021, following ~4.5 Bcf/d decline in 2020

▪ Future supply will be affected by significant reduction in industry activity, as natural gas rig count has declined ~50% from early 2019

▪ Recent industry efficiency likely unsustainable following >2,700 DUC drawdown since June 2020

Natural Gas Demand Has Been Growing

▪ Recent exports of over 17 Bcf/d are >35% higher than 2020 average

▪ Export capacity to grow further in 2021 and beyond

Source: EIA, Bloomberg, Baker Hughes (a) Data represents summer season

60

65

70

75

80

85

90

95

100

EIA

U.S

. Dry

Gas

Pro

du

ctio

n (

Bcf

/d)

02468

1012141618

Bcf

pe

r D

ay

LNG Exports Exports to Mexico

45%

47%

49%

51%

53%

55%

57%

59%

61%

63%

65%

67%

69%

71%

73%

75%

$1.00 $1.25 $1.50 $1.75 $2.00 $2.25 $2.50 $2.75 $3.00 $3.25 $3.50 $3.75 $4.00

Gas Generation as % of Thermal Generation (Gas+Coal) vs. NYMEX

2016-20 2020 2021

(a)

20

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

Jan-19 Apr-19 Jul-19 Oct-19 Jan-20 Apr-20 Jul-20 Oct-20 Jan-21 Apr-21

MB

L/D

EIA LPG Exports Terminal Export Capacity

Source: EIA, operator announcements

U.S. C3+ Supply Expected to Flatten

Rapid Decline in U.S. Propane Storage Levels

NGL Prices Rising As Macro Improves

Significant Growth in U.S. LPG Export Capacity

Supply Forecasted to Be Stable

▪ Reduced activity in 2020 and industry focus on capital discipline reduces potential for supply growth

▪ EIA forecasts U.S. C3+ supply to average ~3% lower in 2021 versus 2020 highs

Significant Storage Deficit Demonstrates Level of Under-Supply

▪ U.S. LPG export capacity grew ~23% in 2020, with additional export capacity to come online in 2021

▪ 2020-21 winter experienced largest propane storage withdrawal in over a decade

2.0

2.2

2.4

2.6

2.8

3.0

3.2

3.4

EIA

U.S

. C3+

Fie

ld P

rod

uct

ion

(MM

BL/

D)

35

45

55

65

75

85

95

105

U.S

. Pro

pan

e S

tora

ge (

MM

BL)

2020 2021 5-Year Avg.

21

U.S. Emissions Reductions Driven by Power Gen.

Electric Vehicle Growth Increases Power Demand Significant Coal Displacement Potential Remains

Source: EIA, NREL, IEA, BP Statistical Review of World Energy

Natural Gas Plays Critical Role in Energy Transition

Emissions Reductions Driven by Natural Gas

▪ Between 2005 and 2019, total U.S. electricity generation increased ~2%, while related CO2 emissions decreased ~33%

▪ EIA attributes ~61% of U.S. power generation emissions reductions to natural gas displacing coal

Natural Gas to Reduce Global Emissions

▪ Electrification of domestic and global economies will boost power demand, much of which will be supplied by natural gas

▪ China and India are increasing natural gas use in efforts to reduce emissions growth

49%

23%

65% 71%

36%

19%

38%

3%4%

23%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

U.S.(2005)

U.S.(2019)

China(2019)

India(2019)

World Average(2019)

2019

Po

we

r G

en

era

tio

n M

ix

Coal Natural Gas Nuclear Hydro Renewables Other

U.S

. E

lectr

icity C

onsum

ptio

n (

TW

h)

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,800

5,000

5,200

5,400

5,600

5,800

6,000

6,200

Po

we

r Ge

n. &

All O

the

r Secto

r

Tota

l En

erg

y

U.S. CO2 Emissions (MMT)

Total Energy Emissions Power Gen. Emissions All Other Sector Emissions

22

Leading in Environmental Practices

(a) Represents Appalachia operations. (b) Workforce and field operations personnel include contractors and Range employees.

For additional information, Range’s 2020 Corporate Sustainability Report can be found on the Company’s website.

Commitment to Clean & Efficient Operations

▪ Over 80% reduction in GHG emissions intensity since 2011

▪ Class-leading GHG emissions intensity of <0.25 metric tons of CO2e per Mmcfe produced in 2020(a)

▪ Recycled 148% of produced water volume through Range’s water recycling and sharing program in 2020

▪ Reduced component-related emissions by 67% due to increased LDAR program

Industry-Leading Emissions Targets

▪ 15% reduction in GHG emissions intensity by 2025 versus 2019 levels

▪ Net Zero GHG emissions by 2025 through continued direct emissions reductions along with carbon offsets, such as reforestation and forest management

Health & Safety Achievements(b)

▪ 80% reduction in total number of Workforce Recordable Incidents over last three years

▪ 68% reduction in Workforce Total Recordable Incident Rate (TRIR) in 2020 versus 2019

▪ 64% reduction in total number of Preventable Vehicle Incidents in 2020 versus 2018 and 2019

Continued Success in Reducing Emissions Intensity

Water Recycling Program Reduces Fresh Water Use

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

2017 2018 2019 2020

GH

G I

nte

nsi

ty (

MT

CO

2e

/Mm

cfe

)

0%

25%

50%

75%

100%

125%

150%

175%

200%

0

5

10

15

20

25

30

35

40

2017 2018 2019 2020

Re

use

Wate

r as % o

f Pro

du

ced

Wate

r

Vo

lum

e o

f W

ate

r (M

illio

n B

bls

)

Freshwater Use Reuse Water from Range

Reuse Water from Other Operators Reuse Water as % of Produced Water

(a)

23

✓ Average Director tenure of five years

❖ Steve Gray appointed to the Board in October 2018

❖ Margaret Dorman appointed to the Board in July 2019

✓ Diversity remains a priority, as Range seeks to achieve a combination of knowledge, experience and skills

✓ 33% of independent directors are women

✓ 50% of committees chaired by women

✓ Independent Chairman

✓ Actively engage directly with shareholders

✓ Formed ESG & Safety Committee with all independent directors currently serving

Director Independence

All directors are independent except the CEO

Board Governance Social Responsibility

Governance & Social Responsibility

Range Is Committed to Strong Governance and Social Responsibility.

Range Views These Objectives as Core to Delivering Long-Term Value for Shareholders.

24

Long-Term Equity Incentive Plan

Long-term incentives focused on shareholder returns and prioritize balance sheet strength and environmental leadership.

✓ 60% Absolute Measures & 40% Time-Based RSU

✓ Greater than 85% of CEO compensation at-risk

✓ Removed absolute measures of production and reserve growth per debt-adjusted share in favor of:

▪ Balance sheet leverage target of 1.5x

▪ Emissions intensity target

✓ Relative TSR component has absolute performance modifier

✓ S&P 500 introduced as peer to better align performance

✓ Restricted stock modified to 3-year cliff vesting from 30% / 30% / 40%

Annual Incentive Targets

Short-term incentives focused on key financial and ESG framework targets, prioritizing returns, cost efficiencies and environmental, health & safety measures.

✓ Removed production and reserve growth per debt-adjusted share in favor of returns-based metrics:

▪ Added Return on Capital

▪ Drilling Rate-of-Return (added in 2017)

✓ EHS component relies heavily on quantitative assessments including:

▪ TRIR for employees and contractors

▪ Preventable vehicle incidents

▪ Spills and leak rates

▪ Notices of violations

✓ Cash Unit Costs & Drilling & Completion Cost per Foot

✓ Reduced discretionary weighting and set rigorous targets

Executive Compensation Framework

Continued Improvements to Compensation Framework Are Essential to Aligning

Incentives with Evolving Shareholder Interests & Long-Term Strategic Initiatives

Changes to 2021 Incentive Plans Were Informed by the Board’s Direct Outreach to

Stakeholders, Including Holders of Over 65% of Shares Outstanding

Appendix

26

Multi-Decade Inventory of Capital Efficient Wells

Range Has Delineated Its Acreage Position in Southwest Appalachia▪ Since pioneering the Marcellus in 2004, Range

has drilled across its SW Appalachian position

▪ More than 1,200 producing wells provide control data for new development activity

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

• Long-lateral development

• Efficient water handling and sourcing

• Use of electric fracturing fleet and existing infrastructure

Track Record of Returning to Existing Pads▪ Network of approximately 250 existing pads with

an average of 5 producing wells versus capacity designed for an average of 20 wells

▪ Drives savings through use of existing surface infrastructure

▪ Over 60% of 2021 activity on existing pads, similar to prior years

▪ Well results after several years from returning to existing pads show no degradation in recoveries

Southwest Pennsylvania = Existing Pad

27

Appalachia Assets – Stacked Pay

▪ ~1.5 million net effective acres(a) in PA leads to decades of drilling inventory

▪ Activity led by Core Marcellus development in Southwest PA

▪ Over 1,200 producing Marcellus wells demonstrate high quality, consistent results across Range’s position

▪ Gas In Place analysis shows the greatest potential is in Southwest Pennsylvania

▪ ~400,000 net acres in SW PA prospective for Utica / Point Pleasant

▪ Range’s third dry gas Utica well appears to be one of the best in the basin

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

28

% of RRC Barrel Mont Belvieu ($/gal) 1Q 2021E 2Q 2021E 3Q 2021E 4Q 2021E Avg. 2021E

53% Ethane $0.24 $0.26 $0.31 $0.32 $0.28

27% Propane $0.89 $0.87 $1.05 $1.04 $0.96

7% Normal Butane $0.94 $0.97 $1.20 $1.17 $1.07

4% Isobutane $0.93 $0.98 $1.22 $1.18 $1.08

9% Natural Gasoline $1.33 $1.46 $1.52 $1.49 $1.45

$0.59 $0.61 $0.72 $0.71 $0.66

$24.83 $25.68 ~$30.00 ~$29.75 ~$27.50

$26.35 $27.92 $28.00 - $29.50

$1.52 $2.24 $0.50 - $2.00

Range-Equivalent Mont Belvieu Barrel ($/gal)

Range-Equivalent Mont Belvieu Barrel ($/bbl)

Range's Pre-Hedge Realization ($/bbl)

Range's NGL Differential ($/bbl)

NGL Price Calculation Example

Note: Prices represent strip pricing as of 7/19/2021. Calculations illustrate pre-hedge realizations.

Conversion rate is 42 gallons : 1 barrel

2021 Guidance Is the Range-Equivalent Mont Belvieu Barrel

PLUS $0.50 to $2.00 per Barrel

29

Southwest Appalachia Marcellus Modeling Data

YearCondensate

(Mbbls)

Residue

(Mmcf)

NGL

(Mbbls)

1 87 1,158 208

2 122 1,962 353

3 146 2,655 477

5 179 3,817 685

10 230 5,965 1,067

20 291 8,744 1,557

EUR 360 11,973 2,111

Note: 2021 plan well costs and type curves assume 10,000 ft. average lateral. Average SWPA NRI is ~79.5%. NGL

recoveries assume 80% ethane extraction.

Super-Rich Area

▪ ~110,000 Net Acres

▪ EUR / 1,000 ft. = 2.68 Bcfe

▪ D&C Cost / ft. = $657

Gross Estimated Cumulative Recoveries by Year

YearCondensate

(Mbbls)

Residue

(Mmcf)

NGL

(Mbbls)

1 29 1,763 306

2 43 2,934 509

3 52 3,882 674

5 63 5,382 934

10 73 7,969 1,383

20 78 11,151 1,935

EUR 80 14,714 2,554

Wet Area

▪ ~240,000 Net Acres

▪ EUR / 1,000 ft. = 3.05 Bcfe

▪ D&C Cost / ft. = $621

YearResidue

(Mmcf)

1 4,166

2 6,334

3 7,928

5 10,288

10 14,096

20 18,576

EUR 24,135

Dry Area

▪ ~110,000 Net Acres

▪ EUR / 1,000 ft. = 2.41 Bcfe

▪ D&C Cost / ft. = $549

Macro OutlookNatural Gas & NGL

31

Natural Gas Demand Growth Outlook

2021-25 Demand Outlook

▪ Total demand growth of +18 Bcf/d through 2025 from LNG and Mexican exports, industrial and electric power demand growth

▪ LNG feedgas capacity increased to over 11 Bcf/d in 2020, with further growth planned in 2021

▪ Second Wave LNG Projects could add another +7 Bcf/d of exports by 2025

▪ Continued coal (currently ~19% of power stack) and nuclear retirements (~20% of power stack) present upside to this demand outlook

U.S. LNG Export Demand Outlook

▪ Second Wave U.S. LNG Projects of ~5 Bcf/d already under-construction. Further +2-4 Bcf/d likely to FID in 2021-22

▪ Over 30 Bcf/d of Second-Wave LNG projects have been proposed

▪ Range forecasts U.S. LNG feedgas capacity to reach ~14 Bcf/d in 2022 and ~19 Bcf/d by 2025

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

U.S. Gas Demand Growth Outlook (Bcf/d)

Source: EIA, LNG operator announcements, Range Resources

Sabine Pass T1-T5

Cove PointElba Island

Corpus Christi T1-T2

Cameron T1-T3

Freeport T1-T3

Corpus Christi T3

Calcasieu Pass

Sabine Pass T6

Golden Pass T1-T3

Potential 2021 FID Projects

0

2

4

6

8

10

12

14

16

18

20

12/16 12/17 12/18 12/19 12/20 12/21 12/22 12/23 12/24 12/25

Under Constructionor In-Service

FERC Approved, Potential Next Wave Projects

ECA Phase 1

0

2

4

6

8

10

12

14

16

18

20

2016-20 2021-25

R+C Other Industrial Electric Power Mexico Exports LNG Exports

32

Natural Gas – 40% of U.S. Generation Mix

Growing Market Share in Power Gen.

▪ Gas power demand grew by 12 Bcf/d from 2010-2020, while coal declined 20 Bcf/d(a)

and renewables grew 6 Bcf/d(a)

Market Share Growth Should Continue

▪ Approximately 15 Bcf/d of coal generation remains to be displaced, or ~19% of U.S. Power Generation Mix

▪ 66 GW of coal plant capacity retired from 2013-2019, and another 44 GW of coal plant retirements have already been announced for 2020-2025

▪ More retirement announcements expected to occur in coming months/years

▪ Planned nuclear retirements (~10 GW of announced retirements for 2020-2025) also remove large base-load of power generation

▪ New gas-fired reciprocating engines being added to balance grid instability issues created by renewables

Announced Coal & Nuclear Reactor Retirements

U.S. Power Generation by Source(a)

Source: EIA. (a) Assumes 7x Heat Rate for gas equivalence

21% 23%24% 25%

30%28% 28%

33% 34%32%

35%38% 40%

3% 4% 4% 5%5% 6% 7% 7% 8% 10% 10%

11% 13%

48%

44%45%

42%

37%39% 39%

33%30% 30%

28%

23%

19%

0

5

10

15

20

25

30

35

40

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Bcf

pe

r D

ay E

qu

ival

en

t

Coal Gas Nuclear Hydro Solar+Wind Other

0.0

1.0

2.0

3.0

4.0

5.0

6.0

0

3,000

6,000

9,000

12,000

15,000

18,000

2020 2021 2022 2023 2024 2025

Disp

lacem

ent (B

cf/d e

qu

ivalen

t)

Re

tire

me

nts

(M

W)

Coal Nuclear Cumulative Displacement

33

68

70

72

74

76

78

80

82

84

86

88

90

92

94

96

98

1-Jan 1-Feb 1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct 1-Nov 1-Dec

U.S

. L4

8 P

ipe

line

Flo

ws

(Bcf

/d)

2018 2019 2020 2021

Lower 48 Dry Gas Production Has Declined

Source: Bloomberg

U.S. Natural Gas Production Has Declined ~7% From 2019 Highs,

Despite Return of Shut-In Production and DUC drawdowns in 2020 and 2021.

Future Supply Expected to Remain Low Due to Reduced Operator Activity.

34

Natural Gas Supply Less Net Exports

Source: Bloomberg

68

70

72

74

76

78

80

82

84

86

88

90

92

1-Jan 1-Feb 1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct 1-Nov 1-Dec

U.S

L4

8 G

as P

rod

uct

ion

-N

et

Exp

ort

s (B

cf/d

)

2018 2019 2020 2021

U.S. Natural Gas Supply Has Returned to 2018

Levels, When Accounting for Significant Growth in

U.S. Exports in Recent Years.

35

86

88

90

92

94

96

98

100

102

104

106

108

110

112

114

116

2020Demand

ResComm& Other

Industrial ElectricPower

MexicoExports

LNGExports

2025Demand

AssociatedGas

GOM & OtherDecline

Call onGassy Basins

Higher Prices Required to Meet Demand Growth

U.S. Natural Gas Supply & Demand Waterfall (Bcf/d)

▪ Demand grows >18 Bcf/d by 2025, driven by increased Mexico & LNG exports and power generation

▪ Collapse in oil-basin activity in 2020 and industry focus on capital discipline significantly reduces outlook for associated gas growth versus pre-2020 expectations

▪ Haynesville grows ~4.5 Bcf/d by 2025, more than offset by declines in offshore and legacy production

▪ Result is a call on Appalachia natural gas of an additional +18 Bcf/d to meet new demand

▪ Even if oil basin activity increases with rising oil prices, significant growth is still needed from gassy basins to meet future demand.

▪ Higher prices will be needed for Appalachia supply growth to meet demand

▪ Investor pressure for free cash flow limits public operator spending at current strip pricing

▪ Capital markets not open for most producers to finance outspends

▪ Lack of exit strategy and incremental funding pressures PE-backed private operators to preserve liquidity / generate free cash

Source: EIA supply estimates from AEO 2020. Other supply represents legacy shale, conventional, offshore and imports.

~23Bcf/d

36

-6

-5

-4

-3

-2

-1

0

1

2

3

4

LPG & Ethane Naphtha Gasoline Kerosene Diesel Fuel OilOther

Products

Ch

ange

in

De

man

d v

s. 2

01

9 (

MM

BL/

D)

STEPS 2025 STEPS 2030 SDS 2030 STEPS 2040 SDS 2040

NGL Demand Growth

▪ IEA forecasts LPG (propane and butane) and ethane to be the fastest growing global oil products over medium and long term

▪ IEA projects LPG growth in residential cooking use, reducing global emissions versus current use of biomass for cooking

▪ IEA forecasts Indian LPG demand to grow >50% 2019-2030 as access to clean cooking grows

▪ In 2021, Asian PDH plants are scheduled to start up with a combined capacity of 125 MBPD of propane demand, in addition to another 55 MMPD of LPG demand from new Asian ethylene capacity

U.S. Export Bottleneck Relieved

▪ 2020 export capacity increased by ~500 MBPD versus EIA field production of LPG (C3, NC4 and iC4) of 2,650 MBPD in April 2021

▪ U.S. waterborne export capacity increases equivalent to ~19% of U.S. LPG Gas Plant supply, which should tighten balances going forward

▪ Local Northeast propane differentials have improved since start up of Mariner East 2

EIA Forecasts C3+ Supply to Average ~4% Lower in 2021 Versus 2020 Highs, Following Reduction in Industry Activity

NGL Macro Outlook

Change in Global Oil Product Demand by Scenario

Source: IEA WEO 2020 (STEPS = Stated Policies Scenario, SDS = Sustainable Development Scenario)

Ample Capacity for Additional U.S. LPG Exports

Source: IEA, India Energy Outlook, EIA, Genscape, Range estimates

-14.0 -10.7

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0

500

1,000

1,500

2,000

2,500

Cap

acity Utilizatio

n

MB

L/D

PADDs 1 & 3 LPG Export Capacity PADDs 1 & 3 LPG Exports Capacity Utilization

37

0%

20%

40%

60%

80%

100%

120%

Jul-93 Jul-95 Jul-97 Jul-99 Jul-01 Jul-03 Jul-05 Jul-07 Jul-09 Jul-11 Jul-13 Jul-15 Jul-17 Jul-19 Jul-21

Pro

pan

e /

WTI

Cru

de

Pri

ce R

atio

Propane% WTI Average

Propane Prices Moving Back to Pre-Shale Norms

▪ Prior to the U.S. shale boom, propane fundamentals supported prices ~70% of WTI

▪ When shale supply growth outpaced demand growth and export capacity, the propane-WTI relationship de-coupled

▪ However, reduced shale supply growth and significant export capacity growth since early 2020 have strengthened propane fundamentals, as propane prices have begun to return to the pre-shale norm

▪ Going forward, industry discipline and commitment to free cash flow reduce the future supply outlook. Meanwhile, global demand for cleaner fuels continues to grow, and the U.S. has ample spare LPG export capacity to reach growing global demand.

▪ Strengthened propane fundamentals support prices similar to pre-shale relationship to WTI. For example, 70% of $60/bbl WTI equates to $1/gal propane.

Balanced Market Average (1993-2011): 71%

Shale Supply Growth & Logistical Bottlenecks (2012-2020): 47%

Expected Return to

Balanced Market

38

9,600

9,800

10,000

10,200

10,400

10,600

10,800

11,000

11,200

11,400

11,600

11,800

2020 Demand ResCom + Industry

+Autogas + Other

PDH Ethylene 2025 Demand Non-U.S.

Supply

Call on

U.S. Supply

LPG Demand Absorbs Growing U.S. Exports

Global LPG Supply & Demand Waterfall (MBL/D)

▪ U.S. LPG Export Capacity expanded ~500 MBL/D by end of 2020

▪ Global LPG demand CAGR of ~3.8% 2011-20. Forecast assumes demand grows at 5-year CAGR of 3.4%. New PDH/ethylene projects drive ~780 MBL/D of demand growth.

▪ ResComm (~50% of demand) is steadily growing due to continued adoption rates in China, India, Indonesia and other regions without access to electricity

▪ International LPG supply is impacted by OPEC+ production cuts, lower refinery run rates/closures (~30% of global LPG supply comes from refining), and a slowdown in new LNG projects

▪ Relative economics support use of LPG over naphtha for international steam crackers. In an over-supply case, converting just 10% of global naphtha ethylene cracking fleet would absorb a further 600 MBL/D of LPG.

▪ Call on U.S. Supply is ~850 MBL/D 2020-25, versus consultant supply growth forecasts of ~25 MBL/D

Source: EIA, Energy Aspects, Genscape, IEA

~850 MBPD

Financial Detail

40

2021 Annual Guidance

(a) Represents differential to Mont Belvieu-equivalent barrel, based on a weighting of 53% ethane, 27% propane, 7% normal

butane, 4% iso-butane and 9% natural gasoline.

Full-Year 2021

Guidance

Production per Day ~2.15 Bcfe

Capital Expenditures

Drilling & Completion $400 Million

Land & Other $25 Million

Cash Expense Guidance

Direct Operating Expense per mcfe $0.09 - $0.11

TGP&C Expense per mcfe $1.43 - $1.47

Production Tax Expense per mcfe $0.02 - $0.04

G&A Expense per mcfe $0.15 - $0.16

Exploration Expense $20 - $25 million

Interest Expense per mcfe $0.26 - $0.28

DD&A Expense per mcfe $0.47 - $0.50

Net Brokered Marketing Expense $2 - $10 million

Pricing Guidance

Natural Gas Differential to NYMEX ($0.30) to ($0.40)

Natural Gas Liquids (a) $0.50 to $2.00 per barrel

Oil/Condensate Differential to WTI ($7.00) - ($9.00)

41

$218

$532

$121

$750$850

$600

$0

$400

$800

$1,200

$1,600

$2,000

$2,400

2021 2022 2023 2023 2024 2025 2026 2027 2028 2029 2030+

$ in

mill

ion

s

2Q 2021

Range Notes Senior Secured Revolving Credit Facility

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

2016 2017 2018 2019 2020

Net

Deb

t/P

D R

eser

ves

($/m

cfe)

RRC Peer Average

$498

$929

$749 $943 $750

$0

$400

$800

$1,200

$1,600

$2,000

$2,400

2021 2022 2023 2023 2024 2025 2026 2027 2028 2029 2030+

$ i

n m

illi

on

s

Year-End 2018

Range Notes Senior Secured Revolving Credit Facility

Well-Structured, Resilient Balance Sheet

• $3 billion elected borrowing base reaffirmed in March

2021

• $2.4 billion elected commitment

• Ample cushion on financial covenants

• Interest coverage ratio(a) covenant of at least 2.5x

• Current ratio(b) covenant of at least 1.0x

• Asset coverage test(c) covenant of at least 1.5x

• No Debt-to-EBITDA covenant

Note: Peers include AR, CNX, EQT and SWN. (a) Excludes non-cash interest expense (b) Calculated as (Current assets excluding

derivatives + unused revolver capacity) / (current liabilities excluding derivatives) (c) Defined as PV-9 of reserves divided by total debt

$2.4 Billion Bank Commitment

Equates to Significant

Liquidity of Over $1.9 Billion

Total Debt:

~$3.1 Billion

Debt / Proved Developed Reserves

Successfully Reduced Debt & Improved Maturity Profile

Total Debt:

~$3.9 Billion

42

Natural Gas & Oil/Condensate Hedges

1) 2022 swap volume assumes election on 160,000 Mmbtu/d of call swaptions for calendar 2022 at an average strike price of $2.89 per Mmbtu

2) 2022 swap volume assumes election on 1,000 Bbl/d call swaptions for calendar 2022 at an average strike price of $54 per Bbl

As of 7/16/21 Time Period Daily Volumes Hedged Average Hedge Prices

Natural Gas1

(Henry Hub)

$/Mmbtu

3Q 2021 Swaps

4Q 2021 Swaps

3Q 2021 3-Way Collars

4Q 2021 3-Way Collars

3Q 2021 Collars

4Q 2021 Collars

2022 Swaps

2022 3-Way Collars

2022 Collars

566,848

583,152

313,152

306,304

360,000

227,391

390,000

200,000

60,000

$2.77

$2.79

$2.16 / $2.48 x $2.80

$2.13 / $2.47 x $2.90

$2.52 x $3.00

$2.87 x $3.42

$2.86

$2.20 / $2.72 x $3.35

$2.93 x $3.34

Oil/Condensate2

(WTI)

$/Bbl

3Q 2021 Swaps

4Q 2021 Swaps

2022 Swaps

6,832

7,500

5,560

$55.58

$56.92

$59.24

43

NGL Hedges

As of 7/16/21 Time Period Barrels per Day Hedged Average Hedge Prices

C3 Propane

3Q 2021 Collars

3Q 2021 Swaps

4Q 2021 Swaps

5,000

10,000

2,000

$0.95 x $1.05/gal

$0.88/gal

$1.00/gal

nC4 Butane

3Q 2021 Collars

4Q 2021 Collars

3Q 2021 Swaps

4Q 2021 Swaps

3,000

2,000

2,000

2,000

$0.90 x $1.00/gal

$1.00 x $1.20/gal

$1.01/gal

$1.09/gal

C5 Natural Gasoline

3Q 2021 Collars

4Q 2021 Collars

3Q 2021 Swaps

4Q 2021 Swaps

1Q 2022 Collars

1Q 2022 Swaps

1,000

3,000

4,000

2,000

2,000

1,000

$1.30 x $1.55/gal

$1.35 x $1.55/gal

$1.22/gal

$1.41/gal

$1.45 x $1.60/gal

$1.50/gal

44

Contact Information

Range Resources Corporation

100 Throckmorton St., Suite 1200

Fort Worth, Texas 76102

Laith Sando, Vice President – Investor Relations

(817) 869-4267

lsando@rangeresources.com

John Durham, Lead Financial Analyst

(817) 869-1538

jdurham@rangeresources.com

www.rangeresources.com