Range Resources : Company Presentation – August 3, 2020

Company

Presentation

August 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-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 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 - Who We Are

Pennsylvania

• Top 10 U.S. Natural Gas Producer
• Top 5 U.S. NGL Producer
• Pioneered Marcellus Shale in 2004
• Approximately One-Half Million Net Acres in Southwest Appalachia
• Leader in NGL Exports & 1st U.S. Independent E&P to Export Ethane
• Upstream Leader in Environmental Practices

3

Range - At a Glance

Strong Emphasis on Capital Efficiency

• 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

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
• Peer-leadingwell costs and productivity underpin top-tier recycle ratio
• Proved Reserves of 18.2 Tcfe at YE2019 - SEC PV-10 of over $17 per share, net of debt(a)

Upstream Leader on Environmental Practices and Safety

• Reduced environmental impact and enhanced profitability through:
• • Water recycling and logistics
  • Long-lateraldevelopment
  • Electric-poweredfracturing fleet
  • Innovative facility designs
  • Robust Leak Detection and Remediation (LDAR) program

(a) SEC PV-10 assumes $2.58/Mmbtu NYMEX natural gas and $55.73/bbl WTI	4

Delivering on Strategic Objectives

• Continued to Reduce Absolute Debt
• Executed Over $1.35 Billion in Asset Sales Since Second Half 2018
• Delivered on Production Targets While Spending Under Budget in Consecutive Years
• Most Capital Efficient Operator in Appalachia(a)
• • 2019 D&C Capex of ~$292 per Mcfepd versus Appalachia peer average of ~$402 per Mcfepd
  • Second quarter 2020 well costs under $600 per foot, lowest in Appalachia
  • Base decline rate of ~19% following North Louisiana divestiture
• Improved Unit Costs
• • Cash unit costs in 2Q20 of $1.79/mcfe improved $0.39, or ~18% since end of 2018
• Significantly Enhanced Liquidity Profile
• • Liquidity exceeds $1.6 billion following North Louisiana asset sale
  • Senior note maturities through 2022 reduced by over $700 million since end of 2018

(a) Calculated as D&C Capital Expenditures divided by Mcfe per day of Production. See slide 10 for details.	5

2020 Plans and Financial Positioning

• All-InCapital Budget of $430 Million
• Appalachia Production Expected to Average ~2.15 Bcfe per day
• Improve Capital Efficiency Through Well Cost Reductions
• 2020 Activity Sets Up Capital Efficient 2021 Development Plan
• • Year-end2020 in-process well inventory similar to year-end 2019
• Enhance Margins Through Cost Improvements & Marketing Strategies
• Strengthen Balance Sheet & Liquidity Profile
• • Repurchased $360 million in bond principal at a discount to par, reducing absolute debt by $47 million since second half 2019
  • Announced sale of North Louisiana assets for $245 million in 3Q20, with the potential for up to $90 million in contingency payments, while additional asset sale processes remain underway
  • Absolute debt expected to be reduced for third consecutive year

6

Unmatched Position in Southwest Appalachia

Range acreage

outlined in green

Significant Marcellus Inventory

• ~470,000 net acres in Southwest Pennsylvania
• ~3,300 Undrilled Marcellus Wells(a)
• • 2,700 liquids rich well inventory
  • 600 dry gas well inventory

Repeatable Capital Efficiency

• Range estimates ~2,000 undrilled locations(a) remain with EURs greater than 2.0 Bcfe per 1,000 foot of lateral
• In addition, over 1,000 down-spaced Marcellus locations

Additional Opportunities

• Highly prolific Utica wells extend Range's dry gas opportunity beyond the Marcellus
• Upper Devonian, mirroring production mix of Marcellus, also provides ability to use existing infrastructure

(a) Estimates as of YE2019; includes anticipated down-spacing activity. Based on 10,000 ft lateral length	7

Multi-Decade Inventory of Capital Efficient Wells

= Existing Pad	Southwest Pennsylvania

Range Has Delineated Its Acreage Position in Southwest Appalachia

• Over the past ten years, Range has drilled across its SW Appalachian position
• More than 1,000 producing wells provide control data for new development activity
• Contiguous acreage position provides for operational efficiencies and industry leading well costs:
• • Long-lateraldevelopment
  • Efficient water handling and infrastructure re-utilization

Track Record of Returning to Existing Pads

• Network of over 200 existing pads with an average of 5 producing wells versus capacity designed for an average of 20 wells
• Represents approximately half of 2020 activity, similar to prior years
• Allow for more efficient use of natural gas-powered electric fracturing fleet
• Well results after several years from returning to existing pads show no degradation in recoveries

(a) Assumes 10,000 ft. lateral	8

Growing Evidence of U.S. Shale Core Exhaustion

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-childissues becoming more prevalent
• Up-spacingreduces core inventory life

Core 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

Average U.S. Shale Oil Recoveries

Average Oil Peak Rate per Foot (YOY Change %)

104

				102.1 (1.2%)
	102
Ft.		100.9 (4.0%)
Lateral	100
98
1,000	97.0
96
per
				94.4 (-7.6%)
Bo/d
94
	92
	90
	2016	2017	2018	2019

Peer 1 - Southwest PA Normalized Recoveries

	1,800
	1,600
Ft.	1,400
Lateral	1,200
1,000	1,000
800
per	600
Mcf/d
400
	200
	0

1	3	5	7	9	11	13	15	17	19	21	23	25	27	29	31	33	35
								Month
						2017		2018		2019

Peer 2 - Northeast PA Normalized Recoveries

2,500

Lateral Ft.	2,000
1,500
1,000
Mcf/d per	1,000
500
	0

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39

	Month
2017	2018	2019

Source: Stifel, Bernstein, Enverus	9

Peer-Leading Capital Efficiency

Well Costs per Lateral Foot		2020 Decline Rate

$1,200 $1,000

$800

$600 $400

$200

$0

40% 35% 30% 25% 20% 15% 10% 5% 0%

RRC	Peer 1	Peer 2 Peer 3	Peer 4	Peer 5	Peer 6			RRC	RRC	Peer 2	Peer 1	Peer 4	Peer 3	Peer 5	Peer 6
												ex-NLA
D&C Capex per Mcfepd Reflects Relative Capital Efficiency
$700							2018		2019		2020	3-Year Average
$600
$500																	$472
$400							$381		$384	$386		$389

$310

$300	$283
$200
$100

$0

RRC

Peer 4

Peer 2

Peer 1

Peer 3

Peer 6

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,	10
guidance and Range estimates. SWN estimates for 2018 represent Appalachia production and capital expenditures only.

Low Maintenance Capital Requirement

Appalachia production:

~2.2 Bcfe/d

Production = ~84 Bcfe

~19% Base Decline

Ending production:

~1.8 Bcfe/d

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

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

• Super Rich = 2.83 Bcfe gross (2.25 Bcfe net)
• Wet = 3.66 Bcfe gross (2.91 Bcfe net)
• Dry = 4.34 Bcf gross (3.45 Bcf net)

Average: ~2.87 Bcfe net per well

Well Costs(a) for SW PA:

• Super Rich: $7.30 million
• Wet : $6.30 million
• Dry: $5.85 million

Average: ~$6.5 million cost per well

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 ~59 wells

59 wells x 1.44 Bcfe recovery = ~84 Bcfe

• ~59 wells x ~$6.5mm average well cost = ~$385mm

~$385 million Maintenance D&C Capital

Typical Operating Adjustments(b)

• Considerations impacting annual development
• • Ethane flexibility
  • TIL allocation (wet vs. dry)
  • Timing of TILs
  • Maintenance
  • Weather

~$440 million Maintenance D&C Capital

(a) Assumes 10,000 ft. laterals (b) Assumes constant DUC inventory	11

Maintenance Capital Drives Free Cash Flow Ability

Sustainable

Free Cash Shallow 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
• Base decline rate of <20% is sustainable, potentially improving as production flattens
• 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

12

Considerable Progress in Reducing Unit Costs

• Cash G&A per mcfe declined ~30% in 2Q20 versus 2018
• Headcount reduced by ~33% since 2018 following asset sales and workforce assessment

LOE & Production Tax

	$0.22
Mcfeper	$0.20
$0.18
Cost	$0.16
$0.14
	$0.12
	$0.10

2018	2019	Original 2020	2H20E
		Guidance

Cash G&A

	$0.20
	$0.19
Mcfe	$0.18
$0.17
per
$0.16
Cost
$0.15
	$0.14
	$0.13
	$0.12

2018	2019	Original 2020	2H20E
		Guidance

• LOE savings driven by:
• • Continued efficiency gains from Range's water management and recycling program
  • Divestment of higher cost assets

13

Unit Cost Improvement Expected to Continue

Cost per Mcfe

$2.00 $1.90 $1.80 $1.70 $1.60 $1.50 $1.40 $1.30 $1.20 $1.10

4Q18	1Q19	2Q19	3Q19		4Q19	Prior 2020	2H20E	2024E
						Guidance		(ZeroScenarioGrowth)
		GP&T	Cash G&A	LOE	Production Taxes

Gathering, Processing & Transport Overview

• GP&T declined $0.15/mcfe from 2Q19 to 2Q20 through full utilization of existing infrastructure
• GP&T expense expected to continue to improve even without production growth, driven by:
• • Expiration of legacy transportation and gathering contracts in non-core assets
  • Certain contracts in Southwest Appalachia structured such that Range's fees decline over time
  • Ability to let certain transportation contracts expire when up for renewal

14

Natural Gas Macro Significantly Improving

Natural Gas Supply Declining Rapidly

• U.S. natural gas supply has declined over 10% from its November 2019 high
• EIA now forecasts >10 Bcf/d of exit-to-exit declines in 2020, placing supply back at 2018 levels
• Supply has only modestly rebounded despite return of shut-in production, while future supply affected by significant reductions in industry activity

Gas Rig Count Decline Steepens

• Natural gas rig count down ~65% from early 2019
• Potential dry gas supply response muted by disciplined capital spending

Gas Rig Count Collapse Delays Supply Recovery

	220		100
Rigs	200		90	Haynesville
160		70
	180		80
TotalGas	140		60	Appalachia&
120		50
	100		40	Rigs
	80		30
	60		20
	Total Gas Rigs	Haynesville	Appalachia

U.S. Natural Gas Supply Has Collapsed

	98
	96
	94
(Bcf/d)	92
90
88
Flows
86
84
Pipeline
82
80
L48	78
76
U.S.
74
	72
	70
	68

	1-Jan	1-Feb1-Mar	1-Apr1-May	1-Jun	1-Jul	1-Aug	1-Sep1-Oct	1-Nov1-Dec
			2016	2017		2018	2019	2020
		Supply Declines Expected to Continue
	100
(Bcf/d)	95
90
Production
80
	85
Gas	75
Dry
U.S.EIA	70
	65
	60

Source: EIA, Bloomberg, Baker Hughes	15

NGL Macro Benefits from Lower Oil Supply

NGL Supply Expected to Decline

• Reduced oil and gas drilling and completion activity drives falling NGL supply in 2020
• U.S. propane production has declined over 260,000 barrels per day since early 2020
• Near-termsupply benefits from reduced refiner utilization rates

NGL Prices Benefit from Higher Natural Gas Prices

▪ Ethane historically trades at a premium to natural

gas to account for transport and frac fees

▪ Higher natural gas prices incentivize ethane

rejection (reduced supply)

▪ Higher ethane prices support propane and

normal butane fundamentals through

petrochemical feedstock flexibility

U.S. NGL Supply Forecast to Decline

EIA U.S. C3+ Field Production (MMBL/D)

3.4 3.2 3.0 2.8 2.6 2.4 2.2 2.0

Higher Natural Gas Prices Benefit NGLs

C2 Premium to NYMEX Gas (cents per gallon)

40

While 2021 Ethane Futures Currently

30

Trade Near Gas Parity, History and

▪	Over 85% of Range's NGL barrel is comprised of
	ethane, propane and normal butane
▪	Isobutane and natural gasoline demand
	expected to recover in 2H2020

Global Ethane & LPG Demand Has Been Much Stronger Than Oil & Other Liquids

Improving NGL Fundamentals Suggest

Ethane Should Trade at a Premium

20

10

0

-10

Jan-16Jan-17Jan-18Jan-19Jan-20Jan-21Jan-22Jan-23

Source: EIA, Bloomberg	16

Range's Strong NGL Realizations Driven by Exports

Differentiated NGL Sales Arrangements

• Range exports a larger portion of propane and butane than any U.S. independent
• Diversified ethane sales agreements leave minimal exposure to Mont Belvieu pricing

Ability to Export Boosting Realizations

• Range's differential to Mont Belvieu improved throughout 2019 with further price uplift expected in 2020
• Range expects international price arbs to support continued exports

Range's Ability to Export Provides Price Diversity

Ethane Price Diversity	Propane & Butane
Mont
Belvieu	Northeast /
	Mont Belvieu
Oil-Linked
Gas-Linked	Exports

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

NGL Differential Improving With Increased Exports

$2.00

($/bbl)	$1.00
Belvieu	$0.00
Montto
($1.00)
Differential	($2.00)
($3.00)
	($4.00)

1H18

2H18

1H19

2H19

2020E

Note: Weighting based on 53% ethane, 27% propane, 7% normal butane, 4% isobutane and 9% natural gasoline.

International Price Strength Versus Mont Belvieu

gallon)	$0.35	Europe Advantaged Versus Mont
	$0.30	Marcus Hook Shipments to
per	$0.25	Belvieu Due to Lower Freight
($	$0.20
Arb
$0.15
Propane
$0.10
International	$0.05
$0.00
	($0.05)
	($0.10)

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

17

Capital Discipline Strengthens Financial Position

Range's Balance Sheet Continues to Improve Through Disciplined Spending & Strategic Initiatives…

$4,200

$ in millions

$4,000 $3,800 $3,600 $3,400 $3,200 $3,000

Total Debt Reduced by Over 25% Since Early 2018, While Additional Asset Sale Processes Remain Underway

$2,800 $2,600 $2,400

…As Peers Consistently Outspent Cash Flow

Flow/
Cumulative Free Cash	(a)
(Outspend) ($mil)
2018-2019

$200

$100

$0

($100)

($200)

($300)

($400)

($500)

($600)

($700)

RRC

Peer 1

Peer 2

Peer 3

Peer 4

Peer 5

Note: Peers include AR, CNX, EQT, GPOR and SWN. (a) Free cash flow defined as Discretionary Cash Flow less Capital Expenditures.

Excludes one-time items. (b) Includes dividends, share repurchases, changes in working capital, and other non-recurring expenses.	18
(c) Pro forma sale of North Louisiana.

Leading in Environmental Practices

Range is actively	Ranked second	Range's water sharing
working to achieve zero	among top	program is recycling
net emissions across	producers on water	153% of its own and
its operations	management	offset producers water
	and corporate
	environmental
	policies1

1 Rankings according to "Disclosing the Facts 2019: Transparency and Risk in Water & Chemicals Management for	19
Hydraulic Fracturing Operations"

Positioned Well for Low Commodity Prices

$ in Millions

$8,000

$7,000

$6,000

$5,000

$4,000

$3,000

$2,000

$1,000

$0

Borrowing Base

Elected

Commitment

(a)	Credit Facility	SEC PV-10
Borrowings

Self-Funded Business Model

• Flexible capital program as firm transportation commitments are met with current production
• 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

• Over $1.2 billion in debt reduction since mid-2018(a)
• $3 billion borrowing base reaffirmed in March 2020 despite challenged commodity environment
• Borrowing base projected to be unchanged following North Louisiana asset sale
• Elected Commitment increased from $2.0 billion to $2.4 billion in October 2019
• Significant asset coverage - YE19 SEC PV-10 is ~3.2x elected commitment
• Revolver borrowings expected to be reduced via potential asset sales

Note: SEC PV-10 assumes $2.58/Mmbtu NYMEX natural gas and $55.73/bbl WTI. (a) As of 6/30/20, pro forma sale of North Louisiana.	20

Appendix

D&C Capex per Mcfe/d Reflects Relative Efficiency

1Q18

$192

2018 Quarterly Summary

2Q18

3Q18

4Q18

$152

$139 $130 $124

$104

$84

$82

$177 $165

$151	$154	$156

$118

$137

$117 $108

$97 $84

$180 $173

$159

$113

$101 $93

$74 $61

$41

2019 Quarterly Summary

		1Q19	$202				2Q19					3Q19					4Q19
														$178
			$134					$133	$137	$139
		$123	$123
$89	$93	$94	$91	$92	$94							$92					$94
								$86				$85	$87
		$80					$79
							$79
										$66						$63
														$51	$54	$55
										$39

Note: Peers include AR, CNX, COG, EQT, GPOR and SWN. Peer estimates from company filings, presentations, transcripts, guidance and	22
Range estimates. SWN estimates for 2018 represent Appalachia production and capital expenditures only.

Operational Flexibility Given Commitments Have Been Met

2,000,000 Range Is Producing >10% in Excess of Firm Transport Commitments

1,800,000

Mmbtu per day (Gross)

1,600,000

1,400,000

1,200,000

1,000,000

800,000

Dec-20Dec-21Dec-22Dec-23Dec-24	Dec-25Dec-26Dec-27Dec-28Dec-29Dec-30
Marcellus Takeaway Capacity	Range Natural Gas Production (December 2019)

Range Has the Option to Renew Contracts Based on Pricing and Production Outlook

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 YE19

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

Note: SEC PV-10 assumes $2.58/Mmbtu NYMEX natural gas and $55.73/bbl WTI	24

Value of Year-End 2019 ProvedReserves

Proved Developed

9.9 Tcfe

Proved Undeveloped

8.3 Tcfe

Resource Potential

~100 Tcfe

Included in SEC Reserves

• By rule, only 5 years of development activity
• Proved Developed reserves of 9.9 Tcfe
• Proved Undeveloped (PUD) reserves of 8.3 Tcfe
• Includes 442 Marcellus PUD locations

Reserve Value Ignores Resource Potential

• Approximately 2,800 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

SEC PV-10 of $7.6 Billion Equates to Over $17/share, Net of Debt

Note: SEC PV-10 assumes $2.58/Mmbtu NYMEX natural gas and $55.73/bbl WTI	25

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
• Over 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

Gas In Place

For All Zones

Upper

Devonian

Marcellus

Utica/Point

Pleasant

(a) Assumes stacked pay opportunities in Marcellus, Utica and Upper Devonian	26

Significant Utica Resource

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

▪ Range has drilled three Utica wells in Washington County

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

▪ Continued improvement in well performance due to higher sand concentration and improved targeting

The Industry Continues to Delineate the Utica

around Range's Acreage

27

Southwest Appalachia Marcellus Modeling Data

	Super-Rich Area		Wet Area		Dry Area
▪	~110,000 Net Acres	▪	~240,000 Net Acres	▪	~120,000 Net Acres
▪ EUR / 1,000 ft. = 2.60	▪ EUR / 1,000 ft. = 2.96	▪ EUR / 1,000 ft. = 2.52
	Bcfe		Bcfe		Bcfe
▪	D&C Cost / ft. = $730	▪	D&C Cost / ft. = $630	▪	D&C Cost / ft. = $585

Gross Estimated Cumulative Recoveries by Year

Year	Condensate	Residue	NGL		Year	Condensate	Residue	NGL		Year	Residue
(Mbbls)	(Mmcf)	(Mbbls)		(Mbbls)	(Mmcf)	(Mbbls)		(Mmcf)
1	87	1,150	193		1	29	1,737	292		1	4,341
										2	6,677
2	122	1,949	328		2	43	2,890	486
3	146	2,637	443		3	52	3,823	644		3	8,379
										5	10,870
5	179	3,791	637		5	63	5,300	892
10	230	5,942	996		10	73	7,849	1,321		10	14,846
20	291	8,683	1,460		20	78	10,982	1,849		20	19,487
EUR	360	11,890	1,999		EUR	80	14,491	2,440		EUR	25,199

Note: Well costs and type curves assume 10,000 ft. average lateral. Average SWPA NRI is ~79.5%. NGL recoveries assume	28
80% ethane extraction.

Macro Outlook

Natural Gas & NGL

Natural Gas Demand Growth Outlook

2020-25 Demand Outlook

• Total demand growth of +17 Bcf/d through 2025 from LNG and Mexican exports, industrial and electric power demand growth
• LNG feedgas capacity to increase by end of 2020 to 10 Bcf/d from projects under-construction
• Second Wave LNG Projects could add another +8 Bcf/d of exports by 2025
• Continued coal (currently ~23% of power stack) and nuclear retirements (~20% of power stack) present upside to this demand outlook

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 +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 ~13 Bcf/d in 2022 and ~16 Bcf/d by 2024

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

25	R+C		Other
	Industrial		Electric Power
20	Mexico Exports	LNG Exports
15
10
5
0
	2014-19		2020-25
	Demand Growth		Demand Growth
	U.S. LNG Export Terminal Capacity (Bcf/d)
20
18	FERC Approved. Potential
		Potential 2021 FID
16	Next Wave Projects
	Projects
14			Golden Pass T1-T3
12			Sabine Pass T6
Under Construction		Calcasieu Pass
10	or In-Service		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	30

Natural Gas - 38% of U.S. Generation Mix

Growing Market Share in Power Gen.

• Gas power demand grew by 11 Bcf/d from 2010-2019, while coal declined 17 Bcf/d(a) and renewables grew 5.2 Bcf/d(a)

Market Share Growth Should Continue

• 18 Bcf/d of coal generation remains to be displaced, or ~23% of U.S. Power Generation Mix
• 53 GW of coal plant capacity retired from
  2013-2018, and another 48.2 GW of plant retirements have already been announced for 2019-2025
• • 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

U.S. Power Generation by Source(a)

40

35

38%

Equivalent	30											35%
				25%				33%	34%
							32%
	25
					30%	28%	28%
Day	20		23%	24%
	21%
per	15
Bcf													11%
	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	2019
			Coal	Gas	Nuclear	Hydro		Solar+Wind	Other

Announced Coal & Nuclear Reactor Retirements

(MW)Retirements	16,000						5.0	Displacement(Bcf/dequivalent)
14,000						4.5
	12,000						4.0
						3.5
	10,000						3.0
	8,000						2.5
	6,000						2.0
	4,000						1.5
						1.0
	2,000						0.5
	0						0.0
	2019	2020	2021	2022	2023	2024	2025
		Coal	Nuclear	Cumulative Displacement

Source: EIA. (a) Assumes 7x Heat Rate for gas equivalence	31

Natural Gas - Base Decline & Capital Discipline

Base Declines Offset Current Activity

U.S. Natural Gas Base Decline Rate

• Average U.S. decline rate of 26% equates to ~27 Bcf/d of new gas required each year to simply hold production flat
• With minimal industry completion activity expected at current strip U.S. natural gas supply should fall sharply by exit 2020 and through 2021

Producer Discipline Materially Impacts

Supply Forecast

• Industry spending being limited to cash flow in 2020 and beyond
• Consensus 4Q-4Q growth forecast now flat 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.)

Source: RS Energy

Associated Gas Decline & Demand Growth Results in Higher Call on Dry Gas Basins

32

L48 Dry Gas Production Has Declined Significantly

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

U.S. Natural Gas Production Has Declined Over 10% From 2019

98 Highs, Despite Return of Shut-In Production. Future Supply

96	Expected to Remain Low Due to Reduced Operator Activity.
94

92

90

88

86

84

82

80

78

76

74

72

70

68

1-Jan1-Feb1-Mar1-Apr1-May1-Jun1-Jul1-Aug1-Sep1-Oct1-Nov1-Dec

2016		2017		2018		2019		2020

Source: Bloomberg	33

Higher Prices Required to Meet Demand Growth

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

108
106
104
102
100
98
										~11
96											Bcf/d
94
92
90
88
2019	ResComm	Industrial	Electric	Mexico	LNG	2025	Associated	Haynesville	Call on
		Demand	& Other		Power	Exports	Exports	Demand	Gas	& Other	Appalachia

• Demand grows ~17 Bcf/d by 2025, driven by increased Mexico & LNG exports and power generation
• Permian was expected to grow ~1.5-2.0 Bcf/d per year with build out of new infrastructure, partially offset by declines in other oil basins in aggregate. This supply growth is now at risk due to low oil prices.
• Haynesville grows ~3 Bcf/d by 2025, partially offset by declines in conventional and offshore
• Result is a call on Appalachia natural gas of an additional 11 Bcf/d to meet new demand. This call on
  Appalachia becomes even greater if low oil prices persist.
• 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 pressures PE-backed private operators to preserve liquidity / generate free cash
• Early evidence of capital discipline by gas producers demonstrated by declining rig count due to low prices, even as U.S. natural gas supply has declined ~10% from its November 2019 highs

Source: EIA supply estimates from AEO 2020. Other supply represents legacy shale, conventional, offshore and imports.	34

NGL Macro Outlook

NGL Demand Growth

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

U.S. Export Bottleneck Relieved

• 2020 export capacity to increase by ~300 MBPD versus EIA gas plant propane and normal butane supply of 1,976 MBPD in May 2020
• U.S. waterborne export capacity increases equivalent to over 15% 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

NGL Supply to Decline in 2020+ with Decreasing U.S. Crude and Natural Gas Supply

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

2.25

2.00

1.75

1.50

1.25

1.00

0.75

0.50

0.25

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 Announcements

35

LPG Demand Absorbs Growing U.S. Exports

Global LPG Supply & Demand Waterfall (MBL/D)

11,400
11,200
11,000
10,800
10,600	~821
10,400	MBPD
10,200
10,000
9,800
9,600

2019 Demand ResCom + Industry	PDH	Ethylene	2024 Demand	Non-U.S. Supply Call on U.S. Supply
+Autogas + Other				(EIA)

• U.S. LPG Export Capacity expands 300 MBL/D by end of 2020
• Global LPG demand grew ~4.3% 2014-19. Demand forecast assumes 2020 is down ~1% y/y, and 2021-2024 growth of ~2.9%. New PDH/ethylene projects drive ~500 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 821 MBL/D 2020-24, versus consultant supply growth forecasts of ~11 MBL/D

Source: EIA, Energy Aspects, Genscape, IEA	36

Financial Detail

2020 Annual Guidance

	Prior Full-Year 2020	Updated Full-Year 2020
	Guidance	Guidance (a)
Production per Day	~2.3 Bcfe	~2.25 Bcfe
Capital Expenditures
Drilling & Completion	$400 Million	$400 Million
Land & Other	$30 Million	$30 Million
Cash Expense Guidance
Direct Operating Expense per mcfe	$0.14	- $0.16	$0.11 - $0.13
TGP&C Expense per mcfe	$1.37	- $1.40	$1.32 - $1.36
Production Tax Expense per mcfe	$0.04	- $0.05	$0.03 - $0.04
G&A Expense per mcfe	$0.14	- $0.16	$0.14 - $0.15
Exploration Expense	$30 - $38 million	$28 - $34 million
Interest Expense per mcfe	$0.22	- $0.24	$0.22 - $0.24
DD&A Expense per mcfe	$0.48	- $0.52	$0.48 - $0.52
Net Brokered Marketing Expense	$10 - $16 million	$10 - $16 million
Pricing Guidance
Natural Gas Differential to NYMEX	($0.20) - ($0.26)	($0.22) - ($0.28)
Natural Gas Liquids (b)	$0.50 to $1.50 per barrel	$0.50 to $1.50 per barrel
Oil/Condensate Differential to WTI	($8.00) - ($9.00)	($8.00) - ($10.00)

Guidance Update Summary

• ~10 to 12 cents per mcfe unit cost improvement due to continued Company-wide cost reductions and sale of North Louisiana
• Sold ~160 Mmcfe per day of production in August with NLA sale
• Minor changes to differentials guidance resulting from NLA sale (fewer Gulf Coast sales)

(a) Reflects impact of North Louisiana divestiture and other Company-wide cost reductions. (b) Represents differential to Mont Belvieu-equivalent	38
barrel, based on a weighting of 53% ethane, 27% propane, 7% normal butane, 4% iso-butane and 9% natural gasoline.

Well-Structured, Resilient Balance Sheet

• $3 billion elected borrowing base reaffirmed in March 2020
• $2.4 billion elected commitment
• Ample cushion on financial covenants
• • Interest coverage ratio(b) covenant of at least 2.5x
  • Current ratio(c) covenant of at least 1.0x
  • Asset coverage test(d) covenant of at least 1.5x
  • No Debt-to-EBITDA covenant

Debt / Proved Developed Reserves

($/mcfe)	$0.80
$0.70
Reserves
$0.60
Developed	$0.50
$0.30
Debt/ProvedNet	$0.40
$0.20
	$0.10
	$0.00

2016	2017	2018	2019
	RRC	Peer Average

Commitment to Absolute Debt Reduction & Improving Maturity Profile

					Year-End 2018
	$2,400
				Total Debt:
millions	$2,000			~$3.9 Billion
$1,600
$1,200				$929
$ in
$800					$749	$943		$750
				$498
	$400
	$0
	2020	2021	2022	2023	2023	2024	2025	2026	2027+
			Range Notes	Senior Secured Revolving Credit Facility

			2Q 2020(a)
	$2,400
		Total Debt:					$2.4 Billion Bank Commitment
	$2,000	~$3.0 Billion					Equates to Significant
millionsin$	$1,600						Liquidity of >$1.6 Billion(a)
$1,200						$750
	$800	$595	$662			$550

$400	$394
	$59
$0

2020 2021 2022 2023 2023 2024 2025 2026 2027+

Range Notes

Senior Secured Revolving Credit Facility

Note: Peers include AR, CHK, CNX, COG, EQT, GPOR and SWN. (a) As of 6/30/20, pro forma sale of North Louisiana (b) Excludes non-cash	39
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

Natural Gas & Oil/Condensate Hedges

As of 6/30/20	Time Period	Volumes Hedged	Average Hedge Prices
	Jul-Oct 2020 3-Way Collar	60,000	$1.75 / $2.00 x $2.53
	3Q	2020 Swaps	1,206,522	$2.58
Natural Gas1	4Q 2020 Swaps	1,087,147	$2.60
(Henry Hub)
$/Mmbtu	Apr-Oct 2021 Collars	60,000	$2.60 x $3.00
	2021	3-Way Collars	240,000	$1.99 / $2.33 x $2.60
	2021 Swaps	70,000	$2.61
Oil/Condensate2	3Q	2020 Swaps	8,000	$58.19
(WTI)	4Q	2020 Swaps	6,000	$58.02
$/Bbl	2021 Swaps	1,000	$55.00

1. Range sold natural gas call swaptions of 180,000 Mmbtu/d for calendar 2021 at an average strike price of $2.825 per Mmbtu. Range also sold 60,000 Mmbtu/d of 3Q20 $2.50 strike calls.
2. Range sold 500 bbls/d of 3Q20 $59.00 per barrel strike WTI calls, and call swaptions of 1,000 bbls/d for calendar 2021 at an average strike price of $55.00.

40

NGL Hedges

As of 6/30/20	Time Period	Volumes Hedged	Average Hedge Prices
C3 Propane	3Q 2020 Swaps	3,022 bbls	$0.470/gal
nC4 Butane1	3Q 2020 Swaps	2,500 bbls	$0.570/gal
C5 Natural Gasoline	3Q 2020 Swaps	1,674 bbls	$0.732/gal

1. Range sold nC4 butane calls of 2,500 bbls/d for 3Q20 at an average strike price of $0.57 per gallon.

41

Contact Information

Range Resources Corporation

100 Throckmorton St., Suite 1200

Fort Worth, Texas 76102

Laith Sando, Vice President - Investor Relations

1. 869-4267
   [e-mail]

John Durham, Senior Financial Analyst

1. 869-1538
   [e-mail]

www.rangeresources.com

42