Range Resources : Company Presentation – February 27, 2020

Company Presentation

February 27, 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 LDAR program

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

2019: A Focus on Performance

• Continued to Reduce Absolute Debt
• Executed $785 Million in Asset Sales
• Delivered on 2019 Production Target While Spending Under Budget for Second Consecutive Year
• Most Capital Efficient Operator in Appalachia(a)
• • 2019 D&C Capex of ~$292 per Mcfepd versus Appalachia peer average of ~$402 per Mcfepd
  • 2020 well costs improving to <$610 per foot, a ~15% improvement to 2019
• Improved Unit Costs
• • Cash unit costs in 4Q19 of $1.92/mcfe were $0.26, or ~12%, lower than prior year period
• Significantly Enhanced Liquidity Profile
• • Increased elected commitment from $2.0 billion to $2.4 billion
  • Improved liquidity by over $1 billion

(a) Calculated as D&C Capital Expenditures divided by Mcfe per day of Production. See slide 11 for details.	5

2020 Plans and Financial Positioning

• All-InCapital Budget of $520 Million
• Production Expected to Be Maintained at ~2.3 Bcfe per day
• Improve Capital Efficiency Through Continued Well Cost Reductions
• Year-End2020 In-Process Well Inventory Expected to Be the Same as Year-End 2019
• Enhance Margins Through Unit Cost Management & Marketing Strategies
• Strengthen Balance Sheet & Liquidity Profile
• • Additional asset sale processes remain underway
  • In January 2020, Range issued $550 million in 2026 senior unsecured notes in exchange for tendered 2021 and 2022 notes
  • $1.7 billion in available liquidity

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 extends 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 (b) As of YE2019. Does not	7
include over 18 Tcfe in proved reserves.

Multi-Decade Inventory of Capital Efficient Wells

= Existing Pad	Southwest Pennsylvania

(a) Assumes 10,000 ft. lateral

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 from returning to existing pads show no degradation in recoveries

8

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	9

Peer-Leading Capital Efficiency

Well Costs per Lateral Foot		2020 Decline Rate
$1,200	40%
$1,000	35%
	30%
$800	25%
$600	20%
$400	15%
	10%
$200	5%
$0	0%

RRC	Peer 1	Peer 2 Peer 3	Peer 4	Peer 5	Peer 6		RRC	Peer 2	Peer 1	Peer 4	Peer 3	Peer 5	Peer 6
D&C Capex per Mcfepd Reflects Relative Capital Efficiency
$700					2018 2019	2020	3-Year Average
$600
$500											$473
								$425
							$389
$400					$384	$387

$295	$310
$300
$200
$100

$0

RRC

Peer 4

Peer 1

Peer 2

Peer 6

Peer 3

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

Low Maintenance Capital Requirement

Starting production

assumed ~2.3 Bcfe/d

Production = ~92 Bcfe

<20% Base Decline

Ending production

of ~1.84 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 ~64 wells

64 wells x 1.44 Bcfe recovery = ~92 Bcfe

• ~64 wells x ~$6.5 average well cost = ~$415 million

~$415 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

~$475 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
• 2020 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 ~13% in 2019 versus 2018, with continued improvement expected in 2020
• Headcount reduced by ~18% in 2019 following asset sales and workforce assessment

LOE & Production Tax

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	2020 Guidance
		Midpoint

Cost per Mcfe

$0.23 $0.22 $0.21 $0.20 $0.19 $0.18 $0.17 $0.16 $0.15

2018	2019	2020 Guidance
		Midpoint

• LOE savings driven by:
• • Continued efficiency gains from Range's water management and recycling program
  • Divestment of higher cost legacy assets
  • Lowest cost assets becoming larger portion of corporate production mix
• Pennsylvania Impact Fees decline with low natural gas prices and longer production history

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

Startup of ME2 Capacity Enhances

Margins, but Transport Now

Accounted for as an Expense Versus

Net Price in 2019 (see slide 16)

4Q18	1Q19	2Q19	3Q19	4Q19	2020
					Guidance
	GP&T	Cash G&A	LOE	Production Taxes

Gathering, Processing & Transport Overview

2024E

(ZeroScenarioGrowth)

• GP&T declined $0.12/mcfe from 4Q18 to 4Q19 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

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

• International price arb remains above historical averages
• Range's differential to Mont Belvieu improved throughout 2019 with further price uplift expected in 2020

Range's Ability to Export Provides Price Diversity

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

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
$0.30
($ per	$0.25
$0.20
Arb
Propane	$0.15
International	$0.10
$0.05
	$0.00

-$0.05

Jan-18Apr-18Jul-18Oct-18Jan-19Apr-19Jul-19Oct-19Jan-20

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

15

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 ~23%

in Just Two Years, While

Additional Asset Sale

Processes Remain Underway

$2,800

$2,600

$2,400

YE17 Debt

Asset Sales

Free

Cash

Flow

(a)

Other

(b)

YE18 Debt

Asset Sales

Free

Cash

Flow

(a)

Other

(b)

YE19 Debt

…As Peers Have Consistently Outspent Cash Flow

Flow /	(a)
Cumulative Free(a)Cash	(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.	16
(b) Includes dividends, share repurchases, changes in working capital, and other non-recurring expenses.

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	17
Hydraulic Fracturing Operations"

Positioned Well for Low Commodity Prices

	$8,000			$7.6 Billion
	$7,000
	$6,000
	$5,000
Millions			>$4 Billion
$4,000		Max
$ in
		Conforming
	$3,000
			Borrowing Base
	$2,000
			Elected
	$1,000		Commitment
		$0.4 Billion
	$0
	Borrowings	Credit Facility	SEC PV-10

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 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
• Significant asset coverage - YE19 SEC PV-10 is ~3.2x elected commitment
• Revolver borrowings expected to be reduced via potential asset sales

Note: Revolver borrowings as of 12/31/19, pro forma recent notes and tender offerings. SEC PV-10 assumes $2.58/Mmbtu NYMEX natural gas and	18
$55.73/bbl WTI. Peers include AR, CNX, EQT, GPOR and SWN.

Appendix

19

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 Range estimates.	20
SWN estimates for 2018 represent Appalachia production and capital expenditures only.

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

Gas In Place

For All Zones

Upper

Devonian

Marcellus

Utica/Point

Pleasant

(a) Assumes stacked pay opportunities in Marcellus, Utica and Upper Devonian	21

Significant Utica Resource

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

▪ Range has drilled three Utica wells

▪ 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

22

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 / 1,000 ft. =		▪ D&C Cost / 1,000 ft. =		▪ D&C Cost / 1,000 ft. =
	$730					$630				$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	122	1,949	328		2	43	2,890		486		2		6,677
3	146	2,637	443		3	52	3,823		644		3		8,379
5	179	3,791	637		5	63	5,300		892		5		10,870
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 80% ethane	23
extraction.

Natural Gas &

NGL

Macro Outlook

24

Natural Gas Demand - Increases Through 2025

2020-25 Demand Outlook

• Total demand growth of +20 Bcf/d through 2025 from LNG and Mexican exports, industrial and electric power demand growth
• LNG feedgas capacity to increase in 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 ~25% 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 +3-4 Bcf/d likely to FID in 2020-21
• 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 ~18 Bcf/d by 2024

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

25					R+C		Other
				Industrial		Electric Power
					Mexico Exports	LNG Exports
20
15
10
5
0
		2014-19			2020-25
	U.S. LNG Export Terminal Capacity (Bcf/d)
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	25

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

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

• 23 Bcf/d of coal generation remains to be displaced, or ~25% of U.S. Power Generation Mix
• 53 GW of coal plant capacity retired from
  2013-2018, and another 40 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
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
	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. (a) Assumes 7x Heat Rate for gas equivalence	26

LNG Growth Expected to Continue

22 20 18 16 14 12 10 8 6 4 2 0

12/16

FERC Approved and/or >70% long-termofftake signed. Potential Next Wave Projects.

Under Construction
	or In-Service
				Freeport T1-T3
				Cameron T1-T3
			Corpus Christi T1-T2
				Cove Point	Elba Island
			Sabine Pass T1-T5
12/17	12/18	12/19	12/20	12/21	12/22	12/23

Port Arthur

Magnolia LNG

Freeport T4

Cameron T4-T5

Golden Pass T1-T3

Sabine Pass T6

Calcasieu Pass

Corpus Christi T3

12/24

Source: Operator Estimates	27

Natural Gas - 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 2020 and beyond
• Consensus 4Q-4Q growth forecast now just ~1% (0.2 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

28

L48 Dry Gas Production Growth Slowing

98

96

94

92

90

88

86

84

82

80

78

76

74

72

70

68

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

U.S. Natural Gas Production Has

Declined ~5% From 2019 Highs

1/1

2/1

3/1

4/1

5/1

6/1

7/1

8/1

9/1

10/1

11/1

12/1

2016

2017

2018

2019

2020

Source: Bloomberg	29

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

30

Higher Prices Required to Meet Demand Growth

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

112 110 108 106 104 102 100 98 96 94 92 90 88 86

13-14 Bcf/d

2019	RC, Industrial	Electric	Mexico	LNG	2025	Associated	Haynesville	Call on
Demand	& Other	Power	Exports	Exports	Demand	Gas	& Other	Appalachia

• Demand grows ~20 Bcf/d by 2025, driven by increased Mexico & LNG exports and power generation
• Permian grows by ~1.5-2.0 Bcf/d per year with build out of new infrastructure, partially offset by declines in other shale oil basins in aggregate
• 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 13-14 Bcf/d to meet new 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 pressures PE-back private operators to preserve liquidity / generate free cash
• Early evidence?
• • Declining Appalachia rig count in response to prices
  • U.S. natural gas production has declined ~5% from 2019 high

Source: EIA supply estimates from AEO 2020. Other supply represents legacy shale, conventional, offshore and imports.	31

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
• Relative economics support use of LPG over naphtha for international steam crackers

U.S. Export Bottleneck Relieved

• 2020 export capacity to increase by ~450 MBPD and by ~260 MBPD in 2021 versus EIA gas plant LPG supply of 2,138 MBPD in November 2019
• U.S. waterborne export capacity increases equivalent to over 30% of U.S. LPG supply, which should tighten balances going forward
• Local Northeast propane differentials have narrowed since start up of Mariner East 2

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

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 Announcements

32

LPG Demand Absorbs Growing U.S. Exports

Global LPG Supply & Demand Waterfall (MBL/D)

11,200

11,000

10,800

10,600

10,400

10,200~1.2

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 expands 710 MBL/D (~40%) by end 2021.
• Global LPG demand grew ~4.3% 2014-19, and is forecast to grow ~3.1% 2019-23, driven by ~600 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 715 MBL/D 2020-23, versus consultant supply growth forecasts of ~480 MLB/D.

Source: EIA, Energy Aspects, Genscape, IEA	33

Financial

Detail

34

2020 Annual Guidance

	Full-Year 2020
Production (Bcfe per day)	~2.3
Capital Expenditures
Drilling & Completion	$490 Million
Land & Other	$30 Million
Cash Expense Guidance
Direct Operating Expense per mcfe	$0.14	- $0.16
TGP&C Expense per mcfe	$1.40	- $1.45
Production Tax Expense per mcfe	$0.04	- $0.05
G&A Expense per mcfe	$0.14	- $0.16
Exploration Expense	$30 - $38 million
Interest Expense per mcfe	$0.22	- $0.24
DD&A Expense per mcfe	$0.48	- $0.52
Net Brokered Marketing Expense	$10 - $16 million
Pricing Guidance
Natural Gas Differential to NYMEX	($0.20)	- ($0.26)
Natural Gas Liquids (a)	Mont Belvieu plus $0.50 to $1.50 per barrel
Oil/Condensate Differential to WTI	($7.00)	- ($8.00)
(a) Weighting based on 53% ethane, 27% propane, 7% normal butane, 4% iso-butane and 9% natural gasoline	35

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
• • Interest coverage ratio(b) of ~4.9x versus covenant of at least 2.5x
  • Current ratio(c) of ~4.6x versus covenant of at least 1.0x
  • Asset coverage test(d) of ~2.8x versus covenant of at least 1.5x

Capital Structure(a)

(millions)		4Q19
Bank Debt	$ 450
Senior Notes	2,725
Senior Sub Notes	49
Debt	3,224

Debt / Proved Developed Reserves

	($/mcfe)	$0.90
	$0.80
	Reserves	$0.70
	$0.60
	Developed
	$0.50
	Debt/Proved	$0.40
	$0.10
		$0.30
		$0.20
	Net	$0.00
				2013	2014	2015		2016	2017	2018	2019
							RRC			Peer Average
				Debt Maturity Schedule(a)
	$3,000		$3 Billion Borrowing Base
										Significant Liquidity
	$2,500		$2.4 Billion Bank Commitment							Potential of ~$2.3 Billion
Millionsin$	$2,000
$1,500
	$1,000					$653	$749								$750
									$450					$550
		$500				$72
		$-
		2019	2020	2021	2022	2023	2023	2024	2025	2026
				Range Notes	Senior Secured Revolving Credit Facility
Interest Rate			5.75%	5.2%(e)	5.0%								4.875%	9.25%

Note: Peers include AR, CHK, CNX, COG, EQT, GPOR and SWN. (a) As of 12/31/19, pro forma notes and tender offerings (b) Excludes non-cash interest	36
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) Weighted-average interest rate of 2022 notes

Hedging Status

As of 12/31/19	Time Period	Volumes Hedged	Average Hedge Prices
	1Q20 Swaps	1,007,253	$2.68
Natural Gas1	2Q20 Swaps	1,010,000	$2.62
3Q20 Swaps	1,010,000	$2.62
(Henry Hub)
$/Mmbtu	4Q20 Swaps	976,848	$2.63
	FY21 Swaps	50,000	$2.62
	1Q20 Swaps	9,000	$58.62
Oil/Condensate2	2Q20 Swaps	9,000	$58.18
(WTI)	3Q20 Swaps	8,500	$58.15
$/Bbl	4Q20 Swaps	5,500	$58.00
	FY21 Swaps	1,000	$55.00
NGLs (Non-TET) - $/Gal
Normal Butane (NC4)	1Q20 Swaps	659	$0.730
Natural Gasoline (C5)	1Q20 Swaps	4,297	$1.208

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.
2. Range sold WTI calls of 500 Bbl/d for 2Q20-3Q20 at strike prices of $59. Range also sold WTI call swaptions of 3,000 Bbl/d for calendar 2021 at an average strike price of $56.50

37

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

38