Roan Resources Investment Update July 2018 Important Disclosures - - PowerPoint PPT Presentation

Roan Resources Investment Update July 2018

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Important Disclosures

Forward-Looking Statements and Risk Factors Statements made in this presentation that are not historical facts are “forward-looking statements.” These statements are based on certain assumptions and expectations made by Linn Energy, Inc. (“LNGG”) which reflect management’s experience, estimates and perception of historical trends, current conditions, and anticipated future developments. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of LNGG, which may cause actual results to differ materially from those implied or anticipated in the forward-looking statements. These include risks relating to financial and operational performance and results of LNGG, timing of and ability to execute planned separation transactions and asset sales, continued low or further declining commodity prices and demand for oil, natural gas and natural gas liquids, ability to hedge future production, ability to replace reserves and efficiently develop current reserves, the capacity and utilization of midstream facilities, the regulatory environment, the uncertainty inherent in estimating reserves and in projecting future rates of production, the production potential of our undeveloped acreage, cash flow and access to capital and the timing of development expenditures. These and other important factors could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. Please read “Risk Factors” in LNGG’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and other public filings. LNGG undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information or future events. No Offer or Solicitation This communication is for informational purposes only and shall not constitute an offer to sell or the solicitation of an offer to buy any securities of LNGG or Riviera Resources, LLC (“RVRA”) or otherwise, nor shall there be any sale of securities in any jurisdiction in which the offer, solicitation or sale would be unlawful prior to the registration or qualification under the securities laws of any such jurisdiction. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended. Important Additional Information In connection with the proposed spinoff transaction between LNGG and RVRA, RVRA has filed a registration statement on Form S-1 containing a prospectus with the SEC. This communication is not a substitute for any documents that LNGG may file with the SEC or send to LNGG shareholders in connection with the spinoff transaction. SHAREHOLDERS OF LNGG ARE URGED TO READ ALL RELEVANT DOCUMENTS FILED WITH THE SEC, BECAUSE THEY CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. When available, investors and security holders will be able to obtain copies of the documents that may be filed with the SEC with respect to the proposed transaction free of charge at the SEC’s website, http://www.sec.gov, or as described in the following paragraph. The documents filed with the SEC by LNGG may be obtained free of charge at the applicable website (www.linnenergy.com) or by requesting them by mail at Linn Energy, Inc., 600 Travis, Suite 1400, Houston, TX 77002, Attention: Investor Relations, or by telephone at (281) 840-4110.

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Important Disclosures

Reserve Estimates The SEC permits oil and natural gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms. LNGG may use terms in this presentation that the SEC’s guidelines strictly prohibit in SEC filings, such as “estimated ultimate recovery” or “EUR,” “resources,” “net resources,” “total resource potential” and similar terms to estimate oil and natural gas that may ultimately be recovered. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves as used in SEC filings and, accordingly, are subject to substantially greater uncertainty of being actually

• realized. These estimates have not been fully risked by management. Actual quantities that may be ultimately recovered will likely differ

substantially from these estimates. Factors affecting ultimate recovery include the scope of Roan Resources LLC’s (“Roan”) actual drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, field spacing rules, actual drilling results and recoveries of oil and natural gas in place, and other factors. These estimates may change significantly as the development of properties provides additional data. Non-GAAP Measures Adjusted EBITDAX and Net Debt are financial measures not presented in accordance with generally accepted accounting principles in the United States (“GAAP”). Reconciliations of these non-GAAP financial measures to the most directly comparable GAAP measures can be found in the appendix to this presentation. Industry and Market Data This presentation has been prepared by LNGG and includes market data and other statistical information from sources believed by LNGG to be reliable, including independent industry publications, government publications or other published independent sources. Some data is also based on LNGG’s good faith estimates, which are derived from its review of internal sources as well as the independent sources described above. Although LNGG believes these sources are reliable, they have not independently verified the information and cannot guarantee its accuracy and completeness.

3

Spin Transaction Update

Anticipated Separation Into Two Public Companies August 7th

• LNGG is separating into two stand-alone, publicly traded companies:
• LNGG, which will initially hold 50% of Roan
• RVRA will hold mature low decline producing assets in Hugoton, Michigan, and

Drunkards Wash, emerging high growth assets in Arkoma, East Texas, North Louisiana, and NW STACK, in addition to significant midstream assets with Blue Mountain Midstream LLC, a rapidly expanding midstream business centered in the core of the Merge

• LNGG shareholders on record date will receive 1 share of RVRA common stock for each

share of LNGG common stock

• Working closely with our 50% ownership partner, Roan Holdings LLC, on definitive

documentation to consolidate 100% of Roan’s equity interest under LNGG

• Post consolidation, LNGG intends to uplist its common stock to NASDAQ or NYSE in

2018 and change from LNGG to ticker “ROAN”

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Separation Overview

LINN Energy, Inc. 50% equity interest Riviera Resources, Inc. Riviera Upstream Assets Blue Mountain Midstream LLC Roan Holdings, LLC 50% equity interest Roan Resources LLC LNGG shareholders

Distribution of Riviera Resources stock

Distribution of 1 share of RVRA for each share of LNGG

LINN Energy, Inc. 50% equity interest Riviera Resources, Inc. Riviera Upstream Assets Blue Mountain Midstream LLC Roan Holdings, LLC 50% equity interest Roan Resources LLC LNGG shareholders RVRA Share LNGG Share

Immediately following Spinoff Transaction

LNGG shareholders on record date will receive 1 share of RVRA common stock for each share of LNGG common stock

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Strong Offset Activity and Well Results Demonstrates Asset Quality

Alta Mesa STACK Oil Window Meramec / Osage EOG Eastern Anadarko Woodford Oil Window “High-Return Premium Play in Crude Oil Window” GPOR SCOOP Woodford / Sycamore / Springer MRO STACK / Meramec “Consistent

• utperformance
• f STACK volatile
• il wells”

XEC Lone Rock Play “Best Results to Date” CLR SCOOP Springer CLR SCOOP Woodford/Sycamore

Roan’s Investment Thesis

• Only pure play operator with large scale, contiguous acreage

position in the oil window of the Merge/SCOOP/STACK

• Second most active basin in lower 48 based on rig count
• Multiple decades of inventory of high rate-of-return locations
• Development opportunities with:
• Rate of return (ROR)(1) of ~75% to +100%
• Present value index (PVI)(1) of over 2.0x
• 13 to 18 month payback period(1) per well
• 4.9x recycle ratio(2)
• Competitive with Tier 1 Permian plays
• Strong historic well results with expectation of substantial

rate-of-change improvements driven by experienced management team

• WTI pricing and ample processing and takeaway capacity
• Robust production growth plus line of sight to free cash flow

generation

• Well-capitalized balance sheet with significant financial

flexibility

• Deeply analytical and experienced operations team with

significant history running large scale assets in the Mid- Continent

Roan acreage

1) PVI, ROR, and payback period are based on $65 WTI and $2.75 HH; please see slide 20 for information on the related type curves 2) Please see slide 13 for recycle ratio calculation

Acreage Position

(Net Acres)

Merge 117,000 SCOOP 29,000 STACK 8,000 Total 154,000

Merge

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Roan Production

20.1 22.9 25.7 37.7 45.0 61.0 94.0 44% 46% 50% 56% 54% 61% 62%

• 5%

5% 15% 25% 35% 45% 55% 65% 20 40 60 80 100 120 2Q'17 3Q'17 4Q'17 1Q'18 Current rate Exit rate 2018 Exit rate 2019 % Liquids MBoe/d Net Production % Liquids

~365% projected growth from 2Q’17 to Dec’19

» »

Production History and Guidance:

(1) (1) 1) Based on the midpoint of guidance

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Roan Financial Overview

Key Metrics / Guidance

1Q’18 Adjusted EBITDAX(1) ($MM) $74 1Q’18 Net Debt(1) ($MM) $204 Current DUC count(2) 13 Current Rig Count(2) 7 YE’18 Rig Count 8 2018 Estimated Production (MBoe/d) 43 – 46 2018 Adjusted EBITDAX(1)(3) $340 - $370 2019 Estimated Production (MBoe/d) 72 – 83 2019 Adjusted EBITDAX(1)(3) $625- $725

1) Adjusted EBITDAX and Net Debt are non-GAAP measures, please see slide 34 for a reconciliation of these measures to the most directly comparable GAAP measure. Projected 2018 and 2019 Adjusted EBITDAX is not reconcilable at this time. 2) As of July 2018 3) Represents unhedged Adjusted EBITDAX based on $65 WTI and $2.75 HH flat pricing

8

Unique Investment Opportunity

1) Source: FactSet and public filings. Market data as of 7/20/2018. Publicly Traded U.S. E&P Universe filtered for companies with Enterprise Values >$500mm and that trade on the NYSE or NASDAQ.

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Roan Management Team & Initial Board

 Mr. Maranto has 35 years of industry experience, with 21 years at EOG Resources, where he served as Vice President of its Mid-Continent division for more than a decade  He earned his Masters of Business Administration from Centenary College and a Bachelor of Science in Petroleum Engineering from Louisiana Tech University

Tony Maranto

President, CEO and Director

Greg Condray

EVP – Geoscience & Business Development

Joel Pettit

EVP – Operations and Marketing

David Edwards

Chief Financial Officer  Mr. Condray has 22 years of industry experience and previously served as Exploration Manager in the Mid-Con division of EOG Resources  Prior to that, he served as Geoscience Manager for Chesapeake Energy Corporation, where he was responsible for the identification and development of the Haynesville, Eagleford and Powder River Basin assets  Mr. Condray earned a Master of Science and Bachelor of Science in Geology from University of Alabama  Mr. Pettit has more than 35 years of industry experience, employed with Pennzoil for 22 years  Previously, he served as Operations Manager in the Mid-Continent and Permian Divisions for EOG Resources  Mr. Pettit earned a Bachelor of Science in Petroleum Engineering from Mississippi State University  Mr. Edwards was the former CFO for Tapstone Energy since 2014  Prior experience includes various roles in Corporate Finance at Sandridge Energy and Equity Research at UBS, with a focus on the Energy sector  Mr. Edwards holds a Bachelor of Science degree in Applied Mathematics from Brown University

Board of Directors

Matthew Bonanno

Member of LNGG Board of Directors York Capital Management

Mark Ellis

Member of LNGG Board of Directors

Evan Lederman

Chairman of LNGG Board of Directors Fir Tree Partners

John Lovoi

JVL Partners

Paul B. Loyd Jr.

JVL Partners

Tony Maranto

President and CEO, Roan Resources

Michael Raleigh

JVL Partners

Andy Taylor

Member of LNGG Board of Directors Elliott Management Corporation

James Woods

Vice President of Land, Citizen Energy III

Top-Tier, Handpicked Management Team with Expertise in Mid-Continent

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Roan Investment Highlights

 154,000 net acres located in the Merge, SCOOP and STACK plays in Central Oklahoma  Over 110 operated horizontal wells developed as of July 2018, ranking Roan as the dominant developer and producer in the Merge play  Stacked pay with multiple well-developed, benches with superior reservoir characteristics  Roan has a ~76% average working interest throughout its Merge acreage that is ~80% held by production (HBP’d), allowing for optimal full- field development with decades of high quality inventory  Oil sales price off WTI at Cushing with all-in differential of less than $1.50 per barrel Pure Play Merge / SCOOP / STACK Operator Rate-of-Change Improvements in Development Program Ample Organic Growth Potential, Supported by Large Base Production Best in Class Financial Flexibility Experienced Management Team  Merge play offers single well ROR(2) of ~75% to +100%, superior to SCOOP / STACK and competitive to Tier 1 Permian economics  Corporate recycle ratio(1) 4.9x; development opportunities with PVI(2) of over 2.0x and an average payback(2) of 13 to 18 months per well  Base cash flows, high growth potential and capital efficiency position Roan for line of sight to free cash flow by 1H 2020  Attractive baseline well results established through horizontal development activity by Citizen and LNGG  Roan’s subsurface and exploration team leverage in-basin experience and significant well control to produce differentiated development model  Roan operations team technical approach and experience offers potential for significant improvements in development program results – Advances in lateral targeting, drilling times and cost initiatives already evident in results  Substantial growth opportunities, with 7 rigs currently and increasing to 8 rigs by YE’18 – 2018 to 2019 projected to deliver YoY production growth of ~75%  Development program de-risked through over 110 operated wells and over 225 non-operated wells  Sizable current base production of ~45 MBoe/d  Well-capitalized balance sheet with high cash flowing asset base; LQA Leverage of 0.7x at 1Q'18  $204MM of Net Debt(3) at 1Q’18 (all debt held in the credit facility); current borrowing base of $425MM implied available liquidity of >$200MM at 1Q'18  Led by Tony Maranto, Roan’s technical teams have extensive Merge experience and were integral in building EOG’s current Mid-Con position  Executive leadership has over 100 years of combined experience from EOG and other top tier operators

1) Please see slide 13 for how recycle ratio is calculated 2) ROR, PVI and payback period are based on $65 WTI and $2.75 HH; please see slide 20 for information on the related type curves 3) Adjusted EBITDAX and Net Debt are non-GAAP measures, please see slide 34 for a reconciliation of these measures to the most directly comparable GAAP measure

Top-Tier Capital Efficiency

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Roan’s Core Business Strategy

• Maximize value across Roan’s asset base
• Applying best-in-class practices in the development of our resources based on EOG pedigree and

experience

• Continual pursuit of improvements to operations
• Maintain well-capitalized balance sheet and financial flexibility
• Continual focus on credit profile; including line of sight to grow substantially within cash flow
• Consistently evaluate and position for the proper application of risk in our business strategy
• Recruit and maintain top-tier employee base
• Provide challenging, stimulating and supportive experience for motivated individuals
• Selectively pursue opportunities to expand the asset base through leasing and acquisitions
• Seek expansion of the asset base only where a strategic advantage and accretive valuation is identified

To be the best-in-class disciplined operator of unconventional resources

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Introduction to the Merge

Merge Overview:

• The main target zones in the Merge are the

Woodford and Mayes (Sycamore)

• The Woodford is between 75 and 175+ feet thick in

the Merge and historically was the main horizontal target in the SCOOP

• The Mayes is between 40 and 250+ feet thick and

has emerged as a viable, repeatable target zone Stratigraphic Cross Section Schematic

A A A’ A’

Roan acreage

Merge Highlights: Merge SCOOP STACK

Porosity

4% - 10% 4% - 8% 3% - 8%

Gross Thickness (ft)

70 - 400+ 125 - 400 100 - 500

Net to Gross

40% - 80% 50% - 80% 30% - 50%

Primary Target

Mayes / Woodford Woodford Meramec

Merge

13

Roan Economics Best in Class

74% 65% 63% 55% 54% 41% 41% 23%

0% 20% 40% 60% 80% 100% ROR(1) @ $55 WTI / $3 HH

1) Source: RS Energy Group for economics other than Roan. Merge RORs based on type curves from Roan’s YE’17 reserve report prepared by D&M, please see slide 20 for more detail. 2) Peers include AMR, CDEV, COG, CPE, CXO, FANG, JAG, LPI, MTDR, NFX, PE, PXD, XEC sourced from public filings; Recycle ratio is calculated as: (1Q’18 unhedged adjusted EBITDAX / 1Q’18 production)/(YE’17 proved undeveloped capital cost / undeveloped net reserves); Sourced from public filings.

23% ROR 63% ROR 41% ROR 4.9x 4.6x 4.2x 4.2x 3.2x 3.1x 2.6x 2.5x 2.4x 2.0x 2.0x 1.9x 1.7x 1.5x 1 2 3 4 5

ROR(1) @ $55 WTI / $3 HH Peer Recycle Ratio(2) Comparison

Highly competitive well level returns Drive peer-leading corporate capital efficiency

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Roan’s Premier Merge Acreage Position

• Multiple stacked drilling targets throughout acreage

position

• Vast majority of acreage in high-return oil window
• Significant thickness of Woodford with superior reservoir

properties

• Multiple well-developed benches in the Mayes with great

porosity and permeability

• Mayes play de-risked by historic vertical production
• Pore pressure gradients ranging from 0.45 – 0.52 psi/ft

through core area

• Shallower depths reduce drilling costs
• High-quality leasehold, characterized as contiguous

acreage with high working interest and predominantly HBP’d

Woodford Oil Gravity Map

API Oil:

Roan acreage

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Roan’s Premier Merge Acreage Position Continued

• Significant operational control through the

high-return oil window

• ~175 operated sections in the Merge are in

the oil and liquids-rich windows (~90% of acreage)

• Operated acreage position largely HBP’d
• Development program not dictated by need

to hold acreage

• Contiguous acreage throughout leasehold
• Optimal for pad development and efficient

surface operations

• Demonstrated ability to capture operations

Merge SCOOP STACK Total Operated Sections(1) 206 37 12 255 HBP’d Operated Sections ~80% ~70% ~90% ~80%

1) Operation control assumed if leasehold exceeds 240 acres in a section and 1-mile units

Woodford Oil Gravity Map

API Oil:

Roan acreage

STACK Merge SCOOP

16

Roan’s De-Risked Inventory

1) Includes all operated sections in Merge; 206 operated sections for Mississippian and 197 operated sections for Woodford. Operation control assumed if leasehold exceeds 240 acres in a section and 1-mile units 2) Assumes 16 wells per rig per year 3) Theoretical density diagram not depicted to scale or to reflect current or future density tests

Mayes (Sycamore) Woodford

Theoretical Merge Density Test(3) Roan has a deep inventory to be developed

• Merge operated gross locations(1) at different well

assumptions

• 12 wells per section = 2,418 gross operated

locations

• 16 wells per section = 3,224 gross operated

locations

• 20 wells per section = 4,030 gross operated

locations

• Operated gross locations will take 15 to 25 years to

develop with 10 rigs(2)

Merge density tests underway

• Currently testing 880’ spacing in the Woodford
• Multiple pattern tests planned:
• Testing up to 8 wells per unit in the Woodford
• Testing up to 6 wells per unit in the Mayes

SCOOP / STACK acreage offer additional development horizons

Base case development wells Upside development wells

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Key Merge Well Results

Collins 11-2-9-5 1XH IP-30: 3,492 Boe/d Oil: 52%; Liquids: 73% LL / Zone: 9,500’; Mayes

• IP-30 rates for Roan wells are on a 3-stream, peak rolling 30-day basis; other operator wells are on a 3-stream basis and assume a shrink of 0.8 and yield of 68 Bbl/MMcf; all wells assume a 6:1 Bbl:MMcf ratio

Collins 10-3-9-5 1XH IP-30: 3,218 Boe/d Oil: 61%; Liquids: 78% LL / Zone: 10,100’; Mayes Leon 1H-2-35 IP-30: 2,624 Boe/d Oil: 37%; Liquids: 64% LL / Zone: 10,070’; Mayes Gene Carroll 1H-18 IP-30: 2,537 Boe/d Oil: 17%; Liquids: 53% LL / Zone: 4,925’; Mayes Griffin 26-23-10-5 1XH IP-30: 2,476 Boe/d Oil: 63%; Liquids: 81% LL / Zone: 6,500’; Woodford Hinparr 31-6-10-5 1XH IP-30: 2,441 Boe/d Oil: 65%; Liquids: 81% LL / Zone: 9,900’; Mayes Govenor James B Edwards 1H-32 IP-30: 2,143 Boe/d Oil: 65%; Liquids: 81% LL / Zone: 4,960’; Mayes Renbarger 2H-26-23 IP-30: 1,978 Boe/d Oil: 32%; Liquids: 61% LL / Zone: 10,250’; Mayes Dutch 1H-33-28 IP-30: 1,918 Boe/d Oil: 41%; Liquids: 67% LL / Zone: 9,700’; Woodford Paxton1H-30-19 IP-30: 1,774 Boe/d Oil: 29%; Liquids: 60% LL / Zone: 10,175’; Woodford Spectacular Bid 18-11-6 2H IP-30: 1,728 Boe/d Oil: 55%; Liquids: 75% LL / Zone: 4,915’; Mayes Meyers 1H-2821X (XEC) IP-30: 2,586 Boe/d Oil: 24% LL / Zone: 7,980’; Woodford Dutch 1H-4-9 IP-30: 1,360 Boe/d Oil: 40%; Liquids: 66% LL / Zone: 7,475’; Woodford Barbour 1-10-7 1H IP-30: 1,487 Boe/d Oil: 34%; Liquids:56% LL / Zone: 4,960’; Mayes Frank Eaton 36-1-11-6 1XH IP-30: 954 Boe/d Oil: 60%; Liquids: 79% LL / Zone: 10,170’; Woodford Curry 21X-1VH (EOG) IP-30: 1,762 Boe/d Oil: 91% LL / Zone: 10,600’; Woodford Bomhoff 1H 20-12-7 (JONE) IP-30: 846 Boe/d Oil: 32% LL / Zone: 4,195’; Woodford Bomhoff 2H 20-12-7 (JONE) IP-30: 1,510 Boe/d Oil: 41% LL / Zone: 4,425’; Mayes Umbach Estate 1H-28-21 (TPR) IP-30: 1,101 Boe/d Oil: 63% LL / Zone: 6,675’; Mayes Roan Operated Mayes Non-Operated Mayes Roan Operated Woodford Non-Operated Woodford

18

Key SCOOP Non-Operated Well Results

Silver Stratton 1-6-31-XH (CLR) IP-30: 2,431 Boe/d Oil:35% LL / Zone: 10,040’; Woodford

• Peak rolling 30-day rates for other operator wells are on a 3-stream basis; all wells assume a 6:1 Boe ratio

Ernsteen 2-21X28H (GPOR) IP-30: 2,128 Boe/d Oil: 24% LL / Zone: 7,600’; Woodford Fowler 4N6W 3-9X16H (GPOR) IP-30: 3,061 Boe/d Oil: 4% LL / Zone: 8,750’; Woodford Triple H 5-30-31HS (CLR) IP-30: 2,344 Boe/d Oil: 88% LL / Zone:10,200’; Springer Pudge 1-7-6XH (CLR) IP-30: 2,419 Boe/d Oil: 4% LL / Zone: 7,500’; Woodford Ernsteen 1-21X28H (GPOR) IP-30: 2,264 Boe/d Oil: 22% LL / Zone: 7,600’; Woodford Bragg 3-35X02H (GPOR) IP-30: 3,200 Boe/d Oil: 1% LL / Zone: 9,600’; Woodford Harper Thomas 1-19H (Unit) IP-30: 2,416 Boe/d Oil: 87% LL / Zone: 5,140’; Hoxbar Pauline 6-27X22H (GPOR) IP-30: 3,663 Boe/d Oil: 24% LL / Zone: 7,625’; Woodford Triple H 3-30-31HS (CLR) IP-30: 2,629 Boe/d Oil: 86% LL / Zone: 10,200’; Springer Triple H 4-30-31HS (CLR) IP-30: 2,418 Boe/d Oil: 88% LL / Zone: 10,200’; Springer Rowell 1-1-12XH (CLR) IP-30: 2,558 Boe/d Oil: 1% LL / Zone: 5,400’; Woodford Triple H 2-30-31HS (CLR) IP-30: 3,537 Boe/d Oil: 85% LL / Zone: 9,900’; Springer Non-Operated Springer/Hoxbar Non-Operated Woodford

19

Industry Activity Gravitating to the Merge / SCOOP

Horizontal Drilling Permits in the Merge(2)

1) Source: Drilling Info as of July 2018 2) Source: IHS; 2018 YTD is as of July 2018

15 93 69 11 20 35 20 3 56

14 61 136 125

2015 2016 2017 2018 YTD Other Operators LNGG Citizen Roan

Merge / SCOOP Rig Activity(1) Active Rigs by Operator in Merge / SCOOP(1)

8 7 3 3 3 2 2 2 2 2 1 1 1 1 1 1 2 4 6 8 10

Peer Rigs Roan Acreage Roan Rigs

• 20,000

40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000

• 30

60 90 120 150 180

Cumulative production (Boe) Days on production

• 20,000

40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000

• 30

60 90 120 150 180

Cumulative production (Boe) Days on production 20

Roan’s Type Curve Economics

• Avg. Roan 2018 Mayes Oil Well Performance(1) vs. YE’17 Mayes Oil Curve(1)

1) Normalized to 10,000’ lateral on a 20:1 Bbl/MMcf; oil curve is average of 1,700, 3,000 and 4,800 GOR curves from the YE’17 reserve report prepared by D&M. 2018 wells represent well developed by Roan and include those that correspond to the represented type curve area and came to first sales in 2018. Wells that had been materially impacted by midstream limitations are excluded from the averages

• Avg. 2018 Mayes wells

YE’17 curve

YE’17 Mayes Oil Curve(1) Overview

YE’17 Mayes Oil Curve

IP 30 EUR Mix $65 WTI / $2.75HH Oil Gas NGL Oil Total Liquids AFE

($MM)

ROR Payout period (months) PVI 1,075 3,130 290 31% 56% ~$8.5 +100% 13 2.06

YE’17 Woodford Oil Curve IP 30 EUR Mix $65 WTI / $2.75HH

Oil Gas NGL Oil Total Liquids AFE

($MM)

ROR Payout period (months) PVI 545 1,350 125 53% 70% ~$8.5 75% 18 2.14

• Avg. Roan 2018 Wdfd Oil Well Performance(1) vs. YE’17 Wdfd Oil Curve(1)
• Avg. 2018 Woodford wells

YE’17 curve

YE’17 Woodford Oil Curve(1) Overview

21

Operational Advancements: Targeting

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97 101 105 109 113 117 121

% In Target Zone Wells

LNGG/Citizen Wells (2015-2017) Roan Wells (1H 2018)

Geosteering Comparison

Roan Average 95% Citizen / LNGG Average 58%

Lateral targeting has improved dramatically since the Roan team assumed operations Advantages to successful targeting

• Optimizes drilling performance
• Improved hydraulic stimulation

performance

• Maximizes well productivity

43 operated gross drilled wells in 1H 2018

• 24 wells producing(1)
• 6 wells completing
• 13 DUCs

1) Some wells have been temporarily shut in for midstream constraints or for fracking offset wells

22

Targeting Results and Subsurface Data Advancements

10 20 30 40 50 60 70 80 90 10 20 30 40

Cumulative MBoe Days on Production 10,000' Normalized Cumulative MBoe

OPPEL 1H-16-21 - WDFD DUTCH 1H-33-28 - WDFD

+85% in 45 days

Well Treated Lateral Length % in Optimal Zone Oppel 1H-16-21 (pre 2018) 9,851 66% Dutch 1H-33-28 (Roan operated) 9,708 99% Oppel (Woodford) Dutch (Woodford)

Advantages of Successful Targeting Evident in Well Results 3D Seismic Overview Since assuming operations, Roan has significantly expanded 3D seismic coverage

• Benefits of expanded coverage include:
• Improved lateral targeting
• Improved identification of key

structural features

• Implementation of seismic attributes

in reservoir quality evaluation

• Geohazard avoidance

2016 2017 2018 Roan LAS (# of wells) 2,500 2,500 30,000 Raster (# of wells) 1,230 8,330 56,000 3D Square Miles 250 ~315 ~800

Evolution of Subsurface Data

Since taking over drilling

• perations in January, Roan has

improved program average drill times by ~35%+

• Improvements have been

achieved by:

• Cohesive drilling team with

proven performance driven track record

• Proprietary mud program
• Utilization and optimization of

high performance motors

• Contracting higher performance

rigs

• Aggressive parameter
• ptimization

Current records indicate further improvements to come:

• Record 1-mile Woodford lateral

drilled in 8.6 days

• Record 2-mile Woodford lateral

drilled in 11.7 days

23

Operational Advancements: Drill Times

Drill Time Comparison: Spud to Total Depth(1)

1) Data is based on 76 LNGG / Citizen wells and 33 Roan wells. Wells with completed lateral lengths less than 6,500’ are designated 1 mile wells; wells with completed lateral lengths greater than 9,000’ are designated as 2 mile wells; spud is drill out of surface casing

23.3 22.0 27.3 30.0 14.1 12.7 18.1 16.9 5 10 15 20 25 30 35 1-Mile Mississippian 1-Mile Woodford 2-Mile Mississippian 2-Mile Woodford Days LNGG / Citizen Roan

24

The Roan Mid-Continent Advantage

Mid-Continent vs Permian Regional Gas Prices(1)

1) Pricing as of July 26, 2018

• Substantially stronger Mid-Continent price realizations
• Oil prices benefit from proximity to Cushing markets
• Gas takeaway solutions in the Mid-Continent are more

imminent than the Permian

• Producer Net Revenue Interests are typically higher in the

Mid-Continent

• Standard Royalty Interest of ~20% in the Mid-Continent are

advantaged to the 25-30% royalties exhibited in the Permian

• Development advancements are exhibiting a greater rate-
• f-change in the Mid-Continent as compared to the

Permian

• Operational infrastructure is less stressed in the Mid-

Continent, resulting in more efficient and lower risk to production and development

• Ability to expand operational control by forced pooling
• In Oklahoma the dominate acreage position in a single or

multi-section spacing unit typically wins operatorship

• Roan has ~76% operated working interest in the Merge

allowing for organic growth through forced pooling and drilling longer laterals

($2.00) ($1.50) ($1.00) ($0.50) $0.00 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 Sep-18 Nov-18 Jan-19 Mar-19 May-19 Jul-19 Sep-19

PEPL WAHA

($25.00) ($20.00) ($15.00) ($10.00) ($5.00) $0.00 $5.00 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 Sep-18 Nov-18 Jan-19 Mar-19 May-19 Jul-19 Sep-19

Historical Future Permian Crude Price Discount to WTI(1) Historical Future

25

Roan Midstream & Marketing: Crude

Crude Oil

• Acreage is advantageously located in close

proximity to Cushing (~65 miles) and several refineries

• Large number of potential crude purchasers
• Current oil price deduct is less than $1.50 per

barrel, and based on trucking transportation

• Considering strategic opportunities to market

directly to Cushing marketplace

• Reviewing proposals to transport oil on pipe

to Cushing

Local Takeaway and Sales Optionality

Ponca City Wynnewood (CVR) Ardmore Cushing

Roan acreage

26

Roan Midstream & Marketing: Gas & NGLs

Natural Gas and NGLs

• Acreage dedications to Blue Mountain

Midstream (~50%) and EnLink Midstream (~50%)

• Similar fixed cost structure and proportional

NGL revenue reduction at both midstream providers

• Contracts based on Mont Belvieu pricing
• Blue Mountain Midstream currently expanding

plant capacity

• June capacity of 60 MMcf/d increasing to 150

MMcf/d in July and then to 250 MMcf/d by 4Q’18

• Blue Mountain evaluating second train in

2019

• EnLink Midstream looping gathering system and

adding compression capacity in Roan producing area

• Increased takeaway solutions in Oklahoma in

2019

• Basis hedges in place through 2Q’20

(proposed)

Current Gas Takeaway Infrastructure

Roan dedication

27

Roan Financial Highlights

• Industry leading balance sheet and credit profile
• LQA Leverage of <1.0x
• High cash flowing production base
• Strong credit profile supplemented by high asset quality
• Deep inventory of de-risked development locations
• Significant cash flow margins
• Superior capital efficiency
• F&D(1) of $4.72 per Boe
• ~75% to +100% ROR(2)
• Corporate recycle ratio(3) of 4.9x
• PVIs(2) of over 2.0x
• Unhedged 1Q’18 cash margin(4) of ~$23 per Boe
• Active hedge program
• Limits financial risk and provides development funding visibility
• Substantial financial flexibility
• High capacity to adjust development program: Acreage largely HBP’d; Rigs on 12-month or less contracts; nominal minimum

volume commitments

Line of sight to continued growth plus free cash flow generation by 1H 2020

1) F&D is calculated by: YE’17 proved undeveloped capital cost / undeveloped net reserves 2) ROR and PVI are based on $65 WTI / $2.75 HH 3) See slide 11 for calculation of recycle ratio 4) Please see slide 36 for calculation of cash margin

28

Capitalization & Credit Metrics

Capitalization & Credit Metrics Peer 1Q'18 LQA Leverage(4) Peer 1Q'18 Net Debt / Total Capitalization(4)(5)

1) Adjusted EBITDAX and Net Debt are non-GAAP measures, please see slide 34 for a reconciliation of these measures to the most directly comparable GAAP measure 2) 1Q'18 Borrowing Base reflects amount effective from the Spring 2018 redetermination 3) From the 2017 Roan reserve report, prepared by D&M; PV10 amount incorporate $65 WTI and $2.75 HH pricing, see slide 35 for reconciliation from SEC pricing to $65 WTI and $2.75 HH 4) Figures sourced from public filings and internal reports. LQA represents last quarter annualized. Peers include: AMR, CDEV, CLR, CPE, CXO, FANG, JAG, LPI, MTDR, NFX, PE, XEC and WRD 5) Net Debt / Total Capitalization calculated as (Total Debt - Cash) / (Total Liabilities + Book Equity)

0.3x 0.5x 0.7x 0.7x 0.8x 1.1x 1.3x 1.4x 1.4x 1.5x 1.6x 1.6x 1.7x 3.0x 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x 1 2 Roan 3 4 5 6 7 8 9 10 11 12 13 8% 10% 10% 11% 15% 19% 22% 22% 23% 35% 43% 45% 53% 53% 0% 10% 20% 30% 40% 50% 60% 1 2 Roan 3 4 5 6 7 8 9 10 11 12 13

29

Roan Guidance

2018

Production (MBoe/d) 43 – 46 Exit Rate Production (MBoe/d) 58 – 64 Adjusted EBITDAX(1)(2) ($MM) $340 - $370 D&C Capex ($MM) $565 - $605 Other Capex $110 - $120 Total Capex ($MM) $675 - $725 4Q18 Operated Rig Count 8

1) Adjusted EBITDAX is a non-GAAP measures as defined on slide 34. Projected 2018 and 2019 Adjusted EBITDAX is not reconcilable at this time and excludes the impact of hedges. 2) Based on $65 WTI and $2.75 HH; excludes the impacts of hedges 3) CAGR represents the periods from 4Q’17 to exit rate 2019 4) Exit rate production numbers and adjusted EBITDAX numbers are the midpoint of guidance

2019

Production (MBoe/d) 72 – 83 Exit Rate Production (MBoe/d) 88 – 100 Adjusted EBITDAX(1)(2) ($MM) $625 - $725 D&C Capex ($MM) $670 - $750 Other Capex $80 - $100 Total Capex ($MM) $750 - $850 2019 Rig Count ≥8 Production Rates Adjusted EBITDAX(1)(2)

25.7 37.7 61.0 94.0 20 40 60 80 100 4Q'17 1Q'18 Exit rate 2018 Exit rate 2019 MBoe/d $355 $675 100 200 300 400 500 600 700 800 2018 2019 $ in MM

Investment criteria Roan

Pure play operator with large acreage position in Merge oil window ~90% of Merge acreage is in

• il and liquids-rich windows

Ample midstream availability with WTI oil pricing Transportation costs to Cushing < $1.50 per barrel; midstream providers adding capacity Decades of high ROR(1) inventory (~75% to +100% ROR) Up to ~4,000 gross operated locations Strong base production ~45,000 Boe/d Robust production growth with vision to free cash flow Projecting 75% YoY production growth; free cash flow by 1H 2020 Superior financial metrics LQA leverage ratio: 0.7x Top-tier, experienced in-basin operations team Legacy EOG team

30

Roan’s Investment Thesis

1) ROR is based on $65 WTI / $2.75 HH

31

Contact Information

Linn Energy, Inc.:

Investor Relations Phone: 281-840-4100 Email: IR@linnenergy.com

Appendix

32

33

Roan’s Current Hedge Summary

Oil Gas Period Swap Volumes Hedged (MBbls) Swap (weighted average $) Swap Volumes Hedged (MMcf) Swap (weighted average $) Basis Volumes Hedged (MMcf) Basis (weighted average $) 2018 3,962 $56.70 29,854 $2.94 16,440 ($0.54) 2019 4,608 $58.66 29,200 $2.86 21,900 ($0.58) 1H 2020 410 $60.19 5,005 $2.69 3,640 ($0.62)

1) Hedge position as of August 3, 2018

34

Non-GAAP Reconciliations

Adjusted EBITDAX Reconciliation

(in thousands) 1Q 2018 4Q 2017 Net Income (Loss) $35,081 $(9,176) Plus Adjustments: Interest Expense $1,799 $1,020 Depreciation, Depletion & Amortization 21,865 15,234 Exploration Expense 7,850 28,154 Non-Cash Equity-Based Compensation 2,292 379 Gain on Early Termination of Derivative Contracts (377)

• Non-Cash Loss on Derivative Contracts

5,476 9,501 Total Adjustments: $38,905 $54,288 Adjusted EBITDAX $73,986 $45,112 Annualized $295,944 $180,448

Adjusted EBITDAX is a non-GAAP financial measure. Roan defines Adjusted EBITDAX as net income (loss) adjusted for interest expense, depreciation, depletion, amortization and accretion, exploration costs, non-cash equity-based compensation expense, gain on early termination of derivative contracts, and non-cash loss on derivative contracts. Adjusted EBITDAX is presented as it allows management and analysts to more effectively evaluate Roan’s operating performance and compare the results of its operations from period to period and to peers without regard to financing methods or capital structure. Adjusted EBITDAX should not be considered an alternative to net income (loss) as defined by GAAP. Net Debt is a non-GAAP financial measure equal to long-term debt outstanding less cash on hand as of the date presented. Roan’s computations of Adjusted EBITDAX and Net Debt may not be comparable to other similarly titled measures of other companies or to such measure in our credit facility or any of our other contracts.

Net Debt Reconciliation

(In thousands) 1Q 2018 4Q 2017 Long-Term Debt $206,639 $85,339 Less: Cash (2,743) (1,471) Net Debt $203,896 $83,868

35

Reconciliation of Standardized Measure

• f Discounted Net Cash Flows to PV-10

Proved Reserves

($ in millions) Dec 31, 2017 Standardized Measure of Discounted Net Cash Flows $668.3 Present Value of Future Net Income Tax Expense Discounted at 10%

• PV-10

$668.3 Effects of Calculating Reserves and Pricing Using $65 WT & $2.75 HH 128.6 PV-10 of $65 WTI and $2.75 HH Proved Reserves 796.9 PV-10 PV-10 represents the present value, discounted at 10% per year, of estimated future net cash flows of reserves. Roan’s calculation of PV-10 herein differs from the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC in that it is calculated before income taxes and including the impact of helium, rather than after income taxes and not including the impact of helium, using the average price during the 12- month period, determined as an unweighted average of the first-day-of-the-month price for each month. Roan’s calculation of PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC.

36

1Q’2018 Cash Margin

Cash Margin Summary

(in thousands) 1Q’2018 $ / Boe(1) Oil, Natural Gas and NGLs Sales Revenue $110,073 $32.42 Cash Operating Expenses: Production Expense $8,355 $2.46 Gathering, Transportation and Processing 9,103 2.68 Production Taxes 2,386 0.70 General and Administrative (excluding non-cash items) 11,728 3.46 Total Expenses: $31,572 $9.30 Cash Margin $78,501 $23.12 Cash Loss on Derivatives Contracts ($4,138) ($1.22) Gain on Early Termination of Derivative Contracts (377) (0.11) Adjusted EBITDAX $73,986 $21.79

1) Assumes a 6:1 Bbl:MMcf ratio

Production Summary

1Q’2018 Oil Sales (MBbls/d) 11.6 Natural Gas Sales (MMcf/d) 98.7 NGLs Sales (MBbls/d) 9.7 Total (MBoe/d)(1) 37.7