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Roan Resources Investment Update July 2018
1
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.
2
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”
4
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
LNGGShare
Immediately following Spinoff Transaction
LNGG shareholders on record date will receive 1 share of RVRA common stock for each share of LNGG common stock
5
Strong Offset Activity and Well Results Demonstrates Asset Quality
Alta MesaSTACK Oil Window
Meramec / Osage
EOGEastern Anadarko
Woodford Oil Window
“High-Return Premium Play in
Crude Oil Window”
GPORSCOOP
Woodford / Sycamore /
Springer
MROSTACK / Meramec
“Consistent outperformance of STACK volatile
oil wells”
XECLone Rock Play“Best Results to
Date”
CLRSCOOP 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 $2.75 HH; please see slide 20 for information on the related type curves2) Please see slide 13 for recycle ratio calculation
Acreage Position(Net Acres)
Merge 117,000
SCOOP 29,000
STACK 8,000
Total 154,000
Merge
6
Roan Production
20.1 22.9 25.7
37.745.0
61.0
94.0
44%46%
50%
56% 54%
61%
62%
-5%
5%
15%
25%
35%
45%
55%
65%
0
20
40
60
80
100
120
2Q'17 3Q'17 4Q'17 1Q'18 Current rate Exit rate2018
Exit rate2019
% L
iqu
ids
MB
oe
/d
Net Production % Liquids
~365% projected growth from 2Q’17 to Dec’19
» »
Production History and Guidance:
(1)(1)
1) Based on the midpoint of guidance
7
Roan Financial Overview
Key Metrics / Guidance
1Q’18 Adjusted EBITDAX(1) ($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 20183) 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.
9
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 MarantoPresident, CEO and
Director
Greg CondrayEVP – Geoscience &
Business Development
Joel PettitEVP – Operations
and Marketing
David EdwardsChief 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 DirectorsMatthew BonannoMember 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 WoodsVice President of Land, Citizen Energy III
Top-Tier, Handpicked Management Team with Expertise in Mid-Continent
10
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 curves3) 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
11
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
12
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 TargetMayes /
WoodfordWoodford Meramec
Merge
13
Roan Economics Best in Class
74%
65% 63%
55% 54%
41% 41%
23%
0%
20%
40%
60%
80%
100%
RO
R(1
) @
$5
5 W
TI
/ $
3 H
H
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
4.9x4.6x
4.2x 4.2x
3.2x 3.1x
2.6x 2.5x 2.4x
2.0x 2.0x 1.9x1.7x
1.5x
0
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
14
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
15
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’dOperated 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 units2) 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
17
Key Merge Well Results
Collins 11-2-9-5 1XHIP-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 1XHIP-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-18IP-30: 2,537 Boe/d Oil: 17%; Liquids: 53%LL / Zone: 4,925’; Mayes
Griffin 26-23-10-5 1XHIP-30: 2,476 Boe/d Oil: 63%; Liquids: 81%LL / Zone: 6,500’; Woodford
Hinparr 31-6-10-5 1XHIP-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-33-28IP-30: 1,918 Boe/d Oil: 41%; Liquids: 67%LL / Zone: 9,700’; Woodford
Paxton1H-30-19IP-30: 1,774 Boe/d Oil: 29%; Liquids: 60%LL / Zone: 10,175’; Woodford
Spectacular Bid 18-11-6 2HIP-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-4-9IP-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/dOil: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/dOil: 24%LL / Zone: 7,600’; Woodford
Fowler 4N6W 3-9X16H (GPOR)IP-30: 3,061 Boe/dOil: 4%LL / Zone: 8,750’; Woodford
Triple H 5-30-31HS (CLR) IP-30: 2,344 Boe/dOil: 88%LL / Zone:10,200’; Springer
Pudge 1-7-6XH (CLR)IP-30: 2,419 Boe/dOil: 4%LL / Zone: 7,500’; Woodford
Ernsteen 1-21X28H (GPOR)
IP-30: 2,264 Boe/dOil: 22%LL / Zone: 7,600’; Woodford
Bragg 3-35X02H (GPOR)IP-30: 3,200 Boe/dOil: 1%LL / Zone: 9,600’; Woodford
Harper Thomas 1-19H (Unit)IP-30: 2,416 Boe/dOil: 87%LL / Zone: 5,140’; Hoxbar
Pauline 6-27X22H (GPOR)IP-30: 3,663 Boe/dOil: 24%LL / Zone: 7,625’; Woodford
Triple H 3-30-31HS (CLR) IP-30: 2,629 Boe/dOil: 86%LL / Zone: 10,200’; Springer
Triple H 4-30-31HS (CLR) IP-30: 2,418 Boe/dOil: 88%LL / Zone: 10,200’; Springer
Rowell 1-1-12XH (CLR)IP-30: 2,558 Boe/dOil: 1%LL / Zone: 5,400’; Woodford
Triple H 2-30-31HS (CLR) IP-30: 3,537 Boe/dOil: 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
9369
11
20
35
203
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
0
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
Cu
mu
lati
ve p
rod
uct
ion
(B
oe
)
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
Cu
mu
lati
ve p
rod
uct
ion
(B
oe
)
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 wellsYE’17 curve
YE’17 Mayes Oil Curve(1) Overview
YE’17 Mayes Oil Curve
IP 30 EUR Mix $65 WTI / $2.75HH
Oil Gas NGL OilTotal Liquids
AFE ($MM)
RORPayout 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 / $2.75HH
Oil Gas NGL OilTotal Liquids
AFE ($MM)
RORPayout 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 wellsYE’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 5 913
17
21
25
29
33
37
41
45
49
53
57
61
65
69
73
77
81
85
89
93
97
10
110
510
9
11
311
7
12
1
% In
Ta
rge
t Z
on
e
WellsLNGG/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
0
10
20
30
40
50
60
70
80
90
0 10 20 30 40
Cu
mu
lati
ve M
Bo
e
Days on Production
10,000' Normalized Cumulative MBoe
OPPEL 1H-16-21 - WDFD DUTCH 1H-33-28 - WDFD
+85% in 45 days
WellTreated 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 operations 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 optimization
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
23.322.0
27.3
30.0
14.112.7
18.116.9
0
5
10
15
20
25
30
35
1-MileMississippian
1-MileWoodford
2-MileMississippian
2-MileWoodford
Da
ys
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-of-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-1
7
Sep
-17
No
v-17
Jan-
18
Mar
-18
May
-18
Jul-1
8
Sep
-18
No
v-18
Jan-
19
Mar
-19
May
-19
Jul-1
9
Sep
-19
PEPL WAHA
($25.00)
($20.00)
($15.00)
($10.00)
($5.00)
$0.00
$5.00
Jul-
17
Sep
-17
No
v-17
Jan-
18
Mar
-18
May
-18
Jul-
18
Sep
-18
No
v-18
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19
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-19
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-19
Jul-
19
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-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 reserves2) ROR and PVI are based on $65 WTI / $2.75 HH 3) See slide 11 for calculation of recycle ratio4) 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 measure2) 1Q'18 Borrowing Base reflects amount effective from the Spring 2018 redetermination3) 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 $2.75 HH4) Figures sourced from public filings and internal reports. LQA represents last quarter annualized. Peers include: AMR, CDEV, CLR, CPE, CXO, FANG, JAG, LPI, MTDR, NFX, PE, XEC and WRD5) Net Debt / Total Capitalization calculated as (Total Debt - Cash) / (Total Liabilities + Book Equity)
0.3x0.5x
0.7x 0.7x 0.8x
1.1x1.3x 1.4x 1.4x 1.5x 1.6x 1.6x 1.7x
3.0x
0.0x
0.5x
1.0x
1.5x
2.0x
2.5x
3.0x
3.5x
1 2 Roan 3 4 5 6 7 8 9 10 11 12 13
8% 10% 10% 11%15%
19%22% 22% 23%
35%
43% 45%
53% 53%
0%
10%
20%
30%
40%
50%
60%
1 2 Roan 3 4 5 6 7 8 9 10 11 12 13
29
Roan Guidance
2018
Production (MBoe/d) 43 – 46
Exit Rate Production (MBoe/d) 58 – 64
Adjusted EBITDAX(1)(2) ($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 $2.75 HH; excludes the impacts of hedges3) CAGR represents the periods from 4Q’17 to exit rate 2019 4) Exit rate production numbers and adjusted EBITDAX numbers are the midpoint of guidance
2019
Production (MBoe/d) 72 – 83
Exit Rate Production (MBoe/d) 88 – 100
Adjusted EBITDAX(1)(2) ($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
0
20
40
60
80
100
4Q'17 1Q'18 Exit rate2018
Exit rate2019
MB
oe
/d
$355
$675
0
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 oil 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: [email protected]
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 VolumesHedged (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 financingmethods 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 $83,868
35
Reconciliation of Standardized Measure of Discounted Net Cash Flows to PV-10
Proved Reserves
($ 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