Riviera Investor Presentation August 23, 2018
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Riviera Investor Presentation August 23, 2018
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 Riviera Resources, Inc. (“Riviera” or the “Company”) 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 the Company, 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 the Company, 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 and the regulatory environment. 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 the Company’s Registration Statement on Form S-1 and other public filings. We undertake no obligation to publicly update any forward- looking statements, whether as a result of new information or future events. Reserve Estimates The Securities and Exchange Commission (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. The Company 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 the Company’s 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 The non-GAAP financial measure of adjusted EBITDAX, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, this non-GAAP measure should be considered in conjunction with net income (loss) and other performance measures prepared in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for GAAP. Adjusted EBITDAX is a measure used by Company management to evaluate the Company's operational performance and for comparisons to the Company's industry peers. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company's financial results. EBITDA The non-GAAP financial measure of EBITDA, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, this non-GAAP measure should be considered in conjunction with net income (loss) and other performance measures prepared in accordance with GAAP. EBITDA should not be considered in isolation or as a substitute for GAAP. EBITDA is a measure used by Company management to evaluate the Company's operational performance and for comparisons to the Company's industry peers. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company's financial results. PV-10 PV-10 represents the present value, discounted at 10% per year, of estimated future net cash flows. The Company’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. The Company’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.
Table of Contents Slides
Riviera Resources, Inc. Overview
Company Overview 5-8
Upstream Asset Overview 9
Proved Reserves 10
Upstream Benchmarking 11-14
Blue Mountain Midstream Overview 15-16
Balance Sheet and Buybacks 17-18
Riviera Upstream Overview 20
Upstream Growth Assets
NW STACK 22-25
Arkoma 26-28
East Texas 29-32
North Louisiana 33-35
Upstream Long Life Low Decline Assets
Hugoton / Jayhawk Plant 37-38
Michigan / Illinois 39
Uinta Basin (Drunkards Wash) 40
Blue Mountain Midstream LLC (wholly owned subsidiary)
Business Overview 42-45
Operational Overview 46-47
Commercial Overview 48-49
Financial Overview 50-51
Guidance Update 53-56
Commodity Hedge Portfolio 57-58
Capital Structure 59
Leadership 60-61
Riviera Resources – Recent Developments
Riviera Resources (Riviera or RVRA) recently spun-out from Linn Energy, Inc (LNGG) to unlock the sum of the
parts Net Asset Value
Riviera is a newly formed independent company focused on efficiently operating its mature low-decline
production, developing its growth-oriented assets (including Blue Mountain Midstream LLC), and returning
capital to shareholders
Based on recent trading, we believe RVRA is trading at a discount to its sum of the parts Net Asset Value
The Riviera Board approved a $100 million share buyback program
Due to encouraging offset activity, Riviera Upstream is initiating a NW STACK drilling program starting Q4 2018
Blue Mountain is working with Riviera Upstream to provide a midstream solution in the NW STACK
Riviera Upstream is evaluating potential development of its other growth assets, such as Arkoma, East Texas
and North Louisiana
Blue Mountain recently brought a state of the art cryogenic processing plant on-line and is currently processing
~150 mmcf/d
Due to rapidly ramping throughput, Blue Mountain has initiated the engineering and design of a second plant
targeting total throughput of 500 mmcf/d in 2H 2019 to meet projected demand
Blue Mountain has established a stand-alone $200 million credit facility with current capacity of $70 million
LNGG share buyback program has reduced outstanding share count to 76.2 million shares as of the Spin
Transaction
5
Riviera Resources - Overview
Riviera Upstream has 1.6 Tcfe of long life proved developed reserves with a Mid-Year adjusted PV-10 value of $963 million(1)
312 mmcfe/d second quarter 2018 average production
11% base production decline(2) (mature asset base declines: Hugoton 6%, Michigan/IL 4%; Uinta 11%)
15 year proved developed reserves to production ratio
Additionally, Riviera Upstream has a large undeveloped acreage position in several active basins
NW STACK (~60,000 net acres in Core Focus Area), Arkoma (~37,000 net acres), East Texas (~110,000 net acres), North
Louisiana (~100,000 net acres)
More than 900 potential net locations identified with expected internal rates of return (IRRs) >40%(3)
NW STACK operated rig starting in Q4 2018
Evaluating deployment of additional rigs in other growth basins
Blue Mountain Midstream is a growth-oriented midstream business in the heart of the Merge/SCOOP/STACK play in central OK
More than 80,000 acres dedicated to the system
Anchor producer is well-capitalized and currently running 8 rigs
State of the art cryogenic processing plant with current capacity of 150 mmcf/d growing up to 250 mmcf/d in Q4 2018
Initiated engineering and design of a second plant with additional capacity up to 250 mmcf/d servicing the rapidly growing
Merge play
Targeting additional 3rd party gas gathering, crude gathering, terminals and water handling
Strong balance sheet with no debt, up to $495(4) million of available borrowing capacity, and approximately $100 million in
projected cash as of 9/30/2018
(1) YE 2017 proved reserves as of 8/1/18 with updated pricing of $2.85 per MMBtu for natural gas and $65.00 per bbl for oil, and adjusted for basis pricing, including helium revenue, $7.5MM per year of
third party operating margin at Jayhawk Plant (PV-10 of $75MM) and excluding income taxes. See “Non-GAAP Measures - PV-10” for more information.
(2) Base decline includes both mature and growth assets
(3) Assumed Pricing: $2.85 per MMBtu for natural gas and $65.00 per bbl for oil 6
(4) Includes Riviera Upstream $425 million credit facility, and $70 million of Blue Mountain Midstream LLC $200 million credit facility
Riviera Resources – Sum of the Parts
1 2 3
Balance
Sheet
Current Additional Cash Upstream BMM
Mature / Cash- Future
Growth Assets Acreage Business Credit Credit
Flowing Assets Basins
Dedication Lines Facility Facility
Hugoton NW STACK $200 MM
Michigan Chisholm Trail
Arkoma System Crude credit facility
Drunkards Wash East Texas Gathering / $100 MM with $70MM
Terminals, NW STACK / $425 MM currently
North Louisiana Future projected as of
Jayhawk Plant Water Other credit facility available
Expansions 9/30/18
• 80,000 Acre Dedication
• Current throughput of ~150 mmcf/d
• Proved Developed PV-10: $963 Million(1)
• Initiated engineering and design of 2nd • No Debt
• More than 900 Net Development Locations >
cryogenic plant targeting on-line in 2H 2019 • $100 MM of cash projected as of 9/30/18
40% IRR(2)
• Would increase total processing capacity up
to 500 mmcf/d
(1) YE 2017 proved reserves as of 8/1/18 with updated pricing of $2.85 per MMBtu for natural gas and $65.00 per bbl for oil, and adjusted for basis pricing, including helium revenue, $7.5MM per year of third 7
party operating margin at Jayhawk Plant (PV-10 of $75MM) and excluding income taxes. See “Non-GAAP Measures - PV-10” for more information.
(2) Assumed Pricing: $2.85 per MMBtu for natural gas and $65.00 per bbl for oil
Riviera Resources – Value Proposition
Income Generating Growth Oriented Assets
Assets Requiring Funded by Strong
Minimal Capital Balance Sheet
Northwest STACK
Hugoton Arkoma
Michigan/IL East TX
Uinta North LA
Blue Mountain Midstream
Free Cash Flow
NAV
Returned Through
Growth
Share Repurchases,
Realized
Dividends, and/or
Tenders
Shareholder Returns
8
1 Riviera Upstream – Asset Detail
Proved Developed(2) Proved Developed
Net Production(1) R/P(3)
Reserves PV-10(2)
Upstream Assets Net Acres
(MMcfe/d) (in Years)
(Bcfe) ($ in millions)
Hugoton ~1,100,000 136 842 19 $529
East Texas ~110,000 51 242 13 $137
North Louisiana ~100,000 27 61 7 $78
Michigan / Illinois ~200,000 27 233 23 $85
Arkoma ~37,000 25 111 12 $61
64
NW STACK / other Oklahoma ~110,000 24 7 $51
Uinta ~50,000 22 40 6 $21
Total ~1,707,000 312 1,593 15 $963
(1) Average daily second quarter 2018 actual production
(2) YE 2017 proved reserves as of 8/1/18 with updated pricing of $2.85 per MMBtu for natural gas and $65.00 per bbl for oil, and adjusted for basis pricing, including helium revenue, $7.5MM per year of third
party operating margin at Jayhawk Plant (PV-10 of $75MM) and excluding income taxes. See “Non-GAAP Measures - PV-10” for more information.
(3) R/P is based on proved developed reserves divided by 2018 forecasted production
9
1 Riviera Upstream - Proved Reserves(1)
Total Proved
76% Natural Gas ~1.6 Tcfe of Proved Reserves PV-10 of ~$1.021 Billion
6%
4% 4% 6%
22%
2%
90% 90%
76%
Natural Gas Oil NGL PDP PDNP PUD PDP PDNP PUD
Proved Reserves
as of August 1, 2018 Natural Gas Oil NGL Total PV-10
Bcf MMBbl MMBbl Bcfe ($ in Millions)
PDP 1,115 4 58 1,491 $918
PDNP 96 1 1 102 $45
Total Proved Developed 1,211 5 59 1,593 $963
PUD 54 0 1 60 $58
Total Proved 1,265 5 60 1,653 $1,021
(1) YE 2017 proved reserves as of 8/1/18 with updated pricing of $2.85 per MMBtu for natural gas and $65.00 per bbl for oil, and adjusted for basis pricing, including helium revenue, $7.5MM per year of third
party operating margin at Jayhawk Plant (PV-10 of $75MM) and excluding income taxes. See “Non-GAAP Measures - PV-10” for more information. 101
Riviera Upstream - Benchmarking
Reserve Life
Proved Developed Reserves / Production
(in years)
15
11
10 10
9
8
7
6 6
4
RVRA Company D Company I Company B Company A Company C Company H Company E Company F Company G
Riviera Upstream has the highest ratio of PD reserves to production compared to peers;
To maintain PD reserves, Riviera only needs to replace 7% of its PD reserves annually
Notes:
• Sourced from company 10-K’s and guidance; Proved Developed reserve volumes are from disclosed 2017 SEC reserves; Production is 2018 guidance
• Peers include CHK, CNX, GPOR, LGCY, NFX, RRC, SD, SWN, UNT
111
Riviera Upstream - Benchmarking
PDP Reserve Value vs. Adjusted EBITDAX
7.0x
PDP Reserve Value / Adjusted EBITDAX
(multiple)
4.8x
3.6x 3.5x 3.5x
3.1x
1.9x
N/A N/A N/A
RVRA Company I Company C Company A Company B Company D Company G Company E Company F Company H
Due to Riviera Upstream’s long life reserves, the company should trade
at a higher multiple of adjusted EBITDAX versus peers
Notes:
• Sourced from company 10-K’s and guidance; PDP reserve values are from 2017 10-K filings of SEC reserves. RVRA YE 2017 proved reserves as of 8/1/18 with updated pricing of $2.85 per
MMBtu for natural gas and $65.00 per bbl for oil, and adjusted for basis pricing, including helium revenue, $7.5MM per year of third party operating margin at Jayhawk Plant (PV-10 of
$75MM) and excluding income taxes. See “Non-GAAP Measures - PV-10” for more information; adjusted EBITDAX is 2018 company provided guidance 12
• Peers include CHK, CNX, GPOR, LGCY, NFX, RRC, SD, SWN, UNT1 Riviera Upstream - Benchmarking
Enterprise Value Vs. PDP Reserve Value
Enterprise Value / PDP Reserve Value
(multiple)
2.3x
2.1x
Avg. = 1.7x
1.7x
1.5x
1.4x
1.0x
N/A N/A N/A
Company G Company A Company I Company B Company C Company D Company E Company F Company H
If Riviera Upstream’s enterprise value to PDP reserve value was at the midpoint of peers
(1.7x), it would imply a $1.6 billion valuation for the upstream business only
Notes:
• Enterprise Value sourced from Bloomberg and Yahoo Finance as of 8/16/2018; PDP reserve values are from disclosed 2017 SEC reserves
• Peers include CHK, CNX, GPOR, LGCY, NFX, RRC, SD, SWN, UNT 131
Riviera Upstream - Benchmarking
G&A Vs. Production
G&A / Production
($ / mcfe)
$0.59
$0.52
$0.38
$0.34
$0.27
$0.21 $0.21 $0.22
$0.18
$0.13
Company G Company A Company C Company I Company F RVRA Company B Company H Company E Company D
On a production basis, Riviera Upstream’s G&A is expected to be in-line with peers
Notes:
• Sourced from company 10-K’s and guidance; Riviera G&A is pro-forma for 2019 ($30MM annually); peers’ G&A based on 2018 guidance
• Peers include CHK, CNX, GPOR, LGCY, NFX, RRC, SD, SWN, UNT 142 Blue Mountain Midstream –
Overview
• Blue Mountain Midstream, LLC (“Blue Mountain”), a wholly owned
subsidiary of Riviera, is a growth-oriented midstream business located
in the heart of the Merge/SCOOP/STACK play in central Oklahoma
• Blue Mountain’s first cryogenic processing plant was brought on-line
in June 2018
– The plant has current throughput of ~150 mmcf/d
– At 250 mmcf/d throughput, plant should generate between
$100-$125 million of run-rate EBITDA
• Blue Mountain recently initiated the design and engineering of a
second cryogenic plant to service its rapidly growing throughput
– Targeting 2H 2019 start-up
– Total processing capacity will increase up to 500 mmcf/d
• Proven management team focused on expanding midstream footprint
by leveraging:
– Existing infrastructure base
– Acreage dedications
– Strong commercial relationships
– Well-funded and active customer base
• Future growth opportunities include:
– Recently approved capacity expansions in Merge play
– Additional business lines (e.g., crude gathering / storage, water
and purity NGLs)
– Extend reach across Merge/SCOOP/STACK/NW STACK plays
• Independent capital structure to self-fund future growth opportunities
either as a part of RVRA or as a stand-alone business
15Blue Mountain Midstream –
Key Statistics
Estimated Operating Margin(1) (in millions) Capital Forecast(2) (in millions)
200 200
$22
175
$32
170
150
140
$18
125
125
$75
MMcf/d
100
$53
75
62
61
50
$6
$53
25 $43
$1 $3 $33
$0
0
Q1 2018 A Q2 2018 E Q3 2018 E Q4 2018 E 2016A 2017A 2018E
Estimated Throughput MMcf / Day - Upper Range Field Cryo I Cryo II
Estimated Throughput MMcf / Day - Lower Range
Plant Operating Margin Estimate - Lower Range
Plant Operating Margin Estimate - Upper Range
(1) Operating margin is all Blue Mountain Midstream revenue less direct operating expenses and does not include G&A
(2) Field includes refrigeration facilities 1 and 2 163 Riviera Resources – Pro-Forma Cash 9/30/18
($ in millions)
$17 ($13)
$301 $301 $304
($50)
$254
($40)
$214 Approximately
76.2 million
shares
($115) outstanding
$85-$100
$100 ($15) $15
$85 $85
LNGG Cash LNGG / RVRA LNGG / RVRA LNGG / RVRA LNGG LNGG Share Working RVRA Projected
Balance Adjusted Severance Capital Cash (1) Repurchase Capital / Cash
6/30/2018 EBITDAX before Spending through Other Balance
Severance Spin-Off 8/7/18 9/30/18 (1)
(1) Prior to the spin-off of Riviera from LNGG (the “Spin-off”), $40 million of cash was remaining at LNGG available for use by LNGG to fund certain obligations of the Company arising
after the Spin-Off and prior to any consolidation with Roan Resources LLC (“Roan Resources”). LNGG will transfer any such remaining cash to Riviera (assumed to be $15MM)
prior to any consolidation of LNGG and Roan Resources.
173 Riviera Resources – Share Buybacks
Through August 7, 2018
LNGG returned approximately $800 million to shareholders
($ in millions)
2018 Open Market
Share Repurchases
2017 Open Market Retirement of Profits and Employee Liquidity
Share Repurchases Tender Offer Interest Shares (1) Program(2) Total
$799
$256
$20
$523 $543
$325
$198 $198
Number of
5,690,192 6,770,833 470,630 6,371,234 19,303,389
Shares
Average Price
$ 34.85 $ 48.00 $ 42.34 $40.18 $ 41.40
Per Share
(1) Class A-2 units of LINN Energy HoldCo LLC held by management retired as a result of common stock repurchases, inclusive of tender offer process
(2) Employee liquidity program repurchases represents 1,331,082 vesting restricted stock units of LNGG (“RSUs”) settled in cash prior to shares being issued, 2,598,663 shares previously issued as a
result of vested RSUs and A-2 units converted to Class A common stock of LNGG and subsequently repurchased 1,837,469 shares of Class A common stock of LNGG retired in open market
purchases, and 604,520 RSUs settled in cash for statutory tax withholdings prior to shares being issued 18Riviera Upstream Asset Overview
Focus on Existing Basins
Riviera Upstream Asset Map
Growth
Mid-Continent 312 MMcfe/d ~1.6 Tcfe 11%(1)
Net Production of ~49 MMcfe/d Second Quarter 2018 Proved Developed Reserves Approximate
NW STACK Net Production 76% Natural Gas Base Decline Rate
• Core acreage position of ~60,000 net acres heavily 22% NGL
concentrated in Blaine, Major and Garfield counties, with
significant offset activity
Arkoma
• ~37,000 net acres, 100% held by production (“HBP”)
with large inventory of remaining horizontal locations
East Texas
Net Production of ~51 MMcfe/d
~ 110,000 net acres HBP
Bossier and Cotton Valley development potential Michigan / IL
Two successful horizontal wells drilled in 2017
North Louisiana Uinta
Net Production of ~27 MMcfe/d
~ 100,000 net acres HBP
Four operated horizontal wells drilled in 2016/2017 with Hugoton
excellent results
Long Life, Low Decline
Hugoton Arkoma
NW STACK
Net Production of ~136 MMcfe/d
Base decline of ~ 6%
More than 3,400 infill drilling locations economic at varying
prices above $3.00 per mcf NLA
Jayhawk Plant derives significant value from helium recovery
and third party processing
Michigan / Illinois ETX
Net Production of ~27 MMcfe/d
Base decline of ~4%
Uinta
Net Production of ~22 MMcfe/d
Base decline of ~ 11%
Non-Operated position
(1) Base decline includes both mature and growth assets 20Growth Assets • NW STACK • Arkoma • East Texas • North Louisiana
NW STACK - Overview
NW STACK Position
• Approximately 60,000 core net acres within
Riviera’s focus area of Major, Blaine, and
Garfield counties
– Acreage is ~100% HBP and ~75%
operated(1)
– Acreage located in black oil window
– Shallow drilling depths of ~7,500 –
~9,500 feet result in significantly lower
drilling costs than STACK play south of
our core area
– Expected wells costs range from
$3.8MM to $5.8MM
– Potential inventory of >825 net
locations with IRRs >40%(2)
• Additional acreage outside of the core is
being delineated by offset operators
• Riviera has participated in 59 non-operated
wells
NW STACK Core Focus Area
• Plan to initiate operated drilling program in
Q4 2018
(1) Operation control assumed if leasehold >/= 200 acres in a section
(2) Assumed Pricing: Gas: $2.85/Mmbtu; Oil: $65.00/bbl 22NW Stack – Regional Geology Plays & Targets
N GR DPHI S
N
MISS LIME
Osage
NW STACK
STACK Woodford
MERGE S Miss Lime NW STACK NW STACK STACK MERGE
Platform
• Merge to NW STACK is continuous petroleum system
• Massive hydrocarbon column with economic production
throughout
SCOOP – Vertical production from Hunton up through Penn
– Established horizontal success in Meramec and
Osage across core acreage
• Target shallows to the north resulting in higher oil cuts
and lower drilling costs
23NW Stack – Osage
Meramec
Rig Activity
Permit
Analogs
Offset Activity
Hedrick 3-1H (Comanche) Elwell 29-1H (Comanche) Childress 1-26H (Fairway) Newton 1-31H (Fairway) Regier 7-2H (Fairway)
IP30/1000ft:124 Boe/d IP30/1000ft: 229 IP30/1000ft: 82 IP30/1000ft: 189 IP30/1000ft: 91
Oil: 50% Oil: 51% Oil: 56% Oil: 67% Oil: 74%
Shepherd 24-25-1H (Comanche) Martens 5-35 (Red Bluff)
IP30/1000ft: 147 Boe/d IP30/1000ft: 161
Oil: 63% Oil: 66%
Mounds 16-1H (Carrera) Schoeppel 16-2 1H (Chesapeake)
IP30/1000ft: 150 IP30/1000ft: 179
Oil: 61% Oil: 54%
Smart 24-20-17 1H (Tapstone) Gerken 2205 1UMH-33 (Chaparral)
IP30/1000ft: 242 IP30/1000ft: 240
Oil: 37% Oil: 53%
Fenton 17-1H (Corlena) Barbee 2105 1LMH-4 (Chaparral)
IP30/1000ft: 131 IP30/1000ft: 241
Oil: 56% Oil: 68%
Olive Lee 1H-22 (Devon) White Oak 2206 1UMH-36 (Chaparral)
IP30/1000ft: 377 IP30/1000ft: 153
Oil: 20% Oil: 15%
Dennis 28-19-1 1H (Tapstone) Osmus 22&15-20 1H (Chesapeake)
IP30/1000ft: 375 IP30/1000ft: 91
Oil: 15% Oil: 71%
Medill 2015 1-27H (Sandridge) Willamette 30 & 1H (Chesapeake)
IP30/1000ft: 184 IP30/1000ft: 122
Oil: 82% Oil: 63%
Campbell 2015 1-26H23H (Sandridge) Joyce 14-1H (Comanche) Burrell 5-33 MH (Red Bluff) Scheffler 1H-9X (Newfield) Hoskins 5-19-1 1H (Chesapeake)
IP30/1000ft: 98 IP30/1000ft: 94 IP30/1000ft: 185 IP30/1000ft: 163 IP30/1000ft: 204
Oil: 82% Oil: 71% Oil: 56% Oil: 77% Oil: 57%
24
Note: Rig and permit data sourced from DrillingInfo as of August 20, 2018NW STACK - Current Inventory
Type Log NW STACK Inventory
Formations • Base case: 4 wells per section in Meramec and Lower Osage
• Gross locations: ~1,950
• Net locations: ~825
Meramec
• Upside case: 7 wells per section in Meramec, Upper Osage, Lower Osage
• Gross locations: ~5,100
• Net locations: ~2,170
1 Mile
Mississippian
Upper Osage
Base Upside
Case Case
Formation Wells Wells Total
Meramec 4 3 7
Lower Osage
U. Osage 0 7 7
L. Osage 4 3 7
Woodford
Woodford Additional Potential
Hunton
25Arkoma - Overview
Arkoma Position
• Approximately 37,000 net acres mainly in
Hughes and Coal counties, OK
– Acreage is ~100% HBP and ~46%
operated
– Position is fully de-risked in the
Woodford shale with ~420 horizontal
wells drilled on Riviera's acreage
– Base inventory of ~90 net Woodford
locations with average IRR ~30%(1)
– Significant upside in the emerging
Mayes, Caney, and Cromwell plays
• Gas production is very liquids rich with
~27% of revenue coming from NGLs
• Substantial recent offset operations with
~230 horizontal wells drilled since 2015
and 9 rigs currently running in the area
Note: Rig data sourced from DrillingInfo as of July 30 2018
(1) Assumed Pricing: Gas: $2.85/Mmbtu; Oil: $65.00/bbl 26Rig Activity Analogs
Arkoma – Offset Activity Permit
Sherry Pad (BP) Pauline Pad (Trinity Operating) Emma Pad (Trinity Operating) Stewart Pad (BP)
3 Wells drilled in 2015 4 Wells drilled in 2017 2 Wells drilled in 2017 4 Wells drilled in 2017
5,174’ Average Lateral Length 10,298’ Average Lateral Length 7,923’ Average Lateral Length 9,448’ Average Lateral Length
5,802 Mcfd Average Peak IP-30 6,311 Mcfd Average Peak IP-30 6,810 Mcfd Average Peak IP-30 4,621 Mcfd Average Peak IP-30
Ina Pad (BP) Hunt-Garrett Pad (BP)
3 Wells drilled in 2015 3 Wells drilled in 2016
5,646’ Average Lateral Length 8,099’ Average Lateral Length
5,656 Mcfd Average Peak IP-30 8,679 Mcfd Average Peak IP-30
Binns Pad (BP) Sandmann 1H-9X Well (Newfield)
4 Wells drilled in 2017 Drilled in 2015
5,288’ Average Lateral Length 10,709’ Lateral Length
6,995 Mcfd Average Peak IP-30 12,095 Mcfd Average Peak IP-30
Phillips Pad (BP) Payden 1H-12XX Well (Newfield)
2 Wells drilled in 2015 Drilled in 2015
5,927’ Average Lateral Length 10,807’ Lateral Length
6,854 Mcfd Average Peak IP-30 14,856 Mcfd Average Peak IP-30
HB 1-11 Well (Canyon Creek) Ellis Pad (Newfield)
Drilled in 2017 2 Wells drilled in 2015
8,099’ Lateral Length 11,619’ Average Lateral Length
2,876 Mcfd Average Peak IP-30 12,674 Mcfd Average Peak IP-30
LDC Pad (Canyon Creek) Persall 1-8/17H Well (Bravo)
2 Wells drilled in 2017 Drilled in 2017
8,984’ Average Lateral Length 8,934’ Lateral Length
2,607 Mcfd Average Peak IP-30 6,783 Mcfd Average Peak IP-30
Lackey Pad (Bravo Arkoma) Resh 2-8H Well (BP)
2 Wells drilled in 2016 Drilled in 2017
7,515’ Average Lateral Length 5,790’ Lateral Length
2,474 Mcfd Average Peak IP-30 6,524 Mcfd Average Peak IP-30
Bellettini Trust Pad (Bravo Arkoma) Smalley Pad (BP)
3 Wells drilled in 2015 3 Wells drilled in 2015
9,247’ Average Lateral Length 5,555’ Average Lateral Length
4,869 Mcfd Average Peak IP-30 6,945 Mcfd Average Peak IP-30
Ward Pad (Bravo Arkoma) McEntire Pad (Bravo Arkoma) Bowen Pad (BP)
2 Wells drilled in 2016 3 Wells drilled in 2016 3 Wells drilled in 2015
9,883’ Average Lateral Length 9,177’ Average Lateral Length 7,354’ Average Lateral Length
7,619 Mcfd Average Peak IP-30 4,421 Mcfd Average Peak IP-30 6,786 Mcfd Average Peak IP-30
27
Note: Rig and permit data sourced from DrillingInfo as of July 30, 2018Arkoma - Current Inventory
Type Log Arkoma Inventory
• Base case: 5 wells per section in Woodford
• Gross locations: ~230
• Net locations: ~90
Cromwell • Upside: 5 wells per section in Mayes & Caney
• Additional Potential: Cromwell emerging play
1 Mile
Jefferson
Base Upside
Case Case
Caney Formation Wells Wells Total
Cromwell Additional Potential
Caney 0 5 5
Mayes 0 5 5
Woodford 5 0 5
Mayes
Woodford
Hunton
28East Texas – Overview
East Texas Position • Approximately 110,000 net acres
mainly in Limestone, Freestone, and
Personville
Smith counties, TX
– Acreage is ~98% HBP and ~86%
operated
– Significant upside horizontal
development of the Bossier and
Cotton Valley formations
– Significant inventory of >60 net
locations with attractive returns at
current commodity prices
• Recently completed integration of 3D
seismic into Bossier mapping to identify
Overton
additional inventory in the Personville
field
– Bossier well drilled in 2017
yielded excellent results with EUR
~1.5 Bcf/1,000ft
• Overton field is seeing increased
horizontal activity directly offset the
position
29East Texas – Personville Field
• Bossier target of incised valley fill sandstones Personville Type Log
• 3D seismic tied to well control using waveform modeling combined with
amplitude mapping provide high probability in prediction of IVF sand
presence
Bossier
• Current inventory of 27 net Bossier wells
• Cotton Valley Lime infill horizontal developement provides additional upside
IVF
Bossier – Incised Valley Fill (IVF) Sandstones – Cross Section
Cotton Valley
Lime
Buckner
30East Texas – Overton Field
Type Log
• Overton Field is currently a vertical
producing Cotton Valley field
• There have been 72 offset horizontal
wells drilled in the Cotton Valley Taylor
Sands Taylor L1
Cotton Valley Sands
• Significant amount of offset horizontal
activity generating attractive returns at
current prices Taylor L2
• Approximately 45 net horizontal
development locations identified within Taylor L3
Riviera's acreage position
Taylor L4
• Economics of development benefit from
high liquid yields of approximately 30
bbls/mmcf
31Rig Activity Analogs
Overton – Offset Activity Permit
CV Taylor Sand Gross Isopach Map
McElroy-Swann Moore 1H (Tanos)
Completion Date: 7/3/2017
Peak IP-30: 5.7 MMCFD
LL: 6,737’ Burns 3HR (Valence)
Completion Date: 6/9/2018
McElroy ‘A’- Wilkinson 1H (Tanos) Peak IP-30: Too Recent
Completion Date: 3/23/2017 LL: 5,313’
Peak IP-30: 6.1 MMCFD
LL: 4,803’ Burns-Poole 1H (Valence)
Completion Date: 6/10/2018
Maldonado-Murray 1H (Tanos) Peak IP-30: Too Recent
Completion Date: 3/20/2018 LL: 7,281’
Peak IP-30: 5.8 MMCFD
LL: 4,910’ Burton 2H (Jamex)
Completion Date: 8/3/2017
McElroy ‘A’- Murray 1H (Tanos) Peak IP-30: 4.7 MMCFD
Completion Date: 3/12/2018 LL: 5,636’
Peak IP-30: 3.5 MMCFD
LL: 4,478’ Reagan-Black Stone-Wilkinson 2H
(Tanos)
Pond-Gray 1H (Tanos) Completion Date: 1/3/2017
Completion Date: 6/4/2017 Peak IP-30: 7.8 MMCFD
Peak IP-30: 5.4 MMCFD LL: 6,807’
LL: 3,837’
Steele Gas Unit 1H (Jamex)
Pond 2H (Tanos) Completion Date: 6/20/2018
Completion Date: 5/24/2017 Peak IP-30: Too Recent
Peak IP-30: 7.1 MMCFD LL: 5,943’
LL: 4,950’
McElroy 3H (Valence)
Wilkinson Gas Unit 1H (Jamex) Completion Date: 6/5/2018
Completion Date: 07/17/2018 Peak IP-30: Too Recent
Peak IP-30: Too Recent LL: 7,675’
LL: 6,524’
Cecil Martin Gas Unit 1H (Jamex)
Johnson Gas Unit 2H (Jamex) Completion Date: 8/3/2017
Completion Date: 6/4/2018 Peak IP-30: 6.5 MMCFD
Peak IP-30: Too Recent LL: 6,019’
LL: 6,914’
RVRA’s position has very thick CV Taylor Sand compared to offset results
32
Note: Rig and permit data sourced from DrillingInfo as of July 30, 2018North Louisiana - Overview
North Louisiana Position
• Approximately 100,000 net acres
across northern Louisiana
Ruston Field
– Acreage is ~99% HBP and
~63% operated
• Ruston field is direct offset to
prolific Terryville field
– Significant upside of the
stacked benches of Bossier
(Poole) Sands
– 4 horizontal wells drilled on
Riviera’s acreage with 3
Middle Poole wells average
IRR >100%(1)
– Inventory of ~15 net
locations with exceptional
returns
• Additional upside potential exists
throughout position
(1) Assumed Pricing: Gas: $2.85/Mmbtu; Oil: $65.00/bbl 33North Louisiana - Ruston Field
• Growth faults isolate the sands on downthrown block of faults providing a three way trap
• High maturity of Bossier source rocks provides overpressure reservoir
• Recent development has been horizontal wells targeting the Middle and Lower Bossier
(Poole) Sands, proving dual bench development
• The 4 recent wells drilled on Riviera’s acreage have yielded excellent returns
Upper Poole Sand
– Development downthrown of Terryville Fault with ~15 net remaining locations
– Additional potential upside north of Terryville Fault
Ruston RVRA Operated Horizontal Wells
Middle Poole Sand
J P Graham 2H 2 Alt (RVRA)
Lower Poole Sand
Target: Middle Poole
EUR: 5.4 BCF/1,000’
Elliott Etal 1-11HC 1 (RVRA)
Target: Middle Poole Elliott Etal 1H 1 Alt (RVRA) Carter Etal 6H 1 Alt (RVRA)
EUR: 3.7 BCF/1,000’ Target: Lower Poole Target: Middle Poole
EUR: 1.9 BCF/1,000’ EUR: 3.9 BCF/1,000’
34North Louisiana – Rig Activity Analogs
Permit
Ruston Offset Activity
Lewis 21-16-9 HC 2 Alt (Range) Autry 25-36 HC 3 Alt (Range)
Completion Date: 1/19/2017 Completion Date: 2/7/2017
Peak IP-30: 19 MMCFD Terryville/Ruston Wells Drilled Since 1/2017 & Peak IP-30: 25 MMCFD
LL: 6,522’ LL: 8,026’
Riviera Operated Wells
Standifer 16-21 HC 1 Alt (Range) Autrey 25-36 HC 4 Alt (Range)
Completion Date: 5/28/2017 Completion Date: 2/7/2017
Peak IP-30: 19 MMCFD Peak IP-30: 22 MMCFD
LL: 6,158’ LL: 7,952’
Tatum 19-30 HC 1 Alt (Range) Autry 25-36 HC 2 Alt (Range)
Completion Date: 8/6/2017 Completion Date: 2/7/2017
Peak IP-30: 21 MMCFD Peak IP-30: 24 MMCFD
LL: 4,800’ LL: 7,952’
Tatum 19-30 HC 2 Alt (Range) Elliott Etal 1H 1 Alt (LINN)
Completion Date: 8/6/2017 Completion Date: 7/9/2017
Peak IP-30: 17 MMCFD Peak IP-30: 13 MMCFD
LL: 7,781’ LL: 3,797’
Tatum 19-30 HC 3 Alt (Range) Harrison 7-6 HC 2 Alt (N&G)
Completion Date: 8/6/2018 Completion Date: 10/8/2017
Peak IP-30: 25 MMCFD Peak IP-30: 17 MMCFD
LL: 7,816’ LL: 3,367’
Lamar Dowling 28-33 H 2 (Range) Carter Etal 6H 1 Alt (LINN)
Completion Date: 11/25/2017 Completion Date: 1/3/2017
Peak IP-30: 20 MMCFD Peak IP-30: 15 MMCFD
LL: 8,160’ LL: 4,021’
Lamar Dowling 28-33 H 1 (Range) Christian Etal 5-8HC 1 Alt (N&G)
Completion Date: 11/27/2017 Completion Date: 5/7/2017
Peak IP-30: 21 MMCFD Peak IP-30: 20 MMCFD
LL: 8,247’ LL: 6,115’
Barnett 26-35HC 1 Alt (Range) J P Graham 2H 2 Alt (LINN)
Completion Date: 2/27/2017 Completion Date: 8/17/2017
Peak IP-30: 22 MMCFD Peak IP-30: 16 MMCFD
LL: 10,348’ LL: 4,403’
Fallin 23-26-35 HC 2 Alt (Range) Burnett 35-2 HC 1 Alt (Range) Smith Etal 34-3-10 HC 2 Alt (N&G) Elliott Etal 1-11HC 1 (LINN)
Completion Date: 2/18/2017 Completion Date: 2/14/2017 Completion Date: 8/18/2017 Completion Date: 2/20/2016
Peak IP-30: 18 MMCFD Peak IP-30: 29 MMCFD Peak IP-30: 45 MMCFD Peak IP-30: 29 MMCFD
LL: 10,154’ LL: 8,752’ LL: 7,658’ LL: 6,503’
Note: Rig and permit data sourced from DrillingInfo as of July 30, 2018 35Long-Life, Low-Decline Assets • Hugoton – Jayhawk Plant • Michigan / Illinois • Uinta
Hugoton – Overview
• Net Production of ~136 MMcfe/d(1) (66% Natural Gas, 34% NGL) Hugoton Position
• ~1.1 million net acres that are 99%+ held by production(2)
• Very mature, low decline, highly delineated natural gas field
• Focus on Chase and Council Grove formations which produce
significant revenue from NGLs and helium Jayhawk Plant
450 MMcf/d Capacity
• Extensive gathering infrastructure and a significant midstream /
processing investment
• 100% interest in the Jayhawk processing plant with capacity of 450
MMcf/d (currently at ~56% utilization)
• More than 3,400 infill drilling locations economic at varying prices
above $3.00 per mcf
• Estimate a minimal amount of capital to offset base decline
Jayhawk Plant
450 MMcf/d Capacity
Historical Production Trend
180
160 Decline Rate of ~6%
Price Sensitivity
Net Production (Mmcfe/day)
140 Number of drilling locations greater than 20% ROR
120 $2.75
Natural Gas Price ($/MMBtu)
100 $3.00
80 $3.25
Average annual capital of ~$2 million
60
$3.50
40
$3.75
20
0 $4.00
Jul-15 Nov-15 Mar-16 Jul-16 Nov-16 Mar-17 Jul-17 Nov-17 Mar-18
0 500 1,000 1,500 2,000 2,500 3,000 3,500
(1) Volumes are average daily second quarter 2018 actual production 37
(2) Acreage as of year end 2017Hugoton - Jayhawk Plant Overview
• Commissioned April 1998 – 100% Riviera owned
• Cryogenic Plant with high NGL recoveries and ethane rejection capability
• Capacity of 450 MMcf/day; current throughput approximately 256 MMcf/day
• Electric driven compression
• Propane fractionator
• Helium Recovery & Nitrogen Rejection capability
• Two NGL outlets: ONEOK & Enterprise
• Residue outlet: Southern Star Central
• Helium outlets: Praxair & BLM Pipeline
• 3rd Party annual Adjusted EBITDA of $7MM - $10MM
Jayhawk Plant Historical Throughput
Berry ~256,000
300,000 XTO / Pioneer separation mcf/d
Hugoton Satanta plant
~170,000
Acquisitions shutdown
mcf/d
250,000
45% of
200,000 total
through
MMcf/day
put
150,000
100,000
55% of
total
through
50,000 put
0
Equity Volumes Third Party Gas 38Michigan / Illinois – Overview
Michigan/IL Position
• Net Production of ~27 MMcfe/d(1) (97% Natural Gas, 3% Oil)
• ~ 200,000 net acres
• Base decline of approximately 4%
• Michigan is a low decline, biogenic natural gas asset
• Illinois is a mature waterflood
Michigan Historical Production Trend
MI
35
Decline Rate of ~4%
30
Net Production (Mcfed)
25
20
IL
15
Average annual capital of ~$1.6 million
10
5
-
Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18
39
(1) Volumes are average daily second quarter 2018 actual productionUinta – Overview
Asset Highlights Uinta Position
• ~22 MMcfe/day net production(1)
• ~50,000 net acres, majority HBP
• Base decline of ~11%
• Non-operated position acquired through Devon
acquisition in 2014
• Extensive salt water disposal infrastructure
Uinta Historical Production Trend
30
25 Decline Rate of ~11%
Net Production (Mcfed)
20
15
10
Average annual capital of ~$0.166 million
5
0
Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18
40
(1) Volumes are average daily second quarter 2018 actual productionBlue Mountain Midstream Overview
Blue Mountain History
Key Highlights February 2016 – Executed GPA with Linn Energy Holdings, LLC (“LEH”) and approved
capital for construction of first refrigeration facility with 30 mmcf/d of processing capacity
October 2016 – Capital plan approved, including additional compression and second
refrigeration facility, adding 30 mmcf/d of processing capacity
November 2016 – Second refrigeration facility operational for total processing capacity of
60 mmcf/d
May 2017 – Supplemental capital approved to build Cryo Plant I with 250 mmcf/d of
processing capacity
June 2017 – Start of construction for Cryo Plant I
September 2017 – Amended GPA with LEH, dedicating ~70,000 acres to Blue Mountain
system
December 2017 – Other third-party dedicates ~7,200 acres to Blue Mountain system
April 2018 – Current management team joins Blue Mountain
June 2018 – Start up of Cryo Plant I
August 2018 – Initiated design and engineering of Cryo Plant II
Today Blue Mountain system has more than 80,000 acres dedicated and is currently
processing ~150 mmcf/d of natural gas and 9,800 bbl/d of NGLs
42Blue Mountain Company Overview
• Growth-oriented midstream company focused on
Merge/SCOOP/STACK plays in Oklahoma
• System located in core of prolific Merge play, currently a leading
operating area in U.S.
• More than 80,000 net acres dedicated to system
– LINN Energy’s acreage contributed to Roan Resources is
dedicated to the Blue Mountain system
– Other third-party dedication accelerating growth of business
• Cryo Plant I is catalyst for future growth
– Estimated 2018 exit-rate of 170-200 mmcf/d and expect to
reach full capacity 250 mmcf/d in mid-2019
– At full capacity, Cryo Plant I forecasted to generate
annualized EBITDA between $100-125 million
• Significant growth expected from increased throughout from
current customers and additional third-party volumes
– Initiating design and engineering of Cryo Plant II for up to
250 MMcf/d to meet growing demand
• Commercially focused on diversifying asset and revenue bases
– Crude gathering would provide commodity diversification
– Future expansion into NW STACK with new counterparties
• Connected to major pipelines out of basin to liquid Midwest & Gulf
Coast markets
Current footprint and sizeable dedication provide ample growth opportunities
43Blue Mountain
Executive Management Team
• Most recently served as President, Gas Pipelines & Processing for Enbridge Energy from January 2014 to April 2017
C. Gregory Harper • Formerly SVP of Midstream for Southwestern Energy, SVP and Group President of CenterPoint Energy Pipelines and Field
Services, President & CEO of Spectra Energy Partners, and multiple executive leadership roles for Duke Energy
President and Chief
Executive Officer • Currently serves on the board of Sprague Resources, and has served on the boards of Midcoast Holdings L.L.C., Enbridge
Energy Company, Inc., Enbridge Energy Management, L.L.C, and Spectra Energy Partners
• Over 35 years of energy industry experience with roles ranging from the field to executive leadership
David A. Weathers
• Prior to Blue Mountain, served as Vice President of Business Development for Enbridge’s U.S. Gathering & Processing
Executive Vice President business unit
and Chief Commercial • Former Senior Director for NextEra Energy and held various roles of increasing responsibility for over 20 years with Duke
Officer Energy
Brad D. Reese • Over 36 years of energy industry experience, with over 25 years concentrated in midstream infrastructure development
Executive Vice President • Most recently was President of Enbridge Canadian Gathering & Processing, and served on the boards of Alliance Pipeline and
Aux Sable companies
and Chief Development &
• Prior to Enbridge, held various leadership roles for over 29 years with Targa Resources, Spectra Energy and DCP Midstream
Corporate Services Officer
• Over 36 years of energy industry experience with roles in engineering / construction, operations, and commercial development
Christopher T. Ditzel • Prior to Blue Mountain, served as Vice President of Commercial Operation for Enable Midstream
Chief Operating Officer • Over 28 years served in multiple leadership roles in engineering, operations and business development for Panhandle Eastern,
Duke Energy and Spectra Energy
Noor S. Kaissi • Most recently held numerous finance leadership roles for Enbridge Energy, including Controller of Enbridge’s U.S. asset base
• Principal accounting officer for Enbridge Energy Management, Enbridge Energy Partnership and Midcoast Energy Partnership
Vice President of
Accounting and Finance • Prior to Enbridge, held leadership positions with Dynegy, Enron and Arthur Andersen
High-quality executive team supported by accomplished, commercially-focused
technical and financial teams
44Blue Moutain Key Priorities
Cryo Plant I in-service June 2018
Capture incremental third-party volumes to system
Ensure sufficient take-away capacity for system volumes
Design and engineering of Cryo Plant II commenced August 2018
Diversification of products, service offerings, and reach into new basins
Stand-up organization, processes and finances for standalone platform
Blue Mountain team focused on achievable, highly value-driven opportunities
45Initial Blue Mountain System Overview
• 250 mmcf/d of designed processing capacity with Cryo Plant I
• ~87,000 HP of total compression
• 110 miles of gathering pipe
• Supported by dedicated acreage position of more than 80,000 net
acres under long-term contracts
• Interconnections into Southern Star Central, Enable Gas
Transmission and ONEOK Gas Transportation pipelines
• At full capacity, Cryo Plant I forecasted to generate annualized
EBITDA between $100-125 million
Blue Mountain system strategically positioned to capture and provide market
access for producer volumes
Note: Processing capacity, compression and pipeline mileage shown are for fully-built system at year-end 2018 46Blue Mountain Midstream –
Cryo Plant I Update
• State of the art cryogenic processing facility in-
service June 2018
• Initial operating capacity of 150 mmcf/d and
62,000 horsepower of compression now online
• Full 250 mmcf/d to become available by 4Q
2018, with the addition of 25,000 HP of
compression
Forecasted Throughput vs. Plant Capacity
300,000
• ONEOK Hydrocarbon providing NGL 250,000
transportation from the facility 200,000
mmcf/d
150,000
• Facility is fully staffed and operating 24/7 100,000
50,000
0
Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18
• 80-acre site provides ample space for additional
Forecasted Throughput (Upper Range)
trains to meet growing demand Actuals Through August 2018; Forecasted Throughput (Lower Range)
Plant Capacity
Blue Mountain system built by experience operations staff; focus now
moves to design and engineering of Cryo Plant II
47Merge / SCOOP Play Overview
Active Rigs by Operator in Merge / SCOOP(1) Merge / SCOOP Rig Activity(1)
14 13
12
10
8
8
6
4 3 3 3
2 2 2 2
2 1 1 1 1 1
0
Horizontal Drilling Permits in the Merge(2)
136 125
3
20
20 56
61
35 93
14 69
11
15
2015 2016 2017 2018 YTD
Other Operators LNGG Citizen Roan
Blue chip operators surround premier Merge / SCOOP acreage position
(1) Source: Drilling Info as of August 2018
(2) Source: IHS; 2018 YTD is as of July 2018 48Customer Acreage Dedication
More than 80,000 acres dedicated to Blue Mountain
System
• Roan Resources is anchor producer (1)
– Pure play operator in Merge/SCOOP/STACK
formed by LINN Energy and Citizen Energy
– Largest position in the Merge play
– Producing ~45,000 Boe/d and forecasting
61,000 Boe/d by end of 2018
– Running 8 rigs on dedicated acreage
• Received other third-party dedication in December
2017
– Private company
– Dedicated acreage located in close proximity
to system
– Expect to add 10 new wells to system in 2018
• In active talks to gain additional third-party
dedications
Decision made on Cryo Plant II with up to 250 mmcf/d of addition capacity, based on producer
commitments and anticipated production growth from Roan and other producers
(1) Guidance from Roan Resources Investor Update July 2018 and current production and rig count from Roan Resources 49Blue Mountain Key Statistics
Estimated Operating Margin(1) (in millions) Capital Forecast (2) (in millions)
200 200
$22
175
170 $32
150
140
$18
125
125
100
mmcf/d
$75
75
62
50 61 $53
$6
25
$1 $3
$0
0
Q1 2018 A Q2 2018 E Q3 2018 E Q4 2018 E $53
$43
$33
Estimated Throughput MMcf / Day - Upper Range
Estimated Throughput MMcf / Day - Lower Range
2016A 2017A 2018E
Plant Operating Margin Estimate - Lower Range
Plant Operating Margin Estimate - Upper Range Field Cryo I Cryo II
Blue Mountain systems designed for speed and efficient deployment of capital
(1) Operating margin is all Blue Mountain Midstream revenue less direct operating expenses and does not include G&A 50
(2) Field includes refrigeration facilities 1 and 2Blue Mountain Key Takeaways
Deep Experienced management team in place with proven track record of
Midstream successful execution in midstream energy infrastructure
Expertise
Strong believers in Anadarko Basin and current asset footprint well-
Leading G&P
positioned to capitalize on growth opportunities in prolific Merge/
Position
SCOOP/STACK/NW STACK plays
Strong
Commercial Closely aligned with our key customer – Roan Resources
Relationships
Aggressive ramp up in volumes and EBITDA strengthens cash flow in near-
Financial
term; secured $200 million line of credit with $70 million currently available
Strength
provides funding for growth
Multiple Key focus on securing future growth projects; beginning design and
Avenues for engineering of Cryo Plant II and evaluating other scalable business growth
Growth opportunities
51Financial and Management Update
2019 Guidance to be
2018 Guidance Provided Following
Budget Approval
Q3 2018E Q4 2018E FY 2018E
Net Production (MMcfe/d) 275 – 305 270 – 305 314 – 330
Natural gas (MMcf/d) 225 – 250 220 – 248 237 – 250
Oil (Bbls/d) 1,300 – 1,500 1,300 – 1,500 3,200 – 3,300
NGL (Bbls/d) 6,900 – 7,700 7,000 – 8,000 9,600 – 10,000
Other revenues, net (in thousands) (1) $ 9,000 - $ 13,000 $ 25,000 - $ 31,000 $ 52,000 – $ 63,000
Blue Mountain Midstream business $ 3,000 - $ 6,000 $ 18,000 - $ 22,000 $ 22,000 – $ 29,000
Other $ 6,000 - $ 7,000 $ 7,000 - $ 9,000 $ 30,000 – $ 34,000
Costs (in thousands) $ 48,000 – $ 54,000 $ 47,000 – $ 54,000 $ 223,000 – $ 236,000
Lease operating expenses $ 23,000 – $ 25,000 $ 23,000 – $ 26,000 $ 118,000 – $ 123,000
Transportation expenses $ 19,000 – $ 21,000 $ 18,000 – $ 20,000 $ 77,000 – $ 81,000
Taxes, other than income taxes $ 6,000 – $ 8,000 $ 6,000 – $ 8,000 $ 28,000 – $ 32,000
Adjusted general and administrative expenses (2) $ 22,000 – $ 24,000 $ 15,000 – $ 17,000 $80,000 – $ 84,000
Severance expenses $ 12,000 – $ 14,000 $ 3,000 – $ 5,000 $ 33,000 – $ 37,000
Costs per Mcfe (Mid-Point) $ 1.91 $ 1.91 $ 1.95
Lease operating expenses $ 0.90 $ 0.93 $ 1.03
Transportation expenses $ 0.75 $ 0.72 $ 0.67
Taxes, other than income taxes $ 0.26 $ 0.26 $ 0.25
Targets (Mid-Point) (in thousands)
Adjusted EBITDAX $ 4,000(3) $ 39,000(3) $ 94,000(3)
Interest expense (4) $— $— $—
Oil and natural gas capital $ 16,000 $ 33,000 $ 66,000
Blue Mountain Midstream capital $ 29,000 $ 41,000 $ 160,000
Total capital $ 50,000 $ 76,000 $ 235,000
Weighted Average NYMEX Differentials
Natural gas (MMBtu) ($ 0.47) – ($ 0.38) ($ 0.45) – ($ 0.35) ($ 0.40) – ($ 0.35)
Oil (Bbl) ($ 5.05) – ($ 4.55) ($ 3.00) – ($ 2.70) ($ 4.00) – ($ 2.00)
NGL price as a % of crude oil price 36% – 41% 36% – 41% 34% – 38%
Unhedged Commodity Price Assumptions Jul Aug Sep Oct Nov Dec 2018E
Natural gas (MMBtu) $3.00 $2.82 $2.94 $2.95 $2.98 $3.07 $2.92
Oil (Bbl) $70.58 $67.63 $67.63 $66.94 $66.54 $66.21 $66.51
(1) Includes other revenues and margin on marketing activities
(2) Excludes share-based compensation expenses and severance expenses
(3) Includes a reduction to Adjusted EBITDAX for certain non-recurring G&A expenses, including estimated severance expenses of $35mm, estimated spin transaction costs of $7.5mm, estimated land diligence costs of
$3.6mm, divestiture related expenses of $1.1mm 53
(4) Excludes non cash amortization of deferred financing costsPro-Forma Adjusted Riviera Upstream
2018 Adjusted EBITDAX Outlook
Adjusted
Riviera
2018 Pro-forma Upstream
Riviera Estimates Guidance
Resources
$140 Guidance
$120
$52
$100
$ in Millions
$80 ($23)
$132
$60 $35
($26)
$94
$40 $80
$71
$20 $45 $45 $45
$0
FY 18 Guidance Pre-Close Adjusted FY18 Operating Implied Riviera Severance Expected G&A Pro-Forma FY18
EBITDAX from Margin from Blue Upstream Pro- Expense Reductions (3) Estimate
Asset Sales (1) Mountain Forma FY 18 E
Midstream (2)
(1) Represents Adjusted EBITDAX before closing for the following: OK Waterfloods closed 2/28/18, TX Panhandle Shallow closed 2/28/18, Permian Conventional W TX closed 3/29/18, Altamont
Bluebell closed 4/4/18, Permian NM closed 4/10/18
(2) Only includes the Chisholm Trail business, and excludes G&A
(3) Further G&A reductions, including Blue Mountain G&A, that will result in a pro-forma run-rate of approximately $30 million annually 54FY 2018 Capital Allocation
Total Capital $235 million
($ in millions)
Drilling = $45MM
Seismic = $ 8MM
Leasing = $11MM
Total = $64MM
Upstream Assets Oil
& Gas Capital (1)
Blue Mountain $64
Midstream 1H'18
$90
Asset Sales (2)
$2
Other P&P / Admin
$9
Blue Mountain
Midstream 2H'18
$70
(1) Assets include Hugoton, Michigan, Uinta, Arkoma, NW STACK, North Louisiana, and East Texas
(2) Asset Sales include Oklahoma Waterfloods and Texas Panhandle closed 2/28/18, Permian Conventional West TX closed 3/29/18, Altamont Bluebell closed 4/4/18, and Permian NM closed 4/10/18. 552018 Capital Bridge – Full Year
($ in millions)
Blue Mountain Midstream Capital Bridge
$160
$32 $160
$120 $8
$120 $120 $128
$80
$40
$0
Prior Guidance Plant 1 Field / Plant 2 Current Guidance
Other (1)
Riviera Upstream Capital Bridge
$80
$4 $1
$60 $14
$8 $56
$8 $48
$40 $75
$40 $40
$20
$0
Prior Guidance NW STACK NW STACK NW STACK Arkoma Non- Other Current
Seismic Leasing Operated Drilling Operated Guidance
(1) Represents acceleration of capital previously forecasted in 2019 to increase plant 1 capacity
56Commodity Hedge Portfolio –
Henry Hub and WTI
Natural Gas Positions Oil Positions
200 191 2000
175 1750
1500
Volume Hedged (MMbtu/d)
150 1500
Volume Hedged (bbls/d)
125 1250
100 $3.02
1000
75 750 $54.07
61
500
50 500
25 $2.89 250 $64.00
0 0
2018 2019 2018 2019
57Commodity Hedge Portfolio –
Natural Gas Basis
PEPL Basis Positions NGPL TXOK Basis Positions
100 25
Volume Hedged (MMbtu/d)
Volume Hedged (MMbtu/d)
20
75
60 60
15
50
10
10
($0.659) ($0.659)
25
5 ($0.185)
0
0 0
2018 2019 2018 2019
Michcon Basis Positions
25
Volume Hedged (MMbtu/d)
20
15
10 10
10
5 ($0.200) ($0.200)
0
2018 2019 58Capital Structure
• Approximately 76.2 million shares issued and outstanding at record date
Common Equity
• Approximately 0.5 million shares of restricted shares(1)
• Interest on borrowings determined by reference to either LIBOR +250 to 350
or ABR +150 to 250, depending on utilization
Riviera Upstream
$425 Million Revolver • $0 million drawn on RBL post Spin-Off
• Redeterminations semi-annually every April and October
Blue Mountain • Interest on borrowings determined by reference to either LIBOR +200 to 300
Midstream or ABR +100 to 200, depending on leverage ratio
$200 Million Revolver • $70 million available post Spin-Off, up to $200 million total availability
(1) Originally granted pursuant to the Linn Energy 2017 Omnibus Incentive Plan and converted to Riviera Resources 2018 Omnibus Inventive Plan at Spin-Off 59Board of Directors
Evan Lederman is a Managing Director, Co-Head of Restructuring and Partner on the Investment Team at Fir Tree Partners. Mr. Lederman focuses on
the funds’ distressed credit and special situation investment strategies, including co-managing its energy restructuring initiatives. Prior to joining Fir Tree
Evan Lederman Partners in 2011, Mr. Lederman worked in the Business Finance and Restructuring groups at Weil, Gotshal & Manges LLP and Cravath, Swaine &
Moore LLP. Mr. Lederman, in his capacity as a Fir Tree Partners employee, is currently a member of the boards of Riviera Resources, Inc. (Chairman),
Director Ultra Petroleum Corp. (Chairman), Amplify Energy Corp., New Emerald Energy LLC, Roan Resources LLC and Deer Finance, LLC. Mr. Lederman
received a J.D. degree with honors from New York University School of Law and a B.A., magna cum laude, from New York University.
Matthew Bonanno joined York Capital Management (“York”) in July 2010 and is a Partner of the firm. Mr. Bonanno joined York from the Blackstone
Group, where he worked as an associate focusing on restructuring, recapitalization and reorganization transactions. Prior to joining the Blackstone
Matthew Bonanno Group, Mr. Bonanno worked on financing and strategic transactions at News Corporation and as an investment banker at JP Morgan and Goldman
Sachs. Mr. Bonanno, in his capacity as a York employee, is currently a member of the boards of Riviera Resources, Inc., Rever Offshore AS, all entities
Director incorporated pursuant to York’s partnership with Costamare Inc., Augustea Bunge Maritime, Next Decade LLC, Vantage Drilling Co. and Roan
Resources LLC.
Phil Brown Philip Brown is a Partner of P. Schoenfeld Asset Management (“PSAM”), where he focuses on credit-oriented investments across various industries.
Prior to joining PSAM in 2009, Mr. Brown held positions at Sun Capital Partners, Inc., an operationally-focused private equity firm, and Buckeye Capital
Director Partners, an event-driven hedge fund. Mr. Brown began his career as an investment banking analyst at Wasserstein Perella & Co.
Andy Taylor is a member of the investment team of Elliott Management Corporation (“Elliott”), a New York-based investment firm, where he is
responsible for various corporate investments. Prior to joining Elliott in 2015, Mr. Taylor held similar positions in BlackRock’s Distressed Products
Andy Taylor Group, R3 Capital Partners and the Global Principal Strategies team at Lehman Brothers. Mr. Taylor, in his capacity as an Elliott employee, is currently
Director a member of the boards of Riviera Resources, Inc., Linn Energy Inc., Roan Resources LLC, Birch Permian Holdings Inc. and Cordero Energy Holdings,
LLC. Mr. Taylor received a B.S. in mechanical engineering from Rose-Hulman Institute of Technology and his M.B.A. with honors from the University of
Chicago.
David Rottino David Rottino is President and Chief Executive Officer and a director of Riviera Resources. Prior to Riviera Resources’ spin-off from LINN Energy, Inc.,
he served as LINN Energy’s Executive Vice President and Chief Financial Officer and as a member of the board of directors. Mr. Rottino has over 25
President and Chief years of total experience and over 20 years of experience in the oil and natural gas industry. Prior to joining LINN in June 2008, he served at El Paso
Energy, ConocoPhillips and Burlington Resources in various finance, accounting and strategic planning roles. Mr. Rottino earned a bachelor’s degree in
Executive Officer business administration from Texas Tech University and an M.B.A. from Texas Christian University.
Greg Harper has served as the President and CEO of Blue Mountain Midstream since 2018. Prior to Blue Mountain Midstream, Mr. Harper served as
Greg Harper President, Gas Pipelines and Processing and as the principal executive officer of Midcoast Holdings L.L.C., an Enbridge Inc. affiliate. Before joining
Enbridge, Mr. Harper served in various Senior Executive positions including Senior Vice President of Midstream of Southwestern Energy Company,
President and Chief Senior Vice President and Group President of CenterPoint Energy Pipelines and Field Services, and President, Chief Executive Officer and Director of
Executive Officer of Spectra Energy Partners, LP. Mr. Harper currently serves on the board of Sprague Resources where he has served as the chair of the audit committee
Blue Mountain since Sprague’s initial public offering in 2013, and previously served on the boards of Midcoast Holdings, L.L.C., Enbridge Energy Company, Inc. and
Enbridge Energy Management, L.L.C. Mr. Harper received his Bachelor’s degree in mechanical engineering from the University of Kentucky and his
Midstream M.B.A from the University of Houston.
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