Barclay s 2018 CEO Energy-Power Conference September 2018 New York City

Transcription

1 Barclay s 2018 CEO Energy-Power Conference September 2018 New York City

2 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 forwardlooking 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.

3 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.

4 Table of Contents Riviera Resources, Inc. Overview Slides Company Overview 5-8 Upstream Asset Overview 9 Proved Reserves 10 Upstream Benchmarking Blue Mountain Midstream Overview Balance Sheet and Buybacks Riviera Upstream Overview 20 Upstream Growth Assets NW STACK Arkoma East Texas North Louisiana Upstream Long Life Low Decline Assets Hugoton / Jayhawk Plant Michigan / Illinois 39 Uinta Basin (Drunkards Wash) 40 Blue Mountain Midstream LLC (wholly owned subsidiary) Business Overview Operational Overview Commercial Overview Financial Overview Guidance Update Commodity Hedge Portfolio Capital Structure 59 Leadership 60-61

5 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 Q 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

6 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 Q 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 Q Initiated engineering and design of a second plant with additional capacity up to 250 mmcf/d servicing the rapidly growing Merge play Targeting additional 3 rd 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 (4) Includes Riviera Upstream $425 million credit facility, and $70 million of Blue Mountain Midstream LLC $200 million credit facility 6

7 Riviera Resources Sum of the Parts Balance Sheet Mature / Cash- Flowing Assets Growth Assets Current Acreage Dedication Additional Business Lines Future Basins Cash Upstream Credit Facility BMM Credit Facility Hugoton Michigan Drunkards Wash Jayhawk Plant NW STACK Arkoma East Texas North Louisiana Chisholm Trail System Future Expansions Crude Gathering / Terminals, Water NW STACK / Other $100 MM projected as of 9/30/18 $425 MM credit facility $200 MM credit facility with $70MM currently available Proved Developed PV-10: $963 Million (1) More than 900 Net Development Locations > 40% IRR (2) 80,000 Acre Dedication Current throughput of ~150 mmcf/d Initiated engineering and design of 2nd cryogenic plant targeting on-line in 2H 2019 Would increase total processing capacity up to 500 mmcf/d No Debt $100 MM of cash projected as of 9/30/18 (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) Assumed Pricing: $2.85 per MMBtu for natural gas and $65.00 per bbl for oil 7

8 Riviera Resources Value Proposition Income Generating Assets Requiring Minimal Capital Growth Oriented Assets Funded by Strong Balance Sheet Hugoton Michigan/IL Uinta Free Cash Flow Returned Through Share Repurchases, Dividends, and/or Tenders Northwest STACK Arkoma East TX North LA Blue Mountain Midstream NAV Growth Realized Shareholder Returns 8

9 1 Riviera Upstream Asset Detail Upstream Assets Net Acres Net Production (1) (MMcfe/d) Proved Developed (2) Reserves (Bcfe) R/P (3) (in Years) Proved Developed PV-10 (2) ($ in millions) Hugoton ~1,100, $529 East Texas ~110, $137 North Louisiana ~100, $78 Michigan / Illinois ~200, $85 Arkoma ~37, $61 NW STACK / other Oklahoma ~110, $51 Uinta ~50, $21 Total ~1,707, , $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

10 1 Riviera Upstream - Proved Reserves (1) 76% Natural Gas 22% ~1.6 Tcfe of Proved Reserves 6% 4% Total Proved PV-10 of ~$1.021 Billion 4% 6% 2% 76% Natural Gas Oil NGL 90% PDP PDNP PUD PDP PDNP PUD 90% Proved Reserves as of August 1, 2018 Natural Gas Bcf Oil MMBbl NGL MMBbl Total Bcfe PV-10 ($ in Millions) PDP 1, ,491 $918 PDNP $45 Total Proved Developed 1, ,593 $963 PUD $58 Total Proved 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. 10

11 1 Riviera Upstream - Benchmarking Reserve Life 15 Proved Developed Reserves / Production (in years) 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 11

12 1 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 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, UNT

13 1 Riviera Upstream - Benchmarking Enterprise Value Vs. PDP Reserve Value 2.3x 2.1x Enterprise Value / PDP Reserve Value (multiple) 1.7x 1.5x 1.4x Avg. = 1.7x 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 13

14 1 Riviera Upstream - Benchmarking G&A Vs. Production G&A / Production ($ / mcfe) $0.59 $0.52 $0.34 $0.38 $0.27 $0.18 $0.21 $0.21 $0.22 $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 14

15 2 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 (1) 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 (1) Estimate assumes $14-$16 million of annual G&A costs. 15

16 2 Blue Mountain Midstream Key Statistics Estimated Operating Margin (1) (in millions) Capital Forecast (2) (in millions) $160 MMcf/d $ $18 $33 $96 $53 $32 $ $6 $1 $3 $0 Q A Q E Q E Q E $53 $43 $ A 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 16

17 3 Riviera Resources Pro-Forma Cash 9/30/18 ($ in millions) $17 ($13) $301 $301 $304 ($50) $254 ($40) $214 ($115) Approximately 76.2 million shares outstanding $100 $85-$100 ($15) $15 $85 $85 LNGG Cash Balance 6/30/2018 LNGG / RVRA Adjusted EBITDAX before Severance LNGG / RVRA Severance LNGG / RVRA Capital Spending LNGG Cash (1) LNGG Share Repurchase through Spin-Off 8/7/18 Working Capital / Other RVRA Projected Cash Balance 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. 17

18 3 Riviera Resources Share Buybacks Through August 7, 2018 LNGG returned approximately $800 million to shareholders ($ in millions) 2017 Open Market Share Repurchases Tender Offer Retirement of Profits Interest Shares (1) 2018 Open Market Share Repurchases and Employee Liquidity Program(2) Total $799 $256 $20 $523 $543 $325 $198 $198 Number of Shares Average Price Per Share 5,690,192 6,770, ,630 6,371,234 19,303,389 $ $ $ $40.18 $ (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 18

19 Riviera Upstream Asset Overview

20 Focus on Existing Basins Riviera Upstream Asset Map Growth Mid-Continent Net Production of ~49 MMcfe/d NW STACK Core acreage position of ~60,000 net acres heavily 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 312 MMcfe/d Second Quarter 2018 Net Production ~1.6 Tcfe Proved Developed Reserves 76% Natural Gas 22% NGL 11% (1) Approximate Base Decline Rate East Texas Net Production of ~51 MMcfe/d ~ 110,000 net acres HBP Bossier and Cotton Valley development potential Two successful horizontal wells drilled in 2017 Michigan / IL North Louisiana Uinta Net Production of ~27 MMcfe/d ~ 100,000 net acres HBP Four operated horizontal wells drilled in 2016/2017 with excellent results Hugoton Long Life, Low Decline Hugoton 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 Jayhawk Plant derives significant value from helium recovery and third party processing NW STACK Arkoma NLA 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 20

21 Growth Assets NW STACK Arkoma East Texas North Louisiana

22 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 Q (1) Operation control assumed if leasehold >/= 200 acres in a section (2) Assumed Pricing: Gas: $2.85/Mmbtu; Oil: $65.00/bbl 22

23 NW Stack Regional Geology Plays & Targets N GR DPHI S N MISS LIME Osage NW STACK STACK Woodford MERGE S Miss Lime Platform NW STACK NW STACK STACK MERGE SCOOP Merge to NW STACK is continuous petroleum system Massive hydrocarbon column with economic production throughout 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 23

24 NW Stack Offset Activity Osage Meramec Rig Activity Permit Analogs Hedrick 3-1H (Comanche) IP30/1000ft:124 Boe/d Oil: 50% Elwell 29-1H (Comanche) IP30/1000ft: 229 Oil: 51% Childress 1-26H (Fairway) IP30/1000ft: 82 Oil: 56% Newton 1-31H (Fairway) IP30/1000ft: 189 Oil: 67% Regier 7-2H (Fairway) IP30/1000ft: 91 Oil: 74% Shepherd H (Comanche) IP30/1000ft: 147 Boe/d Oil: 63% Martens 5-35 (Red Bluff) IP30/1000ft: 161 Oil: 66% Mounds 16-1H (Carrera) IP30/1000ft: 150 Oil: 61% Schoeppel H (Chesapeake) IP30/1000ft: 179 Oil: 54% Smart H (Tapstone) IP30/1000ft: 242 Oil: 37% Gerken UMH-33 (Chaparral) IP30/1000ft: 240 Oil: 53% Fenton 17-1H (Corlena) IP30/1000ft: 131 Oil: 56% Barbee LMH-4 (Chaparral) IP30/1000ft: 241 Oil: 68% Olive Lee 1H-22 (Devon) IP30/1000ft: 377 Oil: 20% White Oak UMH-36 (Chaparral) IP30/1000ft: 153 Oil: 15% Dennis H (Tapstone) IP30/1000ft: 375 Oil: 15% Osmus 22& H (Chesapeake) IP30/1000ft: 91 Oil: 71% Medill H (Sandridge) IP30/1000ft: 184 Oil: 82% Willamette 30 & 1H (Chesapeake) IP30/1000ft: 122 Oil: 63% Campbell H23H (Sandridge) IP30/1000ft: 98 Oil: 82% Joyce 14-1H (Comanche) IP30/1000ft: 94 Oil: 71% Note: Rig and permit data sourced from DrillingInfo as of August 20, 2018 Burrell 5-33 MH (Red Bluff) IP30/1000ft: 185 Oil: 56% Scheffler 1H-9X (Newfield) IP30/1000ft: 163 Oil: 77% Hoskins H (Chesapeake) IP30/1000ft: 204 Oil: 57% 24

25 NW STACK - Current Inventory Type Log Formations Meramec NW STACK Inventory Base case: 4 wells per section in Meramec and Lower Osage Gross locations: ~1,950 Net locations: ~825 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 Lower Osage Woodford Hunton Formation Base Case Wells Upside Case Wells Total Meramec U. Osage L. Osage Woodford Additional Potential 25

26 Arkoma - 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 (1) Assumed Pricing: Gas: $2.85/Mmbtu; Oil: $65.00/bbl 26

27 Arkoma Offset Activity Rig Activity Permit Analogs Sherry Pad (BP) 3 Wells drilled in ,174 Average Lateral Length 5,802 Mcfd Average Peak IP-30 Pauline Pad (Trinity Operating) 4 Wells drilled in ,298 Average Lateral Length 6,311 Mcfd Average Peak IP-30 Emma Pad (Trinity Operating) 2 Wells drilled in ,923 Average Lateral Length 6,810 Mcfd Average Peak IP-30 Stewart Pad (BP) 4 Wells drilled in ,448 Average Lateral Length 4,621 Mcfd Average Peak IP-30 Ina Pad (BP) 3 Wells drilled in ,646 Average Lateral Length 5,656 Mcfd Average Peak IP-30 Hunt-Garrett Pad (BP) 3 Wells drilled in ,099 Average Lateral Length 8,679 Mcfd Average Peak IP-30 Binns Pad (BP) 4 Wells drilled in ,288 Average Lateral Length 6,995 Mcfd Average Peak IP-30 Sandmann 1H-9X Well (Newfield) Drilled in ,709 Lateral Length 12,095 Mcfd Average Peak IP-30 Phillips Pad (BP) 2 Wells drilled in ,927 Average Lateral Length 6,854 Mcfd Average Peak IP-30 Payden 1H-12XX Well (Newfield) Drilled in ,807 Lateral Length 14,856 Mcfd Average Peak IP-30 HB 1-11 Well (Canyon Creek) Drilled in ,099 Lateral Length 2,876 Mcfd Average Peak IP-30 Ellis Pad (Newfield) 2 Wells drilled in ,619 Average Lateral Length 12,674 Mcfd Average Peak IP-30 LDC Pad (Canyon Creek) 2 Wells drilled in ,984 Average Lateral Length 2,607 Mcfd Average Peak IP-30 Persall 1-8/17H Well (Bravo) Drilled in ,934 Lateral Length 6,783 Mcfd Average Peak IP-30 Lackey Pad (Bravo Arkoma) 2 Wells drilled in ,515 Average Lateral Length 2,474 Mcfd Average Peak IP-30 Resh 2-8H Well (BP) Drilled in ,790 Lateral Length 6,524 Mcfd Average Peak IP-30 Bellettini Trust Pad (Bravo Arkoma) 3 Wells drilled in ,247 Average Lateral Length 4,869 Mcfd Average Peak IP-30 Smalley Pad (BP) 3 Wells drilled in ,555 Average Lateral Length 6,945 Mcfd Average Peak IP-30 Ward Pad (Bravo Arkoma) 2 Wells drilled in ,883 Average Lateral Length 7,619 Mcfd Average Peak IP-30 Note: Rig and permit data sourced from DrillingInfo as of July 30, 2018 McEntire Pad (Bravo Arkoma) 3 Wells drilled in ,177 Average Lateral Length 4,421 Mcfd Average Peak IP-30 Bowen Pad (BP) 3 Wells drilled in ,354 Average Lateral Length 6,786 Mcfd Average Peak IP-30 27

28 Arkoma - 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 Jefferson 1 Mile Caney Mayes Formation Cromwell Base Case Wells Upside Case Wells Total Additional Potential Caney Mayes Woodford Woodford Hunton 28

29 East Texas Overview Personville East Texas Position Overton Approximately 110,000 net acres mainly in Limestone, Freestone, and 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 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 29

30 East Texas Personville Field Bossier target of incised valley fill sandstones 3D seismic tied to well control using waveform modeling combined with amplitude mapping provide high probability in prediction of IVF sand presence Current inventory of 27 net Bossier wells Cotton Valley Lime infill horizontal developement provides additional upside Personville Type Log Bossier IVF Bossier Incised Valley Fill (IVF) Sandstones Cross Section Cotton Valley Lime Buckner 30

31 East Texas Overton Field Overton Field is currently a vertical producing Cotton Valley field Type Log There have been 72 offset horizontal wells drilled in the Cotton Valley Taylor Sands Significant amount of offset horizontal activity generating attractive returns at current prices Approximately 45 net horizontal development locations identified within Riviera's acreage position Economics of development benefit from high liquid yields of approximately 30 bbls/mmcf Cotton Valley Sands Taylor L1 Taylor L2 Taylor L3 Taylor L4 31

32 Overton Offset Activity Rig Activity Permit Analogs McElroy-Swann Moore 1H (Tanos) Completion Date: 7/3/2017 Peak IP-30: 5.7 MMCFD LL: 6,737 McElroy A - Wilkinson 1H (Tanos) Completion Date: 3/23/2017 Peak IP-30: 6.1 MMCFD LL: 4,803 Maldonado-Murray 1H (Tanos) Completion Date: 3/20/2018 Peak IP-30: 5.8 MMCFD LL: 4,910 McElroy A - Murray 1H (Tanos) Completion Date: 3/12/2018 Peak IP-30: 3.5 MMCFD LL: 4,478 Pond-Gray 1H (Tanos) Completion Date: 6/4/2017 Peak IP-30: 5.4 MMCFD LL: 3,837 Pond 2H (Tanos) Completion Date: 5/24/2017 Peak IP-30: 7.1 MMCFD LL: 4,950 Wilkinson Gas Unit 1H (Jamex) Completion Date: 07/17/2018 Peak IP-30: Too Recent LL: 6,524 Johnson Gas Unit 2H (Jamex) Completion Date: 6/4/2018 Peak IP-30: Too Recent LL: 6,914 CV Taylor Sand Gross Isopach Map Burns 3HR (Valence) Completion Date: 6/9/2018 Peak IP-30: Too Recent LL: 5,313 Burns-Poole 1H (Valence) Completion Date: 6/10/2018 Peak IP-30: Too Recent LL: 7,281 Burton 2H (Jamex) Completion Date: 8/3/2017 Peak IP-30: 4.7 MMCFD LL: 5,636 Reagan-Black Stone-Wilkinson 2H (Tanos) Completion Date: 1/3/2017 Peak IP-30: 7.8 MMCFD LL: 6,807 Steele Gas Unit 1H (Jamex) Completion Date: 6/20/2018 Peak IP-30: Too Recent LL: 5,943 McElroy 3H (Valence) Completion Date: 6/5/2018 Peak IP-30: Too Recent LL: 7,675 Cecil Martin Gas Unit 1H (Jamex) Completion Date: 8/3/2017 Peak IP-30: 6.5 MMCFD LL: 6,019 RVRA s position has very thick CV Taylor Sand compared to offset results Note: Rig and permit data sourced from DrillingInfo as of July 30,

33 North Louisiana - Overview North Louisiana Position Ruston Field Approximately 100,000 net acres across northern Louisiana 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 33

34 North 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 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 Upper Poole Sand J P Graham 2H 2 Alt (RVRA) Target: Middle Poole EUR: 5.4 BCF/1,000 Lower Poole Sand Elliott Etal 1-11HC 1 (RVRA) Target: Middle Poole EUR: 3.7 BCF/1,000 Elliott Etal 1H 1 Alt (RVRA) Target: Lower Poole EUR: 1.9 BCF/1,000 Carter Etal 6H 1 Alt (RVRA) Target: Middle Poole EUR: 3.9 BCF/1,000 34

35 North Louisiana Ruston Offset Activity Rig Activity Permit Analogs Lewis HC 2 Alt (Range) Completion Date: 1/19/2017 Peak IP-30: 19 MMCFD LL: 6,522 Standifer HC 1 Alt (Range) Completion Date: 5/28/2017 Peak IP-30: 19 MMCFD LL: 6,158 Tatum HC 1 Alt (Range) Completion Date: 8/6/2017 Peak IP-30: 21 MMCFD LL: 4,800 Tatum HC 2 Alt (Range) Completion Date: 8/6/2017 Peak IP-30: 17 MMCFD LL: 7,781 Tatum HC 3 Alt (Range) Completion Date: 8/6/2018 Peak IP-30: 25 MMCFD LL: 7,816 Lamar Dowling H 2 (Range) Completion Date: 11/25/2017 Peak IP-30: 20 MMCFD LL: 8,160 Lamar Dowling H 1 (Range) Completion Date: 11/27/2017 Peak IP-30: 21 MMCFD LL: 8,247 Barnett 26-35HC 1 Alt (Range) Completion Date: 2/27/2017 Peak IP-30: 22 MMCFD LL: 10,348 Terryville/Ruston Wells Drilled Since 1/2017 & Riviera Operated Wells Autry HC 3 Alt (Range) Completion Date: 2/7/2017 Peak IP-30: 25 MMCFD LL: 8,026 Autrey HC 4 Alt (Range) Completion Date: 2/7/2017 Peak IP-30: 22 MMCFD LL: 7,952 Autry HC 2 Alt (Range) Completion Date: 2/7/2017 Peak IP-30: 24 MMCFD LL: 7,952 Elliott Etal 1H 1 Alt (LINN) Completion Date: 7/9/2017 Peak IP-30: 13 MMCFD LL: 3,797 Harrison 7-6 HC 2 Alt (N&G) Completion Date: 10/8/2017 Peak IP-30: 17 MMCFD LL: 3,367 Carter Etal 6H 1 Alt (LINN) Completion Date: 1/3/2017 Peak IP-30: 15 MMCFD LL: 4,021 Christian Etal 5-8HC 1 Alt (N&G) Completion Date: 5/7/2017 Peak IP-30: 20 MMCFD LL: 6,115 J P Graham 2H 2 Alt (LINN) Completion Date: 8/17/2017 Peak IP-30: 16 MMCFD LL: 4,403 Fallin HC 2 Alt (Range) Completion Date: 2/18/2017 Peak IP-30: 18 MMCFD LL: 10,154 Note: Rig and permit data sourced from DrillingInfo as of July 30, 2018 Burnett 35-2 HC 1 Alt (Range) Completion Date: 2/14/2017 Peak IP-30: 29 MMCFD LL: 8,752 Smith Etal HC 2 Alt (N&G) Completion Date: 8/18/2017 Peak IP-30: 45 MMCFD LL: 7,658 Elliott Etal 1-11HC 1 (LINN) Completion Date: 2/20/2016 Peak IP-30: 29 MMCFD LL: 6,503 35

36 Long-Life, Low-Decline Assets Hugoton Jayhawk Plant Michigan / Illinois Uinta

37 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 Extensive gathering infrastructure and a significant midstream / processing investment Jayhawk Plant 450 MMcf/d Capacity 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 Historical Production Trend Jayhawk Plant 450 MMcf/d Capacity 180 Net Production (Mmcfe/day) Average annual capital of ~$2 million 0 Jul-15 Nov-15 Mar-16 Jul-16 Nov-16 Mar-17 Jul-17 Nov-17 Mar-18 (1) Volumes are average daily second quarter 2018 actual production (2) Acreage as of year end 2017 Decline Rate of ~6% Natural Gas Price ($/MMBtu) $2.75 $3.00 $3.25 $3.50 $3.75 $4.00 Price Sensitivity Number of drilling locations greater than 20% ROR ,000 1,500 2,000 2,500 3,000 3,500 37

38 Hugoton - Jayhawk Plant Overview Commissioned April % 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 3 rd Party annual Adjusted EBITDA of $7MM - $10MM Jayhawk Plant Historical Throughput 300, ,000 ~170,000 mcf/d XTO / Pioneer Hugoton Acquisitions Satanta plant shutdown Berry separation ~256,000 mcf/d MMcf/day 200, , ,000 50,000 45% of total through put 55% of total through put 0 Equity Volumes Third Party Gas 38

39 Michigan / Illinois Overview Net Production of ~27 MMcfe/d (1) (97% Natural Gas, 3% Oil) Michigan/IL Position ~ 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 Decline Rate of ~4% MI Net Production (Mcfed) Average annual capital of ~$1.6 million Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 IL (1) Volumes are average daily second quarter 2018 actual production 39

40 Uinta Overview Asset Highlights ~22 MMcfe/day net production (1) Uinta Position ~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 Net Production (Mcfed) Decline Rate of ~11% Average annual capital of ~$0.166 million 5 0 Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 (1) Volumes are average daily second quarter 2018 actual production 40

41 Blue Mountain Midstream Overview

42 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 42

43 Blue 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 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 $ million (1) 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 (1) Estimate assumes $14-$16 million of annual G&A costs. 43

44 Blue Mountain Executive Management Team C. Gregory Harper President and Chief Executive Officer Most recently served as President, Gas Pipelines & Processing for Enbridge Energy from January 2014 to April 2017 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 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 David A. Weathers Executive Vice President and Chief Commercial Officer Over 35 years of energy industry experience with roles ranging from the field to executive leadership Prior to Blue Mountain, served as Vice President of Business Development for Enbridge s U.S. Gathering & Processing business unit Former Senior Director for NextEra Energy and held various roles of increasing responsibility for over 20 years with Duke Energy Brad D. Reese Executive Vice President and Chief Development & Corporate Services Officer Over 36 years of energy industry experience, with over 25 years concentrated in midstream infrastructure development Most recently was President of Enbridge Canadian Gathering & Processing, and served on the boards of Alliance Pipeline and Aux Sable companies Prior to Enbridge, held various leadership roles for over 29 years with Targa Resources, Spectra Energy and DCP Midstream Christopher T. Ditzel Chief Operating Officer Over 36 years of energy industry experience with roles in engineering / construction, operations, and commercial development Prior to Blue Mountain, served as Vice President of Commercial Operation for Enable Midstream 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 Vice President of Accounting and Finance 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 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 44

45 Blue 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 45

46 Initial 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 $ million (1) 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 (1) Estimate assumes $14-$16 million of annual G&A costs. 46

47 Blue Mountain Midstream Cryo Plant I Update State of the art cryogenic processing facility inservice 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 ONEOK Hydrocarbon providing NGL transportation from the facility Facility is fully staffed and operating 24/7 mmcf/d 300, , , , ,000 50,000 Forecasted Throughput vs. Plant Capacity 80-acre site provides ample space for additional trains to meet growing demand 0 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 Forecasted Throughput (Upper Range) 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 47

48 Merge / SCOOP Play Overview Active Rigs by Operator in Merge / SCOOP (1) Merge / SCOOP Rig Activity (1) Horizontal Drilling Permits in the Merge (2) 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

49 Customer 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 49

50 Blue Mountain Key Statistics Estimated Operating Margin (1) (in millions) Capital Forecast (2) (in millions) $160 MMcf/d $ $ $6 $1 $3 $0 Q A Q E Q E Q E Estimated Throughput MMcf / Day - Upper Range $33 $33 $96 $53 $43 $32 $75 $53 Estimated Throughput MMcf / Day - Lower Range Plant Operating Margin Estimate - Lower Range 2016A 2017A 2018E 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 (2) Field includes refrigeration facilities 1 and 2 50

51 Blue Mountain Key Takeaways Deep Midstream Expertise Experienced management team in place with proven track record of successful execution in midstream energy infrastructure Leading G&P Position Strong believers in Anadarko Basin and current asset footprint wellpositioned to capitalize on growth opportunities in prolific Merge/ SCOOP/STACK/NW STACK plays Strong Commercial Relationships Closely aligned with our key customer Roan Resources Financial Strength Aggressive ramp up in volumes and EBITDA strengthens cash flow in nearterm; secured $200 million line of credit with $70 million currently available provides funding for growth Multiple Avenues for Growth Key focus on securing future growth projects; beginning design and engineering of Cryo Plant II and evaluating other scalable business growth opportunities 51

52 Financial and Management Update

53 2018 Guidance 2019 Guidance to be Provided Following Budget Approval Q3 2018E Q4 2018E FY 2018E Net Production (MMcfe/d) Natural gas (MMcf/d) 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 (4) Excludes non cash amortization of deferred financing costs 53

54 Pro-Forma Adjusted Riviera Upstream 2018 Adjusted EBITDAX Outlook $ Riviera Resources Guidance Pro-forma Estimates Adjusted Riviera Upstream Guidance $120 $100 $52 $ in Millions $80 $60 ($23) ($26) $35 $132 $40 $94 $71 $80 $20 $45 $45 $45 $0 FY 18 Guidance Pre-Close Adjusted EBITDAX from Asset Sales (1) FY18 Operating Margin from Blue Mountain Midstream (2) Implied Riviera Upstream Pro- Forma FY 18 E Severance Expense Expected G&A Reductions (3) Pro-Forma FY18 Estimate (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 54