Second Quarter 2019 Supplemental Presentation - Riviera Resources, Inc.

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Second Quarter 2019 Supplemental Presentation - Riviera Resources, Inc.
Second Quarter 2019
Supplemental Presentation
Second Quarter 2019 Supplemental Presentation - Riviera Resources, Inc.
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. These
statements include, among others, statements regarding our 2019 guidance, planned capital
expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or
completed after the date hereof, future cash flows and borrowings, our strategic objectives with
respect to Blue Mountain Midstream LLC, our financial position, business strategy and other plans
and objectives for future operations. 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 our financial and operational performance and results,
low or 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 Annual Report on
Form 10-K, Quarterly Reports on Form 10-Q and other public filings. The Company undertakes 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.
Second Quarter 2019 Supplemental Presentation - Riviera Resources, Inc.
Non-GAAP Measures

Adjusted EBITDAX and Adjusted EBITDA
The non-GAAP financial measures of Adjusted EBITDAX and Adjusted EBITDA, as defined by the
Company below, may not be comparable to similarly titled measures used by other companies.
Therefore, these non-GAAP measure should be considered in conjunction with net income (loss)
and other performance measures prepared in accordance with GAAP. Adjusted EBITDAX and
Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP. Adjusted
EBITDAX and Adjusted EBITDA are measures used by Company management to evaluate the
Company's operational performance and for comparisons to the Company's industry peers.
Management believes these non-GAAP financial measures provide useful information to investors
because these non-GAAP measures, when viewed with the Company’s GAAP results and
accompanying reconciliations, provide a more complete understanding of the Company’s
performance than GAAP results alone. A reconciliation of these historical measures to the most
directly comparable GAAP measures is available in the Appendix of this presentation. The
Company does not provide reconciliation of certain non-GAAP financial measures used herein to
the most directly comparable GAAP financial measures on a forward-looking basis as it is unable
to forecast certain items that it has defined below as “Selected Items Impacting Comparability”
without unreasonable effort, due to the uncertainty and inherent difficulty of predicting the
occurrence and financial impact of and the periods in which such items may be recognized. Thus,
a reconciliation of such non-GAAP financial measures to the most directly comparable GAAP
financial measures could result in disclosure that could be imprecise or potentially misleading.
These items could be material to and have a significant impact on the Company’s results
computed in accordance with GAAP.

Selected Items Impacting Comparability
To supplement financial information presented in accordance with GAAP, management uses
additional measures known as "non-GAAP financial measures" in its evaluation of past
performance and prospects for the future. The primary additional measures used by management
are earnings before interest, taxes, depreciation and amortization, exploration costs, noncash
gains and losses on commodity derivatives, accrued settlements on commodity derivative
contracts related to current production period, share-based compensation expenses, gains and
losses on asset sales, reorganization items, and asset impairments (“Adjusted EBITDAX”) and
earnings before interest, taxes, depreciation and amortization, noncash gains and losses on
commodity derivatives, accrued settlements on commodity derivative contracts related to current
production period, share-based compensation expenses, gains and losses on asset sales, and
asset impairments (“Adjusted EBITDA”) .
Second Quarter 2019 Supplemental Presentation - Riviera Resources, Inc.
Non-GAAP Measures, continued

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.
Second Quarter 2019 Supplemental Presentation - Riviera Resources, Inc.
Riviera Resources – Recent Developments

Highlighted Accomplishments:
    Increased previously announced $100 million share repurchase authorization to a total of $150 million
    Returned over $140 million of capital to shareholders through share repurchases and tender offer since the
     beginning of the year, and over $290 million in the last twelve months
    Closed the sale of certain non-operated properties located in the Hugoton Basin for proceeds of approximately
     $31 million, and Michigan assets for proceeds of approximately $39 million, both at a premium to PDP PV-10
     value
    Ended the second quarter with a consolidated cash balance of ~$80 million and $33.5 million drawn on the Blue
     Mountain Credit Facility

Blue Mountain highlights:
    Continued its ongoing engagement with Tudor, Pickering, Holt & Co. to review strategic alternatives to unlock
     unrealized value
    Executed a crude oil gathering agreement with Roan Resources, Inc.
    Initiated water management services and moved approximately 5.1 million barrels in the second quarter
    Acquired 100% interests in Lumen Midstream Partnership, LLC in August 2019, for a total investment of less
     than $5 million

Riviera Upstream highlights:
    Outperformed second quarter upstream guidance, as provided in our May 2019 earnings release, with respect
     to adjusted EBITDAX and production, on lower capital spending
    Drilled and completed 6 NW STACK operated wells and 2 North Louisiana operated wells in the first half of
     2019 with excellent results

                                                                                                                     5
Second Quarter 2019 Supplemental Presentation - Riviera Resources, Inc.
Riviera Resources – Sum of the Parts

                                                1                                                 2           Balance                 3
                                                                                                               Sheet

                              Growth Oriented Assets         Growth Oriented Midstream business                                  Blue
Income Generating Assets                                                                                           Upstream    Mountain
                             funded by Strong Balance                                                    Cash       Credit      Credit
 requiring minimal capital                                                                                          Facility
                                      Sheet               Supported by separate management team                                 Facility

Mature / Cash-Flowing                                      Gas                              Water                                 $200
       Assets                    Growth Assets          Gathering            Crude                                               Million
                                                                                          Management
                                                           and              Gathering                      $80       $230         credit
                                    NW STACK                                               Services      Million    Million      facility
         Hugoton                    East Texas          Processing
          Uinta                                                                                           as of      credit
                                  North Louisiana                                                                               ~$33.5
                                                         Cryo I Plant                       Gathering,   6/30/19    facility    million
                               Anadarko Basin mineral                                       Treatment,
      Jayhawk Plant                                        System                                                              drawn as
                                       acres                                                                                   of 6/30/19
  Oklahoma City Building                                                                     Disposal

      Free Cash Flow
     returned through                                                   NAV Growth Realized                     Strong Balance
                                       NAV Growth
    share repurchases,                                                      or consider                          Sheet to fund
                                        Realized
     dividends and/or                                                   Consolidation, Merger,                      Growth
       tender offers                                                         JV, or Sale

                                                Shareholder Returns                                                                         6
Second Quarter 2019 Supplemental Presentation - Riviera Resources, Inc.
Riviera Upstream Assets Overview

                                                         247 MMcfe/d(1)                                      ~ 1.0 Tcfe(2)                                      12%(2)
                                                                Second Quarter 2019                                79% Natural Gas                             Approximate
                                                                  Net Production                                      18% NGL                                Base Decline Rate
      Growth Assets
      Low-Decline Assets                                                      Hugoton
                                                                 Net Production of ~104
                                                                  MMcfe/d (3)
                                                                 Base decline of ~ 4%                                                    Anadarko
                                                                 Jayhawk Plant derives
                                                                  significant value from helium                          Net Production of ~40 MMcfe/d,
                                                                  recovery and third party                                • Increased 47% over Q1 2019
                                                                  processing                                             NW STACK
                                                                                                                          • Core acreage position of ~70,000
                                                                                                                              net acres heavily concentrated in
                                                                                                                              Blaine, Major and Garfield counties,
                                                                                                                              with significant offset activity
                                                                                                                         ~6,100 net mineral Acres

                      Uinta
       Net Production of ~18 MMcfe/d
       Base decline of ~ 7%
       Non-Operated position
                                                                                                                                                    North Louisiana
                                                                                                                                          Net Production of ~41 MMcfe/d(4)
                                                                                                                                            • Increased 107% over Q1 2019
                                                                                                                                          Offsetting the Terryville Field, the
                                                                                                                                           remaining inventory has attractive
                                                                         East Texas                                                        economics

                                                             Net Production of ~44 MMcfe/d
                                                             ~ 110,000 net acres HBP
                                                             Bossier and Cotton Valley
                                                              development potential

(1)    Excludes volumes for the sale of certain non-operated Hugoton properties closed 5/31/19, the sale of properties located in Michigan closed 7/3/19, and the sale of properties located in Illinois and non-core
       North Louisiana expected to close in Q3 2019
(2)    Estimated proved developed reserves as of 7/1/2019 with updated pricing of $2.55 per MMBtu for natural gas and $60.00 per bbl for oil, adjusted for basis pricing, includes wells drilled in 2019, and excludes
       closed and pending asset sales per footnote (1)
(3)    Excludes volumes for sale of certain non-operated Hugoton properties closed 5/31/19
(4)    Excludes volumes for sale of non-core North Louisiana properties expected to close in Q3 2019                                                                                                                     7
Second Quarter 2019 Supplemental Presentation - Riviera Resources, Inc.
Riviera Upstream Pro-Forma Proved Developed Reserves(1)
                  Proved Developed Reserves as of June 30, 2019

 YE 2018 Proved                                                                                                                                                                                   Mid-Year 2019
Developed PV-10                                                         Mid-Year 2019                                                                                                               Pro-Forma
at $2.75 / MMBtu                                                         Pro-Forma                                                                                                              Proved Developed
& $60.00 / Bbl (1)(2)                                                   Adjustments                                                                                                                  PV-10 at
                                                                                                                                                                                                 $2.55 / MMBtu &
                                                                                                                                                                                                   $60.00 / Bbl
                                                                                                                                                                                                   (1)(3)(4)(5)(6)(7)(8)(9)

                            ($223)

                                                                        ($30)                                                                                                         $85
                                                                                              ($37)                  $71                 ($67)
                                                                                                                                                                $14

          $763

                             $540                  $540                                                                                                                                                    $576
                                                                        $510                  $473                                       $477                  $477                  $491

    Prior YE 2018        2019 Closed &         Pro-Forma      Rollforward to   Adjusted Basis 2019 New Wells                         Lower Pricing        Hedge Value at       Jayhawk Plant /         Pro-Forma
   Updated Pricing       Pending Asset       Updated Pricng Mid-Year 2019 (4) Differentials and  Drilled (6)                        $2.55/MMBtu &         $2.55/MMBtu &        Other Gathering        Mid-Year 2019
      PD PV-10             Sales (3)         YE 2018 PD PV-                   NGL Realizations                                       $60.00/Bbl (7)        $60.00/Bbl (8)            (9)                PD PV-10
                                                10 (2)(3)                            (5)                                                                                                               (1)(3)(4)(5)
                                                                                                                                                                                                       (6)(7)(8)(9)
    (1)   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 adjusted
          for pricing, to include helium revenue, and excludes income taxes. See “Non-GAAP Measures - PV-10” for more information.
    (2)   Pro-forma YE 2018 proved developed updated pricing PV-10 provided with first quarter earnings at pricing of $2.75 per MMBtu for natural gas and $60.00 per bbl for oil
    (3)   Represents the PV-10 of 2019 closed and pending transactions which include Arkoma assets closed 1/17/19, certain non operated Hugoton properties closed 5/31/19, Michigan assets closed 7/3/19, the
          monetization of a portion of the Company’s helium reserves in the Hugoton Basin utilizing a VPP structure closed 3/2019, and the sale of properties located in Illinois and non-core North Louisiana, expected
          to close in Q3 2019, at pricing of $2.75 per MMBtu for natural gas and $60.00 per bbl for oil
    (4)   Represents the value of estimated cash flows, discounted at 10% per year, for the period January 1, 2019 through June 30, 2019, pro-forma to exclude 2019 closed and pending asset sales
    (5)   Represents the value of estimated cash flows, discounted at 10% per year, at current basis pricing and current NGL realizations
    (6)   Represents the PV-10 of 2019 wells drilled to date, at pricing of $2.75 per MMBtu for natural gas and $60.00 per bbl for oil, adjusted for current basis pricing
    (7)   Represents the value of estimated cash flows, discounted at 10% per year of Pro-Forma Mid-Year 2019 proved developed PV-10 with pricing of $2.55 per MMBtu for natural gas and $60.00 per bbl for oil
    (8)   Represents the value of Riviera Upstream NYMEX natural gas and oil hedge positions at as of July 1, 2019 at assumed pricing of $2.55 per MMBtu for natural gas and $60.00 per bbl for oil
    (9)   Assumes 5x multiple of $17MM per year of third party operating margin, per mid-point of FY2019 guidance estimate                                                                                                    8
Second Quarter 2019 Supplemental Presentation - Riviera Resources, Inc.
Riviera Resources – Pro-Forma Sum of the
                                  Parts Value
                                 MY 2019                                                                                                                                                                     RVRA Market
                                Pro-Forma                                                                                                                                                                    Capitalization
       $800                 Proved Developed                                                                                                                                                                  assuming
                                 PV-10 at                                                                                                                                                                   $12.00 / share(3)
                             $2.55 / MMBtu &
       $700                    $60.00 / Bbl
                               (see slide 8)                                                                $46                                                                     $99
                                                                                                                                              ($62)
       $600                                                               $47                                                                                     Blue Mountain Midstream
                                                                                                                                                                   Cryo 1 gas gathering system
                                                                                                                                                                       •    Q4 2019 annualized Baseline
       $500                                                                                                                                                                 Adj. EBITDA of $46 million(2)
                                                                                                                                                                            (see slide 16)
                                                                                                                                                                   Water gathering services
                                                                                                                                                                       •    Q4 2019 annualized Baseline
$ in Millions

       $400                                                                                                                                                                 Adj. EBITDA of $12 million(2)
                                                                                                                                                                            (see slide 16)
                                                                                                                                                                   Crude Gathering system
                                                                                                                                                                                                                   $706
       $300                           $576                               $576                                                                                                      $607
                                                                                                                                                                  Upstream Inventory
                                                                                                                                                                   Anadarko Basin
       $200                                                                                                                                                        •       ~105,000 net acres HBP
                                                                                                                                                                   •       ~6,100 net mineral acres
                                                                                                                                                                   North Louisiana ~8,100 net
                                                                                                                                                                    acres HBP
       $100                                                                                                                                                        East Texas ~110,000 net
                                                                                                                                                                    acres HBP
                                                                                                                                                                   Oklahoma City office building
                  $0
                            MY 2019 Pro-Forma                Cash Balance, net of                       Q3 2019                            July 2019                   Implied Value of Other                   Market
                             Proved Developed               Riviera & Blue Mountain                   Asset Sales                        Tender Offer                          Assets                         Capitalization
                                   PV-10                      Credit Facility as of                    Estimated                        and Q3 Share
                                (see slide 8)                       6/30/19                           Proceeds (1)                       Repurchases
                                                                                                                                        through 8/7/19

                      Implied market valuation of ~ $99 million for combined Blue Mountain Midstream and
                                         Upstream inventory is significantly discounted
                (1)   Estimated proceeds from the sale of properties located in Michigan closed 7/3/19, and the sale of properties located in Illinois and non-core North Louisiana expected to close in Q3 2019
                (2)   Q4 2019 annualized Baseline Adjusted EBITDA provided as illustrative scenario only and not intended to represent management’s forecast of actual or anticipated results and based on the assumptions set
                      forth in the footnotes on slide 16
                (3)   Market capitalization of approximately 58.8 million shares outstanding as of 8/7/2019
                                                                                                                                                                                                                                 9
Second Quarter 2019 Supplemental Presentation - Riviera Resources, Inc.
Anadarko Basin

      Anadarko Basin Leasehold Position
                                                                                      •   Approximately 105,000 net leasehold acres throughout the
                                                                                          Anadarko Basin

                                                                                      •   Approximately 70,000 net acres in NW STACK Core area
                                                                                           – Current development area
                                                                                           – Acreage is ~98% HBP and ~75% operated(1)
                                                                                           – Acreage located in black oil window
                                                                                           – Relatively shallow drilling depths of ~7,500 – ~9,500
                                                                                               feet

                                                                                      •   Current net production ~6,700 Boepd (~38% oil)
                                                                                           – Approximately 66% operated
                                                                                           – Approximately 2,500 Boepd of current net production
                                                                                                from 6 recent operated horizontal wells (~56% oil)

                                                                                      •   Recent results from 2019 drilling program
                                                                                           – Average gross IP30 rate of 6 well program is
                                                                                               approximately 670 Boepd (~55% oil and ~72% liquids)
                                                                                           – Single mile laterals with target capital cost of $4.9
                                                                                               million - $5.2 million, which is expected to generate a
                                                                                               30% - 40% IRR and PVI > 1.5(2)

                                                                                      •   Total net mineral acres of ~6,100
                                                                                           – Approximately 2,150 net mineral acres in the core of
                                                                                                 the Merge play in Grady county

                                                                                      •   Misunderstood acreage and depressed pricing provides
                                                                                          potential consolidation opportunity

               NW STACK Core Area                                   2019 New Drills
(1)   Operation control assumed if leasehold >/= 200 acres in a section                                                                              10
(2)   Assumed Pricing: Gas: $2.75/MMbtu; Oil: $60.00/bbl
North Louisiana

                                                           •   Approximately 8,100 net acres across northern
                        North Louisiana Leasehold              Louisiana
                                                                – Acreage is ~99% HBP

                                                           •   Current focus area in the Ruston Field
                                                                – Ruston field is direct offset to prolific
                                                                    Terryville field
                                                                – Significant undeveloped resources in the
                                                                    Upper and Lower Red Sand formations

                                                           •   Recent results from 2019 drilling program
                                                                – Completed 2 well operated drilling pad
                                                                – Average capital cost ~$6.2 million
                                                                – Average gross IP30 ~20 Mmcfe/d
                                                                – Expected IRR >100% and PVI > 3.0(1)
                                                                – Payback less than 12 months

                  2019 New Drills

(1)   Assumed Pricing: Gas: $2.75/MMbtu; Oil: $60.00/bbl                                                      11
Blue Mountain – YTD 2019 Highlights

                                                •    Average natural gas throughput of 118 MMcf/d in 1H 2019
             Natural Gas                        •    Connected 18 wells and 13 wells turned to sales on Blue Mountain system in 1H 2019
             Gathering &                        •    Expect 22 wells turned to sales on Blue Mountain system between Q3 – Q4 2019
             Processing                         •    Acquired Lumen Midstream Partnership, LLC in August 2019, securing over 15 new customers and
                                                     incremental volumes to the cryo plant by Q4 2019

                                                •   Hauled 5.1 MM barrels for Roan Resources and third-party customer in Q2 2019
          Produced Water                        •   38 miles of water pipe installed in Q2 2019; first wells connected in July 2019
           Management                           •   Acquired land and permits for two SWDs; expect completion of at least one SWD in Q3 2019
             Services                           •   Reduced capex by ~20% after identifying more capital efficient treating/recycling technology

                                                • In July 2019, executed definitive agreement with Roan Resources to provide crude oil gathering
               Crude Oil                          services (89,000 net acre dedication; 10-year term; 100% fee-based)
               Gathering                        • Commenced construction with initial build-out in 2H 2019/Q1 2020

                                                • Q4 2019 annualized Baseline Adjusted EBITDA of $58 million(1)
                                                • ~$34 million drawn from credit facility, with $155 million of available capacity as of June 30, 2019
            Financial and                       • Launched Open Season for water and crude gathering to offer remaining initial build capacity to
                Other                                prospective third-party producers
                                                • Progressing engagement with Tudor, Pickering, Holt & Co. to develop strategic alternatives to
                                                     unlock unrealized value

          Blue Mountain providing full suite of midstream services for natural gas, crude oil and water;
                   building momentum to become a top tier midstream enterprise by 2020
(1)   Q4 2019 annualized Baseline Adjusted EBITDA provided as illustrative scenario only and not intended to represent management’s forecast of actual or anticipated results and based on the assumptions set
      forth in the footnotes on slide 16                                                                                                                                                                         12
Natural Gas System – Overview

•   Second quarter of 2019 average natural gas throughput
    of 120 MMcf/d
•   Recently acquired Lumen system will add over 5 MMcf/d
    in Q3 2019 with volumes redirected to Cryo plant in Q4
    2019
•   95,000 MMBtu/d of residue gas marketed to firm
    transport and firm sales agreements, locking in
    competitive pricing for remainder of 2019
•   Current system consists of more than 120 miles of
    natural gas pipelines in place, with 123 wells connected
•   7,500 HP of additional compression planned at second
    booster station to be completed by year end 2019
•   Connected to major pipelines out of basin to liquid
    Midwest & Gulf Coast markets
     –     Interconnections into Southern Star Central,
           Enable Gas Transmission and ONEOK Gas
           Transportation pipelines
     –     ONEOK Hydrocarbon providing NGL transportation
           from the facility
              • Expect to eliminate all basis dislocation by
                 Q1 2020

         Blue Mountain system strategically positioned to provide market access for producer volumes;
                 Current footprint provides ample opportunities for growth and diversification
                                                                                                        13
Produced Water System – Overview

•     Providing water management services including hauling,
      pipeline gathering, disposal, treatment and redelivery of
      recycled water for re-use
•     Initial build out in 2019:
        –   Hauling services commenced April 2019

        –   First water gathering connections in service July 2019

               •   Projecting to have over 90 miles of produced
                   water gathering pipelines, connecting to 10 well
                   pads as of August 2019

        –   Multiple owned and operated SWDs planned along
            system

               •   Acquired land and permits for two future saltwater
                   disposal wells and expect completion of at least
                   one well in Q3 2019

•     Estimated $47 million of capital expenditures for initial build;
      $43 million to be incurred in 2019
       •    Identified more capital efficient treating/recycling
            technology, which reduces capital expenditure and
            provides Roan Resources ample recycling capacity
•     Run-rate EBITDA of approximately $18 to $20 million when
      initial facilities fully commissioned in early 2020

    New water management project allows Blue Mountain to extend infrastructure reach and diversify service
                          offerings while leveraging existing staff and expertise
                                                                                                             14
Crude Oil Project – Initial Buildout

•    In July 2019, executed definitive agreement with Roan
     Resources to provide crude oil gathering services

•    10-year term and 89,000 net acre dedication within 9
     Townships in Grady and Canadian Counties

•    Initial build-out in 2019:

       –   Connection to new high-volume/high-potential wellpads
           with LACTs/pumps supporting multi-rig program

       –   ~ 51 miles of crude oil gathering pipelines; two-grade
           trunkline

       –   60,000+ BPD total capacity to Navigator’s Glass
           Mountain pipeline into Cushing, OK via Navigator’s new
           terminals

              •   Tuttle Station – southeastern system – heavier oil

              •   Union City Station – northwestern system – lighter
                  oil

•    Systems commissioned Q4 2019/Jan 2020 – consistent with
     Navigator’s schedule for completion of new stations

    New crude oil agreement establishes Blue Mountain as one of the few midstream companies in MidCon
                providing full suite of midstream services for crude oil, natural gas and water
                                                                                                        15
Contracted Growth Outlook(1)
                                       ($ in millions)

                                                                                                                                                                     $ 58
($ in Millions)

                                                                                                                                                                     $12

                                                                         $ 35
 Baseline Adjusted EBITDA (2)

                                                                            $3

                                                                                                                                                                     $46

                                                                           $32

                                             BASELINE 1H 2019 ANNUALIZED (3)                                                           BASELINE Q4 2019 ANNUALIZED (4)

                                                                                    Gas Gathering & Processing                                 Water
          (1)                   Illustrative scenario only and not intended to represent management’s forecast of actual or anticipated results and based on the assumptions set forth in the footnotes
          (2)                   Dollar amounts shown above have been rounded and are approximate
          (3)                   1H 2019 annualized assumes the following: Q2 2019 adjusted EBITDA from water services annualized for four quarters; Gas Gathering & Processing based upon average actual volume of 118
                                MMcf/d and assumes Mont Belvieu pricing; 13 wells turned to sales on Blue Mountain system in 1H 2019; assumes $21.17/Bbl NGL, $57.36/Bbl WTI and $2.89/Mcf HH, and excludes the
                                impact of hedges
          (4)                   Q4 annualized based upon forecasted average wellhead volume of 143 MMcf/d and assumes Mont Belvieu pricing; assumes 22 wells turned to sales between Q3 – Q4 2019; assumes
                                $23.42/Bbl NGL, $60.13/Bbl WTI and $2.58/Mcf HH
                                                                                                                                                                                                                         16
2019 Capital – Summary
          ($ in millions)

          Upstream - $68 Million Capital               Blue Mountain - $120 Million Capital

                                                                    Acquisition
                                                                         &
                                                                    Integration                                 Merge
                                                                        $5                                       $32
                                                        Water
                                            NW         System                        Gas
                                           STACK         $43                      Gathering
                      Drilling    N LA
Seismic                                     $44                                       &
                                   $9
  $6
                       $53                                                        Processing
                                                                                     $54                        NW
                                                                                                              STACK(1)
                                                                 Crude                                          $22
                                                                 System
Leasing                                                            $18
  $2

                                                   (1) Blue Mountain expects to be reimbursed majority of its capital dollars
                                                   incurred in NW STACK by Q4 2019 through capital reimbursement agreement
                                                   with producer

                                                                                                                                17
2019 Guidance – Upstream
      Upstream
                                                                                                        Q3 2019E                            FY 2019E
      Net Production (MMcfe/d)                                                                          233 – 255                           240 – 270
               Natural gas (MMcf/d)                                                                     185 – 205                           195 – 220
               Oil (Bbls/d)                                                                           1,900 – 2,100                       1,500 – 1,800
               NGL (Bbls/d)                                                                           6,000 – 6,300                       6,000 – 6,500

      Other revenues, net (in thousands) (1)                                                         $ 7,000 - $ 9,000                 $ 36,000 – $ 40,000
               Helium revenues                                                                      $ 4,500 – $ 5,500(2)              $ 20,000 – $ 22,000(3)
               Jayhawk / Other                                                                       $ 2,500 – $ 3,500                 $ 16,000 – $ 18,000

      Costs (in thousands)                                                                          $ 36,500   – $ 41,500             $ 165,000 – $ 175,000
                Lease operating expenses                                                            $ 17,000   – $ 19,000              $ 81,000 – $ 85,000
                Transportation expenses                                                             $ 16,000   – $ 17,000              $ 68,000 – $ 72,000
                Taxes, other than income taxes                                                       $ 3,500   – $ 5,500               $ 16,000 – $ 18,000

      Adjusted general and administrative expenses (4)                                               $ 8,500 – $ 9,500                 $ 32,000 – $ 35,000
      General and administrative – severance expenses                                                 $1,500 - $2,000                    $1,500 - $2,000

      Costs per Mcfe (Mid-Point)                                                                          $ 1.75                              $ 1.82
               Lease operating expenses                                                                   $ 0.80                              $ 0.89
               Transportation expenses                                                                    $ 0.74                              $ 0.75
               Taxes, other than income taxes                                                             $ 0.21                              $ 0.18

      Targets (Mid-Point) (in thousands)
               Adjusted EBITDAX                                                                          $ 19,000                           $91,000
               Helium VPP interest expense payments                                                      $ 1,000                            $ 3,000
               Helium VPP principal payments                                                             $ 2,700                            $ 8,000
               Capital Expenditures                                                                      $ 9,000                            $ 68,000

      Weighted Average NYMEX Differentials
              Natural gas (MMBtu)                                                                   ($ 0.55) – ($ 0.40)                 ($ 0.40) – ($ 0.30)
              Oil (Bbl)                                                                             ($ 2.40) – ($ 1.40)                 ($ 1.70) – ($ 1.10)
              NGL price as a % of crude oil price                                                      24% – 30%                           28% – 34%

      Unhedged Commodity Price Assumptions                                                 Jul 19          Aug 19           Sept 19             2019E
             Natural gas (MMBtu)                                                           $2.29            $2.22            $2.20               $2.59
             Oil (Bbl)                                                                     $57.75          $55.88           $55.88              $56.82
             NGL (Bbl)                                                                     $15.34          $14.86           $14.83              $17.79
(1)       Includes other revenues and margin on marketing activities
(2)       Includes helium revenues from the VPP Interests of approximately $3.7 million
(3)       Includes helium revenues from the VPP Interests of approximately $14.6 million                                                                       18
(4)       Excludes share-based compensation expenses
Pro-Forma Riviera Upstream
                               2019 Adjusted EBITDAX Outlook
                                 Prior 2019                                                                                                                                                           2019
                                  Riviera                                                                                                                                                            Riviera
                                 Upstream                                                                                                                                                           Upstream
                                 Guidance                                                                                                                                                           Guidance

            $100                     $95                                                                                                                                                                 $91
                $90
                                     $15                                                                                                                                  $7
                                                                     ($21)                                                                                                                               $15
                $80                                                                                                                     $11
$ in Millions

                                                                                                       ($1)
                $70

                $60

                $50

                $40                                                                                                                                                      $84
                                      $80                                                                                                                                                                $76
                                                                      $74                                                               $73
                $30

                $20

                $10

                 $0
                                Prior FY19                      Lower Pricing             Michigan and Pending                    Performance                     Q3-Q4 2019E                     Current FY19
                               Guidance (1)                                               Q3'19 Asset Sales (2)                   Q2 2019 (3)                     Performance                     Guidance (1)

                (1)   Guidance provided with first quarter earnings; Includes ~ $14.6 million estimated helium revenues from wells included in VPP structure
                (2)   Represents Adjusted EBITDAX before closing for the sale of properties located in Michigan closed on 7/3/2019, properties located in Illinois expected to close in Q3 2019, and certain non-core
                      properties located in North Louisiana expected to close in Q3 2019
                (3)   Includes a reduction to taxes, other than income taxes costs for non-recurring refund of Texas sales and use tax, net of professional service claim fees, of approximately $4.4 million           19
Riviera Resources – Share Buybacks
                    Through August 7, 2019
                                                                                                                                                                              58,832,398
                                                                                                                                                                                shares
                                                                                          ($ in millions)                                                                    outstanding
               $300
                                                                                                                                                             $40
               $250

               $200                                                                                                                $100

               $150                                                                                                                                                               $292
                                                                      $19
                                                                                                                                                            $252
               $100
                                                                                                    $152                           $152
                                     $133                            $133
                 $50

                   $0
                           Tender Offer closed             2018 Open Market               Aggregate Shares               2019 Repurchases             Tender Offer closed   Aggregate Shares
                            October 23, 2018               Repurchases and                Repurchased 2018                                               July 16, 2019        Repurchased
                                                           Employee Liquidity                                                                                                   through
                                                              Program(1)                                                                                                    August 7, 2019 (1)
       Number of
                                     6,062,179                       973,602                      7,035,781                      7,765,609                 2,666,666           17,468,056
        Shares
      Average Price
                                      $ 22.00                        $ 19.25                        $ 21.62                        $ 12.90                  $ 15.00              $ 16.73
        Per Share

       Riviera has returned over $290 million to shareholders in past 12 months
(1)    Employee liquidity program repurchases represents 27,623 vesting restricted stock units of RVRA settled in cash prior to shares being issued                                              20
Riviera Upstream Commodity Hedge Portfolio
          (As of August 1, 2019)

                                                      2019                              2020
                                             Volume       Average Price        Volume      Average Price
Natural Gas
                                           (MMMBtu/d)      (per MMBtu)       (MMMBtu/d)     (per MMBtu)
Swaps                                          141             $ 2.88            30            $ 2.82
Collars                                         20         $ 2.75 - $ 3.00        -              $-

                                                        2019                             2020
                                             Volume         Average Price     Volume        Average Price
Oil
                                             (Bbls/d)         (per Bbl)       (Bbls/d)        (per Bbl)
Swaps                                         1,000            $ 64.32          500            $ 64.63

                                                      2019                              2020
                                             Volume       Average Price        Volume      Average Price
Natural Gas Basis Differential positions
                                           (MMMBtu/d)      (per MMBtu)       (MMMBtu/d)     (per MMBtu)
PEPL                                           70            ($ 0.64)            20           ($ 0.45)
NWPL                                           10            ($ 0.61)             -              $-

                                                                                                            21
Blue Mountain Commodity Hedge Portfolio
          (As of August 1, 2019)

                                                                        2019
                                                             Volume        Average Price
 Natural Gas
                                                           (MMMBtu/d)       (per MMBtu)
 Swaps                                                         15               $ 2.81
                                                             Volume        Average Price
 Oil
                                                             (Bbls/d)         (per Bbl)
 Swaps                                                         98              $ 66.60
                                                             Volume        Average Price
 Natural Gas Basis Differential positions
                                                           (MMMBtu/d)       (per MMBtu)
 Southern Star TX OK KS                                         5              ($ 0.57)
 Enable Basis Swaps                                             5              ($ 0.23)

NGL Positions:                                                          2019
Fixed price swap (Mont Belvieu ethane):
  Hedged volume (gallons/d in thousands)                                 126
  Average price ($/gallon)                                              $ 0.34
Fixed price swap (Mont Belvieu propane):
  Hedged volume (gallons/d in thousands)                                 42
  Average price ($/gallon)                                              $ 0.68
Margin spread (Mont Belvieu propane and Conway propane):
  Hedged volume (gallons/d in thousands)                                 63
  Average price ($/gallon)                                          ($ 0.07)
Margin spread (Mont Belvieu pentane and Conway pentane):
  Hedged volume (gallons/d in thousands)                                 63
  Average price ($/gallon)                                          ($ 0.09)

                                                                                           22
APPENDIX
Non-GAAP Reconciliations – 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.

The following presents a reconciliation of net income (loss) to adjusted EBITDAX:
                                                                               Three Months Ended
                                                                                       June 30,               Six Months Ended June 30,
                                                                               2019             2018             2019          2018
                                                                                                    (in thousands)
 Net (loss) income                                                          $     (6,676) $         7,197 $          6,050 $      78,136
 Plus (less):
  Loss (income) from discontinued operations                                            —           1,758               —        (34,573)
  Interest expense, net of amounts capitalized                                      2,103              584           3,074           988
  Income tax (benefit) expense                                                    (2,047)          13,336            2,446        64,875
  Depreciation, depletion and amortization                                        23,181           21,980           44,953        50,445
  Exploration costs                                                                   969               53           2,207         1,255
 EBITDAX                                                                          17,530           44,908           58,730       161,126
 Plus (less):
    Noncash (gains) losses on commodity derivatives                             (14,552)            6,955           (4,216)       17,491
    Accrued settlements on commodity derivative contracts related to
    current production period (1)                                                   (663)              935          (1,028)        1,568
    Share-based compensation expenses                                               3,680          58,188            9,987        75,225
    Losses (gains) on sale of assets and other, net (2)                             9,839        (100,928)         (18,786)     (207,260)
    Reorganization items, net (3)                                                     424           1,259              472         3,210
    Impairment of assets held for sale                                            18,390                —           18,390            —
 Adjusted EBITDAX                                                           $     34,648 $         11,317 $         63,549 $      51,360

     (1)   Represent amounts related to commodity derivative contracts that settled during the respective period (contract terms had expired) but cash had not been received as of the end of the period.
     (2)   Primarily represent gains or losses on the sale of assets, earnings from equity method investments and gains or losses on inventory valuation.
     (3)   Represent costs and income directly associated with the predecessor’s filing for voluntary reorganization under Chapter 11 of the U.S. Bankruptcy Code since the petition date, and also include
           adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined.
                                                                                                                                                                                                              24
Non-GAAP Reconciliations – Adjusted EBITDAX
              and Adjusted EBITDA
The non-GAAP financial measures of adjusted EBITDAX and adjusted EBITDA, as defined by the Company, may not be comparable to similarly titled measures
used by other companies. Therefore, these non-GAAP measures should be considered in conjunction with net income (loss) and other performance measures
prepared in accordance with GAAP. Adjusted EBITDAX and adjusted EBITDA should not be considered in isolation or as a substitute for GAAP.

Adjusted EBITDAX and adjusted EBITDA are measures 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.

The following presents a reconciliation of net income (loss) to adjusted EBITDAX and adjusted EBITDA:

                                                                                                                                           Three Months Ended June 30, 2019
                                                                                                                                                     (in thousands)
                                                                                                                                                                        Blue
                                                                                                                                        Consolidated    Upstream
                                                                                                                                                                     Mountain

    Net (loss) income                                                                                                               $              (6,676) $              (7,308)       $             632
    Plus (less):
     Interest expense                                                                                                                                2,103                  1,748                     355
     Income tax benefit                                                                                                                            (2,047)                (2,047)                      —
     Depreciation, depletion and amortization                                                                                                      23,181                 20,970                    2,211
    EBITDA                                                                                                                                         16,561                 13,363                    3,198
     Exploration costs                                                                                                                                 969                    969                      —
    EBITDAX                                                                                                                                        17,530                 14,332                    3,198
    Plus (less):
       Noncash (gains) losses on commodity derivatives                                                                                           (14,552)               (15,282)                      730
       Accrued settlements on commodity derivative contracts related to current
                                                                                                                                                      (663)                     97                  (760)
       production period (1)
       Share-based compensation expenses                                                                                                            3,680                  1,770                    1,910
       Losses on sale of assets and other, net (2)                                                                                                  9,839                  9,030                      809
       Reorganization items, net (3)                                                                                                                  424                    424                       —
       Impairment of assets held for sale                                                                                                          18,390                 18,390                       —
    Adjusted EBITDAX / Adjusted EBITDA                                                                                              $              34,648 $               28,761        $           5,887
     (1)   Represent amounts related to commodity derivative contracts that settled during the respective period (contract terms had expired) but cash had not been received as of the end of the period.
     (2)   Primarily represent gains or losses on the sale of assets, earnings from equity method investments and gains or losses on inventory valuation.
     (3)   Represent costs and income directly associated with the predecessor’s filing for voluntary reorganization under Chapter 11 of the U.S. Bankruptcy Code since the petition date, and also
           include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined.                    25
Non-GAAP Reconciliations – Adjusted EBITDAX
              and Adjusted EBITDA (continued)
The non-GAAP financial measures of adjusted EBITDAX and adjusted EBITDA, as defined by the Company, may not be comparable to similarly titled measures
used by other companies. Therefore, these non-GAAP measures should be considered in conjunction with net income (loss) and other performance measures
prepared in accordance with GAAP. Adjusted EBITDAX and adjusted EBITDA should not be considered in isolation or as a substitute for GAAP.

Adjusted EBITDAX and adjusted EBITDA are measures 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.

The following presents a reconciliation of net income (loss) to adjusted EBITDAX and adjusted EBITDA:
                                                                                                                                             Six Months Ended June 30, 2019
                                                                                                                                                      (in thousands)
                                                                                                                                                                         Blue
                                                                                                                                         Consolidated    Upstream
                                                                                                                                                                       Mountain

    Net income (loss)                                                                                                                $                6,050 $               8,487        $        (2,437)
    Plus (less):
     Interest expense                                                                                                                                3,074                  2,459                      615
     Income tax expense                                                                                                                              2,446                  2,446                       —
     Depreciation, depletion and amortization                                                                                                       44,953                 40,529                    4,424
    EBITDA                                                                                                                                          56,523                 53,921                    2,602
     Exploration costs                                                                                                                               2,207                  2,207                       —
    EBITDAX                                                                                                                                         58,730                 56,128                    2,602
    Plus (less):
       Noncash (gains) losses on commodity derivatives                                                                                              (4,216)               (8,665)                    4,449
       Accrued settlements on commodity derivative contracts related to current
                                                                                                                                                    (1,028)                      51               (1,079)
       production period (1)
       Share-based compensation expenses                                                                                                             9,987                  4,000                   5,987
       (Gains) losses on sale of assets and other, net (2)                                                                                        (18,786)               (19,595)                     809
       Reorganization items, net (3)                                                                                                                   472                    472                      —
       Impairment of assets held for sale                                                                                                           18,390                 18,390                      —
    Adjusted EBITDAX / Adjusted EBITDA                                                                                               $              63,549 $               50,781        $         12,768
    (1)   Represent amounts related to commodity derivative contracts that settled during the respective period (contract terms had expired) but cash had not been received as of the end of the period.
    (2)   Primarily represent gains or losses on the sale of assets, earnings from equity method investments and gains or losses on inventory valuation.
    (3)   Represent costs and income directly associated with the predecessor’s filing for voluntary reorganization under Chapter 11 of the U.S. Bankruptcy Code since the petition date, and also include
          adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined.                              26
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