Second Quarter 2019 Supplemental Presentation - Riviera Resources, Inc.
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Second Quarter 2019 Supplemental Presentation
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.
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”) .
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.
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
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
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
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
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
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/bblNorth 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 11Blue 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 12Natural 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
13Produced 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 $20 million when
initial facilities fully commissioned in early 2020
New water management project allows Blue Mountain to extend infrastructure reach and diversify service
offerings while leveraging existing staff and expertise
14Crude Oil Project – Initial Buildout
• In July 2019, executed definitive agreement with Roan
Resources to provide crude oil gathering services
• 10-year term and 89,000 net acre dedication within 9
Townships in Grady and Canadian Counties
• Initial build-out in 2019:
– Connection to new high-volume/high-potential wellpads
with LACTs/pumps supporting multi-rig program
– ~ 51 miles of crude oil gathering pipelines; two-grade
trunkline
– 60,000+ BPD total capacity to Navigator’s Glass
Mountain pipeline into Cushing, OK via Navigator’s new
terminals
• Tuttle Station – southeastern system – heavier oil
• Union City Station – northwestern system – lighter
oil
• Systems commissioned Q4 2019/Jan 2020 – consistent with
Navigator’s schedule for completion of new stations
New crude oil agreement establishes Blue Mountain as one of the few midstream companies in MidCon
providing full suite of midstream services for crude oil, natural gas and water
15Contracted Growth Outlook(1)
($ 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 $2.58/Mcf HH
162019 Capital – Summary
($ 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
172019 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 expensesPro-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 $4.4 million 19Riviera Resources – Share Buybacks
Through August 7, 2019
58,832,398
shares
($ 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 20Riviera 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) - $-
21Blue 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)
22APPENDIX
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.
24Non-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. 25Non-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. 26You can also read
