2Q 2019 Investor Presentation · 2019-08-07 · 3 Production of 50.8 MBoe/d (26% oil, 29% NGLs, 45%...
Transcript of 2Q 2019 Investor Presentation · 2019-08-07 · 3 Production of 50.8 MBoe/d (26% oil, 29% NGLs, 45%...
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2Q 2019 Investor Presentation
August 2019
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Forward-Looking Statements and Risk Factors
The information in this presentation includes “forward-looking statements.” All statements, other than statements of historical fact included in this presentation, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this presentation, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on certain assumptions and expectations made by Roan Resources, Inc. (“Roan” or the “Company”), which reflect management’s experience, estimates and perception of historical trends, current conditions and anticipated future developments. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or anticipated in the forward-looking statements. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements found in the Company’s filings with the Securities and Exchange Commission, including its annual report on Form 10-K, and any subsequently filed quarterly reports on Form 10-Q or current reports on Form 8-K. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, or incidental to the development, production, gathering and sale of oil, natural gas and NGLs. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks.
You are cautioned not to place undue reliance on any forward-looking statements, which speak only as of the date of this presentation. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this release.
Our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or cost increases.
Non-GAAP Measures
Adjusted EBITDAX, Adjusted Net Income, Adjusted Net Income per Share, cash G&A and Net Debt are financial measures not presented in accordance with generally accepted accounting principles in the United States (“GAAP”). Reconciliations of these non-GAAP financial measures to the most directly comparable GAAP measures can be found in the appendix to this presentation.
Industry and Market Data
This presentation has been prepared by Roan and includes market data and other statistical information from sources believed by Roan to be reliable, including
independent industry publications, government publications or other published independent sources. Some data is also based on Roan’s good faith estimates,
which are derived from its review of internal sources as well as the independent sources described above. Although Roan believes these sources are reliable,
they have not independently verified the information and cannot guarantee its accuracy and completeness.
Important Disclosures
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Production of 50.8 MBoe/d (26% oil, 29% NGLs, 45% gas), up ~4% QoQ
Drilled 17 wells(2) and turned online 22 wells(3)
Drill and completion costs per foot reduced by 25% and 20%, respectively, QoQ
LOE of $2.44 per Boe, down ~28% QoQ
2Q 2019 Highlights
Enhanced liquidity by ~$100MM through term loan facility
Adjusted EBITDAX(1) of ~$79.3MM, up 9% QoQ
CAPEX of ~$114MM, down ~34% QoQ
Entered into definitive agreements for crude oil to be gathered, blended and shipped, expected to decrease crude transportation costs on gathered barrels by ~50%
1) Adjusted EBITDAX is a non-GAAP measure, please see slide [21] for a reconciliation of this measure to the most directly comparable GAAP measure2) Gross, operated wells that have been rig released3) Gross, operated wells
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Roan Snapshot
Company Overview Largest Contiguous Acreage Position in Core of Anadarko Basin
Acreage Position(Net Acres)
Merge 117,300
SCOOP 27,200
STACK 7,400
Other 30,100
Total 182,000
• ~50.8 MBoe/d current net production(1) with 26% being oil
• 3 rigs running
• 22 wells turned online 2Q’19
• 2Q’19 Adjusted EBITDAX(2) of ~$79.3MM
• ~$150 million of liquidity as of 6/30/19
• Well hedged for 2019 with over 95% of oil hedged at $60.39 and
~75% of gas hedged at $2.90
• Focused on achieving free cash flow positive by YE 2019 while
growing production 15% to 22% FY 2018 to FY 2019
• ~117,300 of contiguous acreage in the Merge
‒ ~75% of acreage is in the oil and liquids-rich windows in Merge
‒ ~66% average working interest in Merge
25.7
37.7 36.1
46.554.1
48.9 50.8
4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19
Average Daily Production (MBoe/d)
STACK
MERGE
SCOOP
1) Current net production is as of 2Q’192) Adjusted EBITDAX is a non-GAAP measure, please see slide [21] for a reconciliation of this measure to the most directly comparable GAAP measure
48 rigs running in the Anadarko Basin on this map
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• Focus on enhancing current liquidity position- Secured $100MM term loan facility
• Focus on achieving cash flow neutrality/positive by YE’19
• Focus on optimizing locations and well spacing• Focus on delivering on guidance
- 2Q’19 beat on production, CAPEX & EBITDAX
• Exploring strategic alternatives to enhance value for shareholders- Outright sale- Basin consolidation- Non-core, credit-enhancing asset divestitures
• Focus on reducing completed well costs- Currently trending at ~$7MM, below original projections
• Focus on reducing LOE and G&A- LOE down ~28% QoQ; G&A down ~22% QoQ
2019 – Focus, Focus, Focus
Liquidity
Strategic Alternatives
Results
Costs
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2Q 2019 Results
Mad Play (4 wells)
Earl (6 wells)
2Q 2019 Activity Map: 2Q 2019 results:
• All 22 gross operated wells turned online:
• Average per well 30-day IP rate of 1,165 Boe/d (42% oil, 23% NGLs, 35% gas) from a normalized 10,000-foot lateral
• Average well cost of ~$7.3 million
Highlight 2Q 2019 results:
• Mad Play unit:
• Average per well 30-day IP rate of 1,601 Boe/d (44% oil, 20% NGLs, 36% gas) from a normalized 10,000-foot lateral
• Red Bullet / Silver Charm unit:
• Average per well 30-day IP rate of 1,545 Boe/d (41% oil, 26% NGLs, 33% gas) from a normalized 10,000-foot lateral
• Earl unit (3 Mayes wells):
• Average per well 30-day IP of 1,466 Boe/d (39% oil, 24% NGLs, 37% gas) from a normalized 10,000-foot lateral
• Victory Slide (2 Mayes wells):
• Average per well 30-day IP rate of 1,170 Boe/d (67% oil, 15% NGLs, 18% gas) from a normalized 10,000-foot lateral
• Zenyatta unit:
• Average per well 30-day IP rate of 1,104 Boe/d (32% oil, 32% NGLs, 36% gas) from a normalized 10,000-foot lateral
Victory Slide (3 wells)
WESTCENTRAL
EAST
Red Bullet / Silver Charm
(4 wells)
Zenyatta (2 wells)
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Merge Cross Section
Multiple zones possible where Reservoir is present Reservoir acting as one zoneMultiple zones Required
WEST
CENTRAL
EAST
Merge West:• Multiple zones are required
due to quality reservoir and sufficient thickness
• Target Lower Mayes, Upper Mayes and Woodford
Merge Central:• Multiple zones possible where quality
reservoir is present and sufficient thickness
• Target Lower Mayes, Upper Mayes and Woodford where high quality reservoir exists
Merge East:• One primary target zone• Target Lower Mayes for access
to both Mayes and Woodford
Upper Mayes
Lower Mayes
Upper Mayes
Lower Mayes
Lower Mayes
WoodfordWoodford
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West Merge - Mad Play Unit
Mad Play unit (7-well design)Mayes
Mad Play unit:
• Average per well 30-day IP rate of 1,601 Boe/d (44% oil, 20% NGLs, 36% gas) from a normalized 10,000-foot lateral from 4 wells
• Average per well 90-day IP rate of 1,240 Boe/d (42% oil, 20% NGLs, 38% gas)
• Actual average lateral length of 6,780 feet
• 2 Woodford / 2 Mayes wells drilled; 500’ horizontal spacing between wellbores
• Average well costs of under $7MM per well
• First unit in West Merge, considerable operated running room in this area for Roan
Future units will target Upper Mayes, Lower Mayes and Woodford
Woodford
Mad Play unit
Note: Offset well rates are 30-day IP rates normalized to 10,000’
WEST
CENTRAL
EAST
Future wells
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West Merge – Red Bullet / Silver Charm
Red Bullet / Silver Charm unit:
• Average per well 30-day IP rate of 1,545 Boe/d (41% oil, 26% NGLs, 33% gas) from a normalized 10,000-foot lateral from 4 wells
• Actual average lateral length of 9,500 feet
• 2 Woodford / 2 Mayes wells drilled; 800’ to 1,160’ horizontal spacing and ~200 vertical spacing between wellbores
• Average well costs of ~$8MM per well
• Turned to first sales middle of June
Future units will target Upper Mayes, Lower Mayes and Woodford
Red Bullet / Silver Charm
WEST
CENTRAL
EAST
Red Bullet / Silver Charm unit (5-well design)
Mayes
Woodford
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Central Merge - Earl Unit
Earl unit (6 wells)Mayes
Earl unit (3 Mayes wells):
• Average per well 30-day IP of 1,466 Boe/d (39% oil, 24% NGLs, 37% gas) from a normalized 10,000-foot lateral for the 3 Mayes wells
• Average per well 90-day IP of 1,222 Boe/d (32% oil, 24% NGLs, 44% gas)
• Actual average lateral length of 10,160 feet
• Average well costs of approximately $7.4MM per well
• 3 Woodford / 3 Mayes wells; 500’-800’ horizontal spacing between wellbores
• Learning: the 3 Woodford wells were not optimal because Mayes wells communicated with the Woodford due to the Woodford wells being spaced too close to the Mayes wells
Woodford
Earl unit
Note: Offset well rates are 30-day IP rates normalized to 10,000’
WEST
CENTRAL
EAST
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East Merge - Victory Slide
Victory Slide (2 Mayes wells):
• Average per well 30-day IP rate of 1,170 Boe/d (67% oil, 15% NGLs, 18% gas) from a normalized 10,000-foot lateral for the 2 Mayes wells
• Average per well 60-day IP rate of 1,091 Boe/d (64% oil, 17% NGLs, 19% gas)
• Actual average lateral length of 9,900’
• Average well costs of ~$6MM per well
• Woodford well not optimal for unit
• Learning: suboptimal completion design for rock
• Extensive operated running room in this area for Roan
• Several strong offset operated producing wells
2Q’19 Victory Slide wells
Note: Offset well rates are 30-day IP rates normalized to 10,000’
Victory Slide Mayes
Woodford
Future wells
WEST
CENTRAL
EAST
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Southern SCOOP - Zenyatta
Zenyatta pad (2 wells)
Zenyatta:
• Average per well 30-day IP rate of 1,104 Boe/d (32% oil, 32% NGLs, 36% gas) from a normalized 10,000-foot lateral
• Average per well 90-day IP of 1,004 Boe/d (27% oil, 34% NGLs, 39% gas)
• Actual average lateral length of 9,750 feet
• 2 Woodford wells drilled with ~1,000’ horizontal spacing between wellbores
• Tested two different zones within the Woodford
• Multiple potential benches for future drilling
Zenyatta
Upper Woodford
Middle Woodford
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Anticipated Remaining 2019 Drill Schedule
2019 Focused Activity Map: 2019 anticipated drill plans:
• Activity focused in core areas of the Merge
• Barbara Campbell – completed drilling & will be
turned to first sales in August (3 Mayes wells)
• Battleship pad (3 Mayes wells)
• Big Brown pad (4 Mayes wells)
• Birdstone – completed drilling (2 Mayes wells)
• Don’s Ranch – completed drilling & will be turned to
first sales in August(3 Mayes wells)
• Duke (3 Woodford wells)
• Eight Belles (4 Mayes wells)
• Finn (3 Mayes wells)
• Gallant Fox (2 Mayes wells)
• Northern Dancer (3 Mayes well)
• Omaha (2 Woodford wells, 1 Mayes well)
• Skywalker (2 Mayes wells)
• Tater (2 Mayes wells)
• Unbridled (2 Mayes wells, 1 Woodford well)
• Whirlaway (2 Mayes wells, 1 Woodford)
• Several strong offset producing wells
Unbridled Birdstone(completed drilling)
Barbara Campbell (completed drilling)
Northern Dancer
Big Brown
Battleship
ROAN DRILL UNIT
ROAN LEASEHOLD
WEST CENTRAL EAST
Whirlaway
Skywalker & Tater
Gallant Fox
Don’s Ranch
(completed drilling)
Omaha
Finn
Eight Belles
Duke
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10+ Years of Quality Inventory
• 2018 tested Woodford and Mayes designs, co-completions and independent spacing
• 2019 program will co-develop of Woodford and Mayes to produce maximum unit efficiency within our large, contiguous acreage position
• Operated and non-operated spacing tests have demonstrated unit intensity of 5 to 8 wells will appropriately balance unit returns and per well capital efficiency
• Provides 10+ years of drilling at current pace
1) Operation control assumed if leasehold exceeds 37.5% working interest in a unit2) Excludes horizontal developed locations
STACK
MERGE
SCOOP
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2019 Cost Optimization
$8.5 ~$0.2~$0.8
$7.5 ~$0.5
~$7.0
$0.0
$3.0
$6.0
$9.0
2018 A DrillingReductions
CompletionReductions
2019 Target 2019 CostReductions
Current CWC
Strategic focus on reducing completed well costs
• ~$200k reduction in drilling costs
• Decreased drill times
• Increased equipment efficiency
• ~$800k reduction in completion costs
• Service cost reductions
• Design optimization
• In-basin sand
• Recent 2-mile well completions have come in at ~$7MM per well
• ~$500k better than 2019 target
• Further design optimization
Strategic focus on reducing operating costs
• LOE
• Water disposal agreement with Blue Mountain Midstream began early 2Q’19, which we expect will save ~$8MM in 2019
• G&A
• Focus on overall reduction of G&A costs
2019 improvement in per well CWC ($ in MM) :
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Updated 2019 Guidance Summary
May 2019 Guidance
Updated 2019 Guidance
Total Capex ($MM) $515 - $555 $495 - $525
Production (MBoe/d) 51.5 – 55.5 50.5 – 53.5
Oil Mix 25.5% – 27.5% 25.5% – 27.5%
Liquids Mix 51.5% – 59.5% 51.5% – 59.5%
LOE ($/Boe) $2.90 - $3.20 $2.80 - $3.10
Cash G&A ($/Boe)(1) (non-GAAP) $1.95 - $2.15 $2.00 - $2.20
Production Taxes (% of Production Revenues) 5.2% – 5.4% 5.2% – 5.4%
Gross Operated Spuds (Rig Released) ~60 ~60
Gross Operated Wells Turned Online ~70 ~70
2019 Plan Highlights
• Reducing capital activity to focus
on generating free cash flow by
fourth quarter 2019
• Capital activity anticipated to be
$495 - $525MM, a ~34%
reduction as compared to 2018
and $30MM lower from the top
end of the range of previous
guidance
• Development activity expected to
result in ~15%-22% Y/Y production
growth
• 2H’19 wells are focused on de-
risked core areas and optimal well
spacing
Notes: Guidance now assumes ethane rejection for remainder of year
1) Cash G&A is a non-GAAP measure and is equal to total G&A less equity-based compensation expense and expense for allowance for doubtful accounts.
Capex ($ in MM) Production (MBoe/d)
43.7
2018 2019 (Estimate)
50.5 – 53.5$773
2018 2019 (Estimate)
$495 – $525
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Appendix
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Merge is divided into 3 regions
• East – Woodford + Mayes < 275’
• Central – Woodford + Mayes = 275’ – 375’
• West - Woodford + Mayes > 375’
Spacing assumptions for each region
• East = ~5 wells/unit
‒ One primary target zone (Lower Mayes)
• Central = 5-7 wells/unit
‒ Multiple zones possible (Upper Mayes, Lower Mayes, Woodford)
• West = 8 wells/unit (potential upside)
‒ Multiple zones (Upper Mayes, Lower Mayes, Woodford)
Merge Spacing Assumptions
375’ 275’
A A’
Upper Mayes
Lower Mayes
Woodford
WEST CENTRAL EAST
Hunton
A
A’
Gross Thickness (Mayes+Woodford)
WEST
CENTRAL
EAST
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Updated Production Guidance Walk
2019 Guidance as of: May 14, 2019
Ethane recovery vs
rejection impact
August 7, 2019
Full-Year Production (MBoe/d) 51.5 – 55.5 (~1.9) 50.5 – 53.5
Oil Mix 25.5% – 27.5% - 25.5% - 27.5%
Liquids Mix 51.5% – 59.5% - 51.5% - 59.5%
Reasons for changes in production guidance
• May 2019 guidance assumed ethane recovery for June and 2H’19
• Updated guidance now reflects ethane rejection for June and 2H’19
• Ethane recovery vs. rejection impacts monthly production by ~3.3 MBoe/d;
• ~3.3 MBoe/d x 7/12 = ~1.93
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Current Hedge Summary
As of August 7, 2019:
3Q19 4Q19 Bal 2019 2020 2021
Oil Hedges
Volume Hedged Daily (Bbls/d) 14,151 13,051 13,601 9,370 4,740
Average Hedge Price ($/Bbl) $60.04 $60.74 $60.39 $60.57 $56.08
Natural Gas Hedges
Volume Hedged Daily (MMBtu/d) 110,000 120,000 115,000 43,730 9,863
Average Hedge Price ($/MMBtu) $2.91 $2.90 $2.90 $2.64 $2.86
NGL Hedges
Volume Hedged Daily (Bbls/d) 3,000 3,000 3,000 1,500 -
Average Hedge Price ($/Bbl) $32.25 $32.25 $32.25 $24.50 -
Gas Basis Hedges
Volume Hedged Daily (MMBtu/d) 80,000 80,000 80,000 30,000 -
Average Hedge Price ($/MMBtu) ($0.60) ($0.60) ($0.60) ($0.49) -
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Non-GAAP Reconciliations
Adjusted EBITDAX is a non-GAAP financial measure. We define Adjusted EBITDAX as net income (loss) adjusted for interest expense, income tax (benefit) expense, depreciation, depletion, amortization and accretion, exploration expense, non-cash equity-based compensation expense, aborted offering costs expense, severance and employee matters expense, expense for allowance for doubtful accounts, (gain) loss on sale of other assets, loss (gain) on derivative contracts, and cash (paid) received upon settlement of derivative contracts, including amounts on contracts settled prior to contract maturity. Adjusted EBITDAX is not a measure of net income (loss) as determined by GAAP. Our accounting predecessor, Roan LLC, passed through its taxable income to its owners for income tax purposes and thus, we have not incurred historical income tax expenses.
Net Debt is a non-GAAP financial measure equal to long-term debt outstanding on the credit facility and term loan, exclusive of any discounts or fees, less cash on hand.
Roan’s computations of Adjusted EBITDAX and Net Debt may not be comparable to other similarly titled measures of other companies or to such measure in our credit facility or any of our other contracts.
1) Includes cash received upon settlement of derivative contracts prior to the original contractual maturity
Adjusted EBITDAX Reconciliation Net Debt Reconciliation
(in thousands) 1Q 2019 2Q 2019 2Q 2018 (In thousands) 2Q 2019
Net Income (Loss) ($58,056) $27,246 ($22,757) Credit Facility $659,639
Plus Adjustments: Term Loan, net 44,924
Interest Expense6,744 8,462 1,087
Unamortized original issue discount on Term Loan
1,250
Income Tax (Benefit) Expense(22,897) 13,410 -
Deferred financing costs on Term Loan 3,826
Depreciation, Depletion, Amortization & Accretion41,572 44,893 24,601 Funded Debt $709,639
Exploration Expense12,488 11,406 10,633 Less: Cash 5,428
Non-Cash Equity-Based Compensation3,065 (3,222) 2,835 Net Debt $704,211
Aborted Offering Costs -2,155 -
Severance and Employee Matters -687 -
Allowance for Doubtful Accounts1,481 3,857 -
(Gain) Loss on Sale of Other Assets(664) 50 -
Loss (Gain) on Derivative Contracts83,642 (37,054) 54,602
Cash Received (Paid) Upon Settlement of Derivative Contracts(1)
5,382 7,361 (9,773)Adjusted EBITDAX $72,757 $79,251 $61,228
Annualized $291,028 $317,005 $244,912