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2Q 2019 Investor Presentation
August 2019
2Q 2019 Investor Presentation August 2019 1 Important Disclosures - - PowerPoint PPT Presentation
2Q 2019 Investor Presentation August 2019 1 Important Disclosures Forward-Looking Statements and Risk Factors The information in this presentation includes forward-looking statements. All statements, other than statements of historical
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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.
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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
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 measure 2) Gross, operated wells that have been rig released 3) Gross, operated wells
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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
~75% of gas hedged at $2.90
growing production 15% to 22% FY 2018 to FY 2019
‒ ~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 46.5 54.1 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’19 2) 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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Liquidity Strategic
Alternatives
Results Costs
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Mad Play (4 wells) Earl (6 wells)
2Q 2019 Activity Map: 2Q 2019 results:
foot lateral
Highlight 2Q 2019 results:
foot lateral
foot lateral
24% NGLs, 37% gas) from a normalized 10,000-foot lateral
foot lateral
foot lateral
Victory Slide (3 wells)
WEST CENTRAL EAST
Red Bullet / Silver Charm (4 wells) Zenyatta (2 wells)
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Multiple zones possible where Reservoir is present Reservoir acting as one zone Multiple zones Required WEST CENTRAL EAST Merge West:
due to quality reservoir and sufficient thickness
Mayes and Woodford Merge Central:
reservoir is present and sufficient thickness
and Woodford where high quality reservoir exists Merge East:
to both Mayes and Woodford Upper Mayes Lower Mayes Upper Mayes Lower Mayes Lower Mayes Woodford Woodford
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Mad Play unit (7-well design)
Mayes
Mad Play unit:
1,601 Boe/d (44% oil, 20% NGLs, 36% gas) from a normalized 10,000-foot lateral from 4 wells
1,240 Boe/d (42% oil, 20% NGLs, 38% gas)
feet
500’ horizontal spacing between wellbores
well
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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Red Bullet / Silver Charm unit:
NGLs, 33% gas) from a normalized 10,000-foot lateral from 4 wells
9,500 feet
drilled; 800’ to 1,160’ horizontal spacing and ~200 vertical spacing between wellbores
per well
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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Earl unit (6 wells)
Mayes
Earl unit (3 Mayes wells):
Boe/d (39% oil, 24% NGLs, 37% gas) from a normalized 10,000-foot lateral for the 3 Mayes wells
Boe/d (32% oil, 24% NGLs, 44% gas)
feet
$7.4MM per well
horizontal spacing between wellbores
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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Victory Slide (2 Mayes wells):
1,170 Boe/d (67% oil, 15% NGLs, 18% gas) from a normalized 10,000- foot lateral for the 2 Mayes wells
1,091 Boe/d (64% oil, 17% NGLs, 19% gas)
completion design for rock
this area for Roan
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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Zenyatta pad (2 wells) Zenyatta:
1,104 Boe/d (32% oil, 32% NGLs, 36% gas) from a normalized 10,000-foot lateral
1,004 Boe/d (27% oil, 34% NGLs, 39% gas)
9,750 feet
~1,000’ horizontal spacing between wellbores
the Woodford
future drilling
Zenyatta
Upper Woodford Middle Woodford
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2019 Focused Activity Map: 2019 anticipated drill plans:
turned to first sales in August (3 Mayes wells)
first sales in August(3 Mayes 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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designs, co-completions and independent spacing
Woodford and Mayes to produce maximum unit efficiency within our large, contiguous acreage position
tests have demonstrated unit intensity of 5 to 8 wells will appropriately balance unit returns and per well capital efficiency
current pace
1) Operation control assumed if leasehold exceeds 37.5% working interest in a unit 2) Excludes horizontal developed locations
STACK MERGE SCOOP
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$8.5 ~$0.2 ~$0.8 $7.5 ~$0.5 ~$7.0 $0.0 $3.0 $6.0 $9.0 2018 A Drilling Reductions Completion Reductions 2019 Target 2019 Cost Reductions Current CWC
Strategic focus on reducing completed well costs
~$7MM per well
Strategic focus on reducing operating costs
Midstream began early 2Q’19, which we expect will save ~$8MM in 2019
2019 improvement in per well CWC ($ in MM) :
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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
fourth quarter 2019
$495 - $525MM, a ~34% reduction as compared to 2018 and $30MM lower from the top end of the range of previous guidance
result in ~15%-22% Y/Y production growth
risked core areas and optimal well spacing
Notes: Guidance now assumes ethane rejection for remainder of year 1) Cash G&A is a non-GAAP measure and is equal to total G&A less equity-based compensation expense and expense for allowance for doubtful accounts.
Capex ($ in MM) Production (MBoe/d)
43.7
2018 2019 (Estimate)
50.5 – 53.5 $773
2018 2019 (Estimate)
$495 – $525
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Merge is divided into 3 regions
Spacing assumptions for each region
‒ One primary target zone (Lower Mayes)
‒ Multiple zones possible (Upper Mayes, Lower Mayes, Woodford)
‒ Multiple zones (Upper Mayes, Lower Mayes, Woodford)
375’ 275’ A A’
Upper Mayes Lower Mayes Woodford
WEST
CENTRAL EAST
Hunton A A’
Gross Thickness (Mayes+Woodford)
WEST CENTRAL EAST
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2019 Guidance as of:
May 14, 2019 Ethane recovery vs rejection impact August 7, 2019 Full-Year Production (MBoe/d) 51.5 – 55.5 (~1.9) 50.5 – 53.5 Oil Mix 25.5% – 27.5%
Liquids Mix 51.5% – 59.5%
Reasons for changes in production guidance
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As of August 7, 2019:
3Q19 4Q19 Bal 2019 2020 2021
Oil Hedges Volume Hedged Daily (Bbls/d) 14,151 13,051 13,601 9,370 4,740 Average Hedge Price ($/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
$32.25 $32.25 $32.25 $24.50
Volume Hedged Daily (MMBtu/d) 80,000 80,000 80,000 30,000
($0.60) ($0.60) ($0.60) ($0.49)
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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
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 Expense
6,744 8,462 1,087 Unamortized original issue discount
1,250
Income Tax (Benefit) Expense
(22,897) 13,410
Loan 3,826
Depreciation, Depletion, Amortization & Accretion
41,572 44,893 24,601 Funded Debt $709,639
Exploration Expense
12,488 11,406 10,633 Less: Cash 5,428
Non-Cash Equity-Based Compensation
3,065 (3,222) 2,835 Net Debt $704,211
Aborted Offering Costs
1,481 3,857
(664) 50
83,642 (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
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Investor Relations Alyson Gilbert Phone: 405-896-3767 Email: ir@roanresources.com