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:


• Red Bullet / Silver Charm unit:


• 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):


• Zenyatta unit:


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


• 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)


• 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


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


Victory Slide Mayes

Woodford

Future wells

WEST

CENTRAL

EAST

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Southern SCOOP - Zenyatta

Zenyatta pad (2 wells)

Zenyatta:


• Average per well 90-day IP of 1,004 Boe/d (27% oil, 34% NGLs, 39% gas)


• 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

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Investor Relations

Alyson GilbertPhone: 405-896-3767Email: [email protected]

2q 2019 investor presentation · 2019-08-07 · 3 production of 50.8 mboe/d (26% oil, 29% ngls, 45%...

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