1

March 2019

4Q 2018 Investor Presentation

2

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 Current Report on Form 8-K, filed September 24, 2018 and any subsequently filed annual report on Form 10-K, 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, Net Debt and PV-10 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.

Preliminary Results

Our audit relating to the financial information included in this presentation is not yet complete. Accordingly, the information included herein is subject to change

as we complete our annual audit process.

Important Disclosures

3

Roan Snapshot

Company Overview Largest Contiguous Acreage Position in Merge

Acreage Position(Net Acres)

Merge 114,700

SCOOP 25,200

STACK 7,400

Other 24,700

Total 172,000

• 54.1 MBoe/d net production (27% oil, 31% NGLs) as of 4Q’18

• ~172,000 total net acres with ~115,000 of contiguous acreage in

the Merge

‒ ~80% of acreage is in the oil and liquids-rich windows in Merge

‒ ~72% average working interest in Merge

• YE 2018 proved reserves of 306 MMBoe, up ~32% YoY; PV-10(1):

$2.1 billion

• 4 rigs running with 3 frac crews

• 33 DUCs as of 4Q’18

• Well-capitalized balance sheet with significant financial flexibility

‒ 1.4x 4Q’18 annualized leverage ratio

‒ Well hedged for 2019 with ~90% of oil hedged at ~$60 and ~80% of gas

hedged at ~$2.90

‒ Expected to be free cash flow positive by YE 2019 while growing

production 30% FY 2018 to FY 2019

25.7

37.7 36.1

46.5

54.1

4Q'17 1Q'18 2Q'18 3Q'18 4Q'18

Average Daily Production (MBoe/d)

STACK

MERGE

SCOOP

1) PV-10 is a non-GAAP measure, please see slide 22 for a reconciliation of this measure to the most directly comparable GAAP measure; at YE18 SEC pricing.

4

Roan Acreage has Optimal Woodford Petroleum System Characteristics

Woodford Source Potential IndexWoodford Thickness

• Thicker source rock • High % liquids + gas

Woodford Maturity

• Higher maturity

Roan’s acreage is in the heart of the liquids-rich Woodford petroleum system, optimally charging the prolific Woodford and Mayes reservoirs

5

2018 Highlights

Additional highlights

• 306 MMBoe of proved reserves with a SEC PV-10(3) value of $2.1 billion• 4Q’18 LQA leverage ratio: 1.4x • Executed Water Services Agreement with Blue Mountain Midstream LLC, projected to save ~$10MM

in 2019 on an annualized basis

‒ Savings to increase as gathering/recycling system is implemented

1) Adjusted EBITDAX is a non-GAAP measures, please see slide 20 for a reconciliation of this measure to the most directly comparable GAAP measure2) Gross, operated wells3) PV-10 is a non-GAAP measure, please see slide 22 for a reconciliation of this measure to the most directly comparable GAAP measure; at YE18 SEC pricing.

Metric 4Q 2018 FY 2018

Adjusted EBITDAX(1) ~$88 MM ~$299 MM

Total Production54.1 MBoe/d

(27% oil, 31% NGLs, 42% gas)43.7 MBoe/d

(27% oil, 29% NGLs, 44% gas)

Oil Production Up ~25% QoQ Up ~200% YoY

Drilled wells(2) 26 92

Lateral miles drilled(2) 48.7 143.7

Average Rigs 8 6.5

Wells turned online(2) 20 78

6

2018: Aggressive de-risking program

• Several lessons learned in 2018 will be applied in 2019

• Applying lessons retroactively to the 2018 program would lead to a substantial improvement in PVI

- Full 2018 program delivered a 1.3 PVIweighted average across 78 wells

- Implement 2018 learnings and optimizations – 2018 program delivers a 1.7 PVI(1)

• Anticipating further optimization initiatives in 2019

Optimizing 2019 Based on 2018 Program

Note: 78 gross operated wells turned online in 20181) PVI based on 2019 AFEs and $55/Bbl & $2.75/Mcf

1.3

1.7

2018 Program Optimized2018 Program

Optimizations

‒ Co-develop Woodford and

Mayes as a single flow unit

‒ Complete 3D seismic coverage and better geologic understanding of the asset

‒ Frac preloads (early results have been successful)

7

All 4Q 2018 Well Results

Normalized to 10,000-foot lateral At 90-day rate

Well Name Formation 30-day IP (Boe) 90-day IP (Boe) Oil % NGL%

DON'S RANCH 6-31-9-5 1MXH Mayes 1,662 1,518 65% 16%

FAIR PLAY 34-3-5-4 1XH Woodford 1,340 1,210 2% 44%

JACOBS 30-9-7-1MH Mayes 1,972 1,281 13% 19%

LARRY 26-23-9-5-2WXH Woodford 654 464 79% 10%

NEEDLES 24-13-10-5 1XH Woodford 675 590 52% 22%

NEEDLES 24-13-10-5 2XH Woodford 733 547 65% 16%

SPAULDING 13-7-4 1WH Woodford 1,456 1,327 36% 30%

SPAULDING 13-7-4 2MH Mayes 741 682 38% 29%

TABOREK 26-35-13-6 1MXH Mayes 1,704 1,388 53% 22%

THE DUKE 19-9-4 1H Woodford 2,273 1,810 81% 9%

THE DUKE 24-13-9-5-1XH Woodford 1,422 1,090 82% 9%

VICTORY SLIDE 21-28-9-5 1XH Mayes 1,357 1,165 49% 24%

VICTORY SLIDE 22-27-9-5 2MXH Mayes 1,372 1,308 56% 21%

VIRGINIA LIBERTY 3-34-9-5 2MXH Mayes 1,281 1,137 51% 17%

WILKERSON 34-27-13-6 1MXH Mayes 912 778 48% 24%

WILKERSON 34-27-13-6 2WXH Woodford 692 590 30% 33%

16-well average: 1,265 1,055 50% 21%

Selected Wells Removed from Average due to improper co-development of the Mayes and Woodford intervals

DON'S RANCH 6-31-30-9-5 2WXH Woodford 415 348 63% 17%

SEABISCUIT 1-12-11-6 1WXH Woodford 563 546 21% 29%

VICTORY SLIDE 22-27-9-5 1XH Woodford 313 271 84% 7%

VIRGINIA LIBERTY 4-33-9-5 2WXH Woodford 108 74 76% 12%

All 20-well average: 1,082 906 50% 21%Note: IP rates are on a 3-stream, peak rolling 30-day or 90-day basis

8

0

10,000

20,000

30,000

40,000

50,000

0 30 60 90

Cumulative Oil Production (Normalized to 10,000’)

0%

10%

20%

30%

40%

50%

60%

70%

80%

0 30 60 90

Days

% Oil

4Q 2018 Wells Represent Oilier Mix

4Q’18 wells:

• 20 wells turned online

‒ Average 30-day IP: 1,082 Boe/d (52% oil,

20% NGLs)(1)

‒ Average 90-day IP: 906 Boe/d (50% oil,

21% NGLs)(1)

‒ Cumulative oil production at 90 days is

~15% higher compared to the wells that

came online in 1Q – 3Q

• 16 wells(2) turned online in optimized

co-development designs

‒ Average 30-day IP: 1,265 Boe/d (51% oil,

21% NGLs)(3)

‒ Average 90-day IP: 1,055 Boe/d (50% oil,

21% NGLs)(3)

‒ Cumulative oil production at 90 days is ~35% higher compared to the wells that came online in 1Q – 3Q

4Q wells (all 20 wells) average cumulative oil production1Q -3Q wells average cumulative oil production

1) Normalized to 10,000-foot lateral, average lateral length of 7,500 feet; IP rates are on a 3-stream, peak rolling 30-day or 90-day basis2) Excludes the DON'S RANCH 6-31-30-9-5 2WXH; SEABISCUIT 1-12-11-6 1WXH; VICTORY SLIDE 22-27-9-5 1XH; VIRGINIA LIBERTY 4-33-9-5 2WXH3) Normalized to 10,000-foot lateral, average lateral length of 7,000 feet; IP rates are on a 3-stream, peak rolling 30-day or 90-day basis

4Q wells (16 wells(2)) average cumulative oil production4Q wells (all 20 wells) average cumulative oil production1Q – 3Q wells average cumulative oil production

15%

35%

9

Cu

mu

lati

ve V

olu

me

(B

o)

Months

Pressure Managed Unrestricted

Rat

e (

Bo

)

Months

Pressure Managed Unrestricted

Improving Capital Efficiency Through Better Pressure Management

Rate vs. Time Comparison

Cumulative Production vs. Time Comparison

Pressure management:

• Managing bottom-hole pressure

drawdown to keep reservoir pressure

above bubble point

• Shallow decline rates with reduced IP

• Uplift in oil reserves per well

• Cumulative oil is higher after 4 to 6

months on wells

Began pressure management testing in 4Q 2018

Plan to utilize pressure management techniques on 2019 activity

3 6 9

3 6 9

10

15+ Years of Premium 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 ~8 wells will appropriately balance unit returns and per well capital efficiency

• New assumptions indicate there are over 1,300 remaining premium well locations with an average lateral length of 1.5-miles in operated footprint

• Provides 15+ years of drilling at current pace

Committed to adding premium locations each year

Based on conservative unit well intensity

Area Operated 2-mile units(1)

Operated 1-mile units(1)

Total Laterals(2)

Merge 91 52 959

SCOOP 20 25 342

STACK 1 4 25

Total Remaining Premium Locations

112 81 1,326

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 Guidance Summary

2018A 2019E

Production (MBoe/d) 43.7 56.0 – 59.0

Oil Mix 27% 26 – 28%

Liquids Mix 56% 58 – 60%

LOE ($/Boe) $2.99 $2.50 - $2.80

Cash G&A ($/Boe) $2.62 $1.80 - $2.00

Production Taxes (% of Production Revenues) 4.0% 5.2 – 5.4%

Gross Operated Spuds 92 57 – 62

Gross Operated Completed Wells 78 70 – 75

Total Capex ($MM) $773 $520 - $570

Total Well Cost(1) ($MM) $8.5 $7.5

2019 Plan Highlights

• Reducing capital activity to focus on

generating free cash flow by fourth

quarter 2019

• Development activity expected to

result in 30% Y/Y production growth

and 20% production growth from

4Q18 – 4Q19

• Capital activity anticipated to be $520

- $570MM, a ~30% reduction as

compared to 2018

• Well costs down $1MM, to $7.5MM

• Target YE19 LQA Leverage of ~1.5x

• Industry-leading balance sheet

• Strong hedge position

Notes: Assumes ethane recovery in 2Q19 – 4Q19; Cash flow projections based on $55 oil and $2.75 gas prices1) Based on 2-mile lateral

Capex ($ in MM) Production (MBoe/d)

43.7

2018 2019 (Estimate)

56.0 – 59.0$773

2018 2019 (Estimate)

$520 – $570

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1Q 2019 Production Guidance

1Q’19 Production down QoQ:

• No wells turned to sales for ~80 days from

late 4Q’18 to 1Q’19

• Halted completion activity to reset service

costs and observe new completion

techniques

• 15 gross operated wells projected to come

online in 1Q’19

‒ 14 wells to first sales in March will

average ~10 productive days in the

quarter

• Ethane rejection for January

‒ Negatively impacted production by 1.6

MBoe/d

Spuds, Completions and First Sales:10

9 9 9

7

3 34

Sep-18 Oct-18 Nov-18 Dec-18 Jan-19 Feb-19 Mar-19 Apr-19

Spuds

65

11

1

3

89

6

Sep-18 Oct-18 Nov-18 Dec-18 Jan-19 Feb-19 Mar-19 Apr-19

Completions

7

5

10

5

01

14

8

Sep-18 Oct-18 Nov-18 Dec-18 Jan-19 Feb-19 Mar-19 Apr-19

First Sales

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Reserve Summary

1) PV-10 is a non-GAAP measure, please see slide 22 for a reconciliation of this measure to the most directly comparable GAAP measure; at YE18 SEC pricing.

Note: Projections assume YE2018 SEC pricing of $65.66 WTI / $3.16 HH

PDP includes PBP reserves

Forward F&D incorporates $1,246MM of PUD development capital

PDPOi l

(MMBbls)

Gas

(Bcf)

NGL

(MMBbls)

To tal

(MMBoe)

YE17 12.4 259.2 24.0 79.6

YE18 18.7 369.7 39.9 120.2

Growth 51% 43% 66% 51%

Pr ovedOi l

(MMBbls)

Gas

(Bcf)

NGL

(MMBbls)

To tal

(MMBoe)

YE17 37.4 685.9 79.6 231.3

YE18 55.7 911.2 98.4 306.0

Growth 49% 33% 24% 32%

1P Reserves by Category BFIT PV-10(1) ($MM)

120

23

163 306 MMboe ~$2,092MM

PDP

DUC - PUDs

PUD

PDP

DUC - PUDs

PUD

• PDP Reserve Replacement: 255%• Proved Reserve Replacement: 468%• Forward F&D: $6.71/Boe

SEC

Oi l Natur a l Gas NGLs Tota l Oi l Li qui ds PV-10 PV-10

Categor y (MMBbl s) (Bcf) (MMBbl s) (MMBoe) % % ($MM) %

PDP 18.7 369.7 39.9 120.2 16% 49% $1,127 54%

DUC - PUDs 5.0 64.1 6.9 22.6 22% 53% 214 10%

PUD 32.0 477.4 51.6 163.1 20% 51% 751 36%

Tota l 55.7 911.2 98.4 306.0 18% 50% $2,092 100%

$1,127

$214

$751

(1)

14

0.7x

1.0x 1.0x

1.3x 1.4x 1.4x

1.6x 1.6x 1.8x

1.9x 2.1x

2.2x

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

1 2 3 4 5 6 7 8 9 10 11

Capitalization & Credit Metrics

Capitalization & Credit Metrics Peer 4Q'18 LQA Leverage(3)

Peer 4Q’18 PV-10(4) / Net Debt(1)(3)

1) Adjusted EBITDAX and Net Debt are non-GAAP measures, please see slide 20 for a reconciliation of these measures to the most directly comparable GAAP measure2) 4Q'18 Borrowing Base reflects amount effective from the amendment as of 3/13/193) Figures sourced from public filings and internal reports. LQA represents last quarter annualized. Peers include: CDEV, CLR, CPE, CXO, FANG, GPOR, JAG, LPI, MTDR, PE and XEC4) PV-10 based on SEC pricing YE 2018; PV-10 is a non-GAAP measure, please see slide 22 for a reconciliation of this measure to the most directly comparable GAAP measure

Roan

Roan

$MM 4Q 2018

Capitalization

CashCredit Facility Debt

Total DebtNet Debt(1)

Borrowing Base Amount(2)

Total Capitalization

$7515

$515$508$750

$2,010

Financial & Operating Metrics

Quarterly Adjusted EBITDAX(1)

LQA Adjusted EBITDAX(1)

Production (MBoe/d)YE’18 PV-10(4)

$88$35154.1

$2,092

Credit Metrics(1)

Net Debt(1) / LQA Adjusted EBITDAX(1)

PV-10(4) / Net Debt(1)

Net Debt(1) / Total Capital

1.4x4.1x25%

Liquidity

Borrowing Base(1)

(Borrowings Outstanding)(Letters of Credit)Cash

Available Liquidity

$750(515)

-7

$242

4.4x4.1x 4.1x

3.4x 3.4x 3.3x

2.8x 2.8x2.4x

2.1x

1.7x 1.7x

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

1 2 3 4 5 6 7 8 9 10 11

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Current Hedge Summary

As of March 14, 2019:

1Q19 2Q19 3Q19 4Q19 2019 2020

Oil Hedges

Volume Hedged Daily (Bbls/d) 13,814 13,057 14,151 15,051 14,022 8,370

Average Hedge Price ($/Bbl) $60.65 $60.24 $60.04 $59.91 $60.20 $60.74

Natural Gas Hedges

Volume Hedged Daily (MMBtu/d) 120,000 102,000 110,000 120,000 112,992 43,730

Average Hedge Price ($/MMBtu) $2.90 $2.94 $2.91 $2.90 $2.91 $2.64

NGL Hedges

Volume Hedged Daily (Bbls/d) 3,000 3,000 3,000 3,000 3,000 -

Average Hedge Price ($/Bbl) $32.25 $32.25 $32.25 $32.25 $32.25 -

Gas Basis Hedges

Volume Hedged Daily (MMBtu/d) 80,000 80,000 80,000 80,000 80,000 20,000

Average Hedge Price ($/MMBtu) ($0.60) ($0.60) ($0.60) ($0.60) ($0.60) ($0.53)

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Investment Thesis for Roan

Success Criteria Roan

Pure play operator with large acreage position in Merge oil and liquids-rich windows

~80% of Merge acreage is in oil and liquids-rich windows

Ample midstream availability with WTI oil pricing

Transportation costs to Cushing < $1.50 per barrel; midstream providers adding capacity

Strong base production ~54,100 Boe/d as of 4Q’18

Robust production growth with vision to free cash flowProjecting 30% YoY production growth; free cash flow by YE 2019

Superior financial metrics LQA leverage ratio: 1.4x

Top-tier, experienced in-basin operations teamSeasoned team with combined 90+ years of experience

17

Contact Information

Roan Resources:

Investor Relations

Alyson Gilbert

Phone: 405-896-3767

Email: ir@roanresources.com

18

Appendix

19

2018 Cash Margin

1) Assumes a 6:1 Bbl:MMcf ratio2) Cash G&A expense is a non-GAAP measure, which is defined as total general and administrative expense as determined in accordance with GAAP less equity-based compensation expense and reorganization

costs. Cash G&A expense should not be considered as an alternative to, or more meaningful than, total general and administrative expense as determined in accordance with GAAP and may not be comparable to other companies’ similarly titled measures.

Production Summary

1Q’18 2Q’18 3Q’18 4Q’18 FY 2018

Oil Sales (MBbls/d) 11.5 9.6 11.8 14.8 12.0

Natural Gas Sales (MMcf/d) 99.0 100.6 124.1 134.8 114.8

NGLs Sales (MBbls/d) 9.7 9.7 14.0 16.8 12.6

Total (MBoe/d)(1) 37.7 36.1 46.5 54.1 43.7

Cash Margin Summary

(in thousands, except per Boe amounts) 1Q’18 $ / Boe(1) 2Q’18 $ / Boe(1) 3Q’18 $ / Boe(1) 4Q’18 $ / Boe(1) FY 2018 $ / Boe(1)

Oil, Natural Gas and NGLs Sales Revenue(2) $100,970 $29.72 $90,567 $27.55 $120,152 $28.09 $ 128,078 $25.73 $439,767 $27.59

Cash Operating Expenses:

Production Expense $8,355 $2.46 $7,019 $2.14 $14,737 $3.44 $17,489 $3.51 $47,600 $2.99

Production Taxes 2,386 0.70 2,296 0.70 6,210 1.45 6,687 1.34 17,579 1.10

Cash General and Administrative (G&A) Expense(2) 11,728 3.46 10,251 3.12 9,371 2.39 10,617 2.13 41,967 2.62

Total Expenses: $22,469 $6.62 $19,566 $5.94 $30,318 $7.28 $34,793 $6.99 $107,146 $6.72

Cash Margin $78,501 $23.11 $71,001 $21.60 $89,834 $20.81 $93,285 $18.74 $332,621 $20.87

Cash Loss on Derivatives Contracts ($4,138) ($1.22) ($9,773) ($2.97) ($13,928) ($3.17) ($5,440) ($1.09) ($33,279) ($2.09)

Gain on Early Termination of Derivative Contracts (377) (0.11) - - 377 0.09 - - - -

Adjusted EBITDAX $73,986 $21.78 $61,228 $18.64 $76,283 $17.73 $87,845 $17.65 $299,342 $18.78

20

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 expense, depreciation, depletion, amortization and accretion, exploration expense, non-cash equity-based compensation expense, reorganization transaction costs, expense for allowance for doubtful accounts, non-cash (gain) loss 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 less cash on hand as of the date presented.

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 2018 2Q 2018 3Q 2018 4Q 2018 FY 2018 (In thousands) 1Q 2018 2Q 2018 3Q 2018 4Q 2018

Net Income (Loss) $35,081 ($22,757) ($301,240) $148,245 ($140,671) Long-Term Debt $206,639 $284,639 $394,639 $514,639

Plus Adjustments: Less: Cash (2,743) (24,376) (3,900) (6,883)

Interest Expense $1,799 $1,087 $2,092 $3,374 $8,352 Net Debt $203,896 $260,263 $390,739 $507,756

Income tax expenses - - 299,662 57,200 356,862

Depreciation, Depletion, Amortization & Accretion 21,865 24,601 37,164 40,292 123,922

Exploration Expense 7,850 10,633 11,646 13,174 43,303

Non-Cash Equity-Based Compensation 2,292 2,835 2,933 2,970 11,030

Reorganization Transaction Costs - - 873 3,704 4,577

Allowance for Doubtful Accounts 3,300 3,300

Cash (Paid) Received Upon Settlement of Derivative Contracts(1) (377) - 377 -

Non-Cash loss (gain) on Derivative Contracts 5,476 44,829 22,776 (184,414) (111,333)

Total Adjustments: $38,905 $83,985 $377,523 ($60,400) $440,013

Adjusted EBITDAX $73,986 $61,228 $76,283 $87,845 $299,342

Annualized $295,944 $244,912 $305,132 $351,380

21

Non-GAAP Reconciliations

Adjusted net income and adjusted net income per share are non-GAAP performance measures. The Company defines adjusted net income and adjusted net income per share as net (loss) income and net (loss) income per share excluding non-cash gains or losses on derivatives, gains on early terminations of derivative contracts, gain on the sale of property, exploration expenses and the income tax expense associated with our deferred tax liability as a result of the reorganization of the Company completed in September 2018. Management uses adjusted net income and adjusted net income per share as an indicator of the Company's operational trends and performance relative to other oil and natural gas companies. Adjusted net income and adjusted net income per share should not be considered an alternative to net income (loss), operating income, or any other measure of financial performance presented in accordance with GAAP or as an indicator of our operating performance.

1) Excludes cash received upon settlement of derivative contracts prior to the original contractual maturity2) Computed by applying a combined federal and state statutory tax rate of 24.3% for the period subsequent to the Reorganization. No tax effect is presented for periods prior to the Reorganization

Adjusted Net Income Reconciliation For the Three Months Ended

December 31, 2018 December 31, 2017

(in thousands) (per diluted share) (in thousands) (per diluted share)

Net Income (Loss) $ 148,245 $ 0.97 $ (10,380) $ (0.07)Adjusted for:

Loss (gain) on Derivative Contracts (178,974) (1.17) 9,182 0.06

Cash (paid) Received Upon Settlement of Derivative Contracts(1) (5,440) (0.04) 320 0.00

Exploration Expense 13,174 0.09 19,616 0.13

(Gain) Loss on Sale of Oil & Natural Gas Properties - - - -

Reorganization Transaction Costs 3,704 0.02 - -

Income Tax Expense Resulting from Reorganization 4,793 0.03 - -

Total Tax Effect of Adjustments(2) 40,661 0.27 - -

Adjusted Net Income $26,163 $0.17 $18,738 $0.12

Adjusted Net Income Reconciliation For the Twelve Months Ended

December 31, 2018 December 31, 2017

(in thousands) (per diluted share) (in thousands) (per diluted share)

Net Income (Loss) $ (140,671) $ (0.92) $ 18,457 $ 0.18

Adjusted for:

Loss (gain) on Derivative Contracts (78,054) (0.51) 6,797 0.07

Cash (paid) Received Upon Settlement of Derivative Contracts(1) (33,279) (0.22) 450 0.00

Exploration Expense 43,303 0.28 24,091 0.24

(Gain) Loss on Sale of Oil & Natural Gas Properties - - (838) (0.01)

Reorganization Transaction Costs 4,577 0.03 - -

Income Tax Expense Resulting from Reorganization 304,455 2.00 - -

Total Tax Effect of Adjustments(2) 40,090 0.26 - -

Adjusted Net Income $140,421 $0.92 $48,957 $0.49

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PV-10 is not a financial measure calculated or presented in accordance with GAAP and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. The following table reconciles the GAAP standardized measure of discounted future net cash flows to PV-10 at December 31, 2018 (in thousands):

The following table presents summary data with respect to our estimated net proved reserves as of December 31, 2018. The reserve estimates attributable to our properties as of December 31, 2018, were prepared in accordance with the rules and regulations of the SEC regarding reserve reporting.

Non-GAAP Reconciliations

PV-10

As of December 31, 2018

($ in thousands)

Standardized measure of discounted future

net cash flows$1,699,701

Present value of future income taxes

discounted at 10%$391,808

PV-10 of proved reserves $2,091,509

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Revenue Recognition Reconciliation

The Company adopted ASC 606 on January 1, 2018 using a modified retrospective approach, which only applies to contracts that were not completed

as of the date of initial application. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment. The

adoption does not have a material impact on the timing of the Company’s revenue recognition or its financial position, results of operations, net income,

or cash flows, but does impact the Company’s presentation of revenues and expenses under the gross-versus-net presentation guidance in ASU 2016-

08.

The following table shows the impact of the adoption of ASC 606 on the Company’s current period results as compared to the previous revenue

recognition standard, ASC Topic 605, Revenue recognition (“ASC 605”):

Three Months Ended December 31, 2018

Under ASC 606 Under ASC 605

(in thousands) (per Boe) (in thousands) (per Boe)

Revenues:

Oil sales $77,883 $57.27 $77,968 $57.33

Natural gas $27,100 $2.18 $35,167 $2.84

Natural gas liquid sales $23,095 $14.90 $30,286 $19.54

Operating expenses:- - $15,343 $3.08

Gathering, transportation and processing

Twelve Months Ended December 31, 2018

Under ASC 606 Under ASC 605

(in thousands) (per Boe) (in thousands) (per Boe)

Revenues:

Oil sales $275,239 $63.07 $275,399 $63.11

Natural gas $76,056 $1.82 $96,086 $2.29

Natural gas liquid sales $88,472 $19.27 $114,021 $24.83

Operating expenses:- - $45,739 $2.87

Gathering, transportation and processing

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2018 ROE and ROCE Reconciliation

ROE & ROCE For the Year Ended

December 31, 2018

($ in millions)

Adjusted Net Income $140.4

Equity $1,495.0

ROE 9.4%

Adjusted EBITDAX $299.3

Less: DD&A 123.9

Less: Exploration expense 43.3

Adjusted EBIT $132.1

Net Debt $507.8

Equity 1,495.0

Total $2,002.8

ROCE 6.6%

Return on Equity (ROE) and Return on Capital Employed (ROCE) are not financial measures calculated or presented in accordance with GAAP. The following table presents the calculation of ROE and ROCE:

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