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Results Driven. Manufacturing Focused.

Corporate Presentation

November 2014

© 2014 Sanchez Energy Corporation

Legal DisclaimersForward Looking Statements This presentation contains, and our officers and representatives may from time to time make, “forward-looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this presentation that address activities, events, conditions or developments that Sanchez Energy expects, estimates, believes or anticipates will or may occur or exist in the future are forward-looking statements. These statements are based on certain assumptions made by the company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this presentation, words such as “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model,” “strategy,” “future” or their negatives or the statements that include these words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, statements, express or implied, concerning Sanchez Energy’s future operating results and returns or Sanchez Energy’s ability to replace or increase reserves, increase production, generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although Sanchez Energy believes that the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Important factors that could cause Sanchez Energy’s actual results to differ materially from the expectations reflected in its forward-looking statements include, among others:

Sanchez Energy’s ability to successfully execute its business and financial strategies;

Sanchez Energy’s ability to replace the reserves it produces through drilling and property acquisitions;

the realized benefits of Sanchez Energy’s various acquisitions including Sanchez Energy’s Catarina acquisition referred to herein and the liabilities assumed in connection with these acquisitions;

the extent to which Sanchez Energy’s drilling plans are successful in economically developing its acreage in, and to produce reserves and achieve anticipated production levels from, its existing and future projects;

the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;

the extent to which Sanchez Energy can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling, advanced completion technologies and hydraulic fracturing;

Sanchez Energy’s ability to successfully execute its hedging strategy and the resulting realized prices therefrom;

competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;

Sanchez Energy’s ability to access the credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;

the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;

the timing and extent of changes in prices for, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;

Sanchez Energy’s ability to compete with other companies in the oil and natural gas industry;

the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;

developments in oil-producing and natural-gas producing countries;

Sanchez Energy’s ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;

unexpected results of litigation filed against Sanchez Energy;

the extent to which Sanchez Energy’s crude oil and natural gas properties operated by others are operated successfully and economically;

the use of competing energy sources and the development of alternative energy sources;

the extent to which Sanchez Energy incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; and

the other factors described under ITEM 1A, “Risk Factors,” on pages 26 through 52 of Sanchez Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013 and any updates to those factors set forth in its subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by Sanchez Energy’s forward-looking statements may not occur, and, if any of such events do, Sanchez Energy may not have correctly anticipated the timing of their occurrence or the extent of their impact on its actual results. Accordingly, you should not place any undue reliance on any of Sanchez Energy’s forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made and Sanchez Energy undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

Oil and Gas Reserves The Securities and Exchange Commission (“SEC”) requires oil and gas companies, in their filings with the SEC, to disclose “proved oil and gas reserves” (i.e., quantities of oil and gas that are estimated with reasonable certainty to be economically producible) and permits oil and gas companies to disclose “probable reserves” (i.e., quantities of oil and gas that are as likely as not to be recovered) and “possible reserves” (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). We may use certain terms in this presentation, such as “resource potential” that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. The calculation of resource potential, and any other estimates of reserves and resources that are not proved, probable or possible reserves are not necessarily calculated in accordance with SEC guidelines. Investors are urged to consider closely the disclosure in Sanchez Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013.

Non-GAAP Measures Included in this presentation are certain non-GAAP financial measures as defined under Securities and Exchange Commission Regulation G. Investors are urged to consider closely the disclosure in Sanchez Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K and the reconciliation to GAAP measures provided in this presentation.

2


Positioned to thrive in a period of volatile commodity prices

Managing activity to support economic growth and maintain financial flexibility

Balanced reserve and production weighting between liquids and natural gas

72% of reserves are liquids

Eagle Ford is Flagship Asset ~2,800+ net drilling locations

Tuscaloosa Marine Shale Upside

Ample Liquidity $896 million at 3Q14

Market Cap (1) ~$1,285 MMEnterprise Value (1) ~$2,440 MM

Sanchez Energy Overview

3

Net Acreage: ~226,000 acres1P Reserves: 125 MMBoe (2)

3Q14 Average Production: ~39,000 Boe/d

Eagle Ford Shale

Net Acreage: ~61,000 acres (3)

Tuscaloosa Marine Shale (“TMS”)

1. Based on a closing stock price of $17.38 as of 11/7/14 and includes convertible preferred stock at book value (~$269 million)2. Based on SN’s internally estimated proved reserves at 9/30/143. SN has acquired ~20,000 net acres in the TMS area of mutual interest (“AMI”) since 1/1/14 on behalf of the JV with SR Acquisition I, L.L.C. (“SR”). Under the AMI terms, SN has an obligation to offer SR an interest in the

acquired acres


Eagle Ford Shale Position

4

SN Eagle Ford Position Summary

Net Acres ~226,000

3Q14 Average Production (Boe/d) ~39,000

Operated Rigs

Non-Operated Rigs

Gross Producing Wells 458

AlexanderRanch

BriggsRanch

Hausser

Wycross

TalbuttTrust


5

Transformational Growth

At IPO(12/31/11)

Today(9/30/14)

Production •609 Boe/d •~39,000 Boe/d

Proved Reserves•6.7 MMBoe•14% PD

•~125 MMBoe (1)

•46% PD

PV-10 •$152 million •$2,082 million (1)

LTM Revenue •$15 million •$885 million (2)

LTM Adj. EBITDA •$7 million •$639 million (2)

Acreage (3) •92,000 Eagle Ford•226,000 Eagle Ford•61,000 TMS

Market Capitalization

•$0.7 billion •$1.3 billion (4)

64x

19x

14x

91x

2.5xEntered new basin

1.9x

59x

1. Based on SN’s internally estimated proved reserves at 9/30/142. LTM Revenue and Adj. EBITDA are pro forma for 12 months of ownership of Catarina and Wycross3. 2.5x growth figure represents increase in Eagle Ford Shale acreage4. Based on a closing stock price of $17.38 as of 11/7/14 and includes convertible preferred stock at book value (~$269 million)


0

25

50

75

100

125

150

12/31/11 6/30/12 12/31/12 6/30/13 12/31/13 6/30/14 9/30/14

MM

Bo

e

PD PUD

7 15

21 82%91%86%

70%

43

30%

59

58%

42%

117

56%

44%

125

54%

46%

6

Delivering Strong Results

Reserves by Product Mix (9/30/14) (1)

125 MMBoe (46% PD)

Reserves by Product Mix (9/30/14) (1) Production (Boe/d)

Revenue and Adjusted EBITDA ($MM)

Oil 47%

NGL 25%

Gas 28%

0

10,000

20,000

30,000

40,000

1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q

2012 2013 2014

$0

$50

$100

$150

$200

$250

1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q

Revenue Adj. EBITDA

2012 2013 2014

1. Based on SN’s internally estimated proved reserves at 9/30/14


Capital Expenditure & Production Guidance

7

1. Annualized preferred stock dividends and interest expense total $16.0 million and $116.9 million, respectively

Preliminary Revised

2015 Capital 2015 Capital

Budget Budget

Catarina 2.5 2.5

Cotulla / Wycross 1.5 1.5

Marquis 2.0 1.0

Palmetto 1.0 1.0

Total Eagle Ford 7.0 6.0

TMS 1.0 0.25

Total 8.0 6.25

Gross Rigs

Reflecting the downturn in oil prices, SN has revised its preliminary 2015 capital plan range downwards to $850 – $900

million, a reduction of $250 – $300 million from the previous guidance’s midpoint

Focus will be on the development drilling of SN’s existing multi-year inventory of high rate of return projects

Land position mostly held by production, preserving optionality

Expected 2015 average production of 50,000 Boe/d, a 70% increase over 2014 and a 4Q15 over 4Q14 expected increase

over 25%

Anticipated 2015 capital program expected to be fully funded through cash and cash flow from operations without utilizing

SN’s revolving credit facility (assumes average oil prices of $80 / Bbl and natural gas prices of $3.75 / MMBtu)

Metrics 4Q14 2015

Production Guidance (BOE/D)

Period Average 40,000 - 44,000 50,000

Operating Cost & Expense Guidance ($/BOE)

Oil & Natural Gas Production Expenses $9.00 - $10.00 $9.00 - $10.00

Production & Ad Valorem Taxes $3.00 - $4.00 $2.50 - $3.50

Cash G&A $3.00 - $4.00 $2.50 - $3.50

Preferred Stock Dividends & Interest Expense (1)

$8.00 - $9.00 $7.30

DD&A $26.00 - $28.00

Effective Corporate Tax Rate

~35% (100% Deferred)

Guidance


Operations

8

A Manufacturing Transformation


Tailored Programs Enhancing Returns

99

Down spacing pilots

Buda open hole lateral

development

UEF standalone, UEF/LEF

stacking overlap

Down spacing pilots, UEF/Buda

tests

Longer laterals, down spacing

pilots

Longer laterals, higher proppant

load trials

LEF/UEF stacking, radiator pattern

fracs

Higher proppant load trials in UEF, pending for LEF


Stacked Lateral Potential

1010

Upper Eagle Ford

Buda

Lower Eagle Ford Target 2

Lower Eagle Ford Target 1

Mar

qu

is

Palm

etto

Co

tulla

Wyc

ross

Co

tulla

La

Sal

le

Cat

arin

a

Development Appraisal


Manufacturing Process Drives Capital Efficiency

11

$9.5 $7.3

$12.9

$0.0

$2.0

$4.0

$6.0

$8.0

$10.0

$12.0

$14.0

$M

M

SN Competitive Advantage

Appraisal Well

Multi-Well Pad + Zipper Frac Savings

Field Development and Well Design Savings

• Multi-well pad drilling and zipper fracturing

• Walking and skidding rigs

• Segmented de-risking of the wellbore

First Order Capital Savings

• Optimized well design

• Direct sourcing of chemicals and proppant

• Demand planning and staggered dedication of services

Opportunity to drive

Competitive Advantage


Track Record of Reducing Capital

12

Prost Well Cost Reductions

$-

$2.0

$4.0

$6.0

$8.0

$10.0

Previous Operator 3Q13 4Q13 1Q14

($M

M)

Drilling Completions Facilities

5 Wells

8 Wells

7 Wells

Alexander Rach Well Cost Reductions

0%

20%

40%

60%

80%

100%

120%

$80 $90 $100

IRR

Oil Price / Bbl

$5 MM Well $6 MM Well

$7 MM Well Previous Operator

0%

20%

40%

60%

80%

$80 $90 $100

IRR

Oil Price / Bbl

$7 MM Well $8 MM Well $9 MM Well


$30.91 $24.95

$6.73 $5.55 $6.47$3.35

$9.37

$7.26

$9.21 $9.41 $7.48 $9.68

$4.78

$4.53

$4.47 $6.15 $4.21$3.07

$4.72

$10.99 $9.72$9.09

$8.41

$45.06$41.46

$31.40 $30.83$27.25

$24.51

2011 2012 2013 (1) 1Q14 2Q14 (1) 3Q14 (1)

Interest & Preferred Dividends Taxes LOE Cash G&A

Low Cost Operator With Sustained Cost Reductions

13

1. 2013, 2Q14, and 3Q14 cash G&A per Boe excludes $1.07/Boe, $0.48/Boe, and $0.26/Boe in non-recurring acquisition expenses, respectively.

Total Cash Operating Cost Including Interest & Preferred Dividends ($/Boe)


Asset Overview

14


Catarina Overview

15

Total Net Acres ~106,000

Average Working Interest 100%

Average Net Revenue Interest 75%

Planned Well Spacing (Acres) 75 – 100

Net Identified Drilling Locations 1,250 - 1,650

Gross Wells On Production (1) 187

Awaiting / Undergoing Completions (1) 21

EURs (MBoe) 600 – 700

D&C Costs ($MM) $6.5

F&D Cost ($ / Boe) $9.29 – $10.83

IRR @ $4.50 / Mcf 33% – 51%

NPV ($MM) $3.0 – $4.7

LEF Well Economics

Acreage, Inventory & Operational Update

1. Well status as of 11/4/14

Western Catarina (~43,000 net acres)

─ Partially developed; excellent offset operator results

─ ~200 LEF drilling locations

─ 71 Proven UEF locations; ~180 potential locations in

UEF

─ Recently completed 11 UEF wells exceeding

expectations (24-hr IP ranging from 973 – 2193

boe/d)

─ Added potential to book up to 200 additional UEF

locations

Eastern Catarina (~37,000 net acres)

─ Largely underexplored; excellent LEF core & log rock

quality in the LEF

─ ~400 LEF potential drilling locations with additional

upside locations in the UEF

─ Similar characteristics to Alexander Ranch but

significantly larger

Central Catarina (~26,000 net acres)

─ Exploration area; full 3D seismic coverage and UEF

potential

PUD Locations only in Western Catarina

Western Catarina

Central Catarina

Eastern Catarina

Catarina Gross Rigs 2.5

Revised 2015 Capital Plan


16

Initial Catarina Well Results

These wells were drilled by the previous operator in the Upper Eagle Ford and completed by SN

Initial pad average IP 70% higher than the previous operator’s average wells

SN is using a much lighter gel load (10# vs 20#+ from the previous operator) and tighter frac cluster spacing

likely causing the uplift

Well Name

24 Hour IP

(Boe/d)

%

Liquids

Choke

Size

Lateral

Length

(Feet) Stages

D20 HE 2,117 63% 24 5,399 22

D20 HB 1,589 64% 20 5,960 24

D20 HW 1,560 63% 22 5,268 21

D20 HD 1,491 66% 20 5,953 24

D20 HA 1,405 66% 16 5,728 23

D20 HX 1,264 63% 14 5,046 21

D20 HZ 1,117 63% 16 4,851 20

D20 HY 1,099 62% 14 5,311 21

D20 HV 973 62% 16 3,029 12

A24 HY 2,193 60% 24 4,454 18

A24 HZ 1,358 62% 18 5,061 21

Average D20 Pad 1,402 64% 18 5,172 21

Average A24 Pad 1,776 61% 21 4,758 20

Previous Operator Average 825 62% 5,226 22


EURs (MBoe) 500

D&C Costs ($MM) $6.0 - $7.0

F&D Cost ($ / Boe) $12.00 - $14.00

IRR @ $90 / Bbl 72% - 109%

IRR @ $80 / Bbl 51% - 77%

NPV @ $90 / Bbl ($MM) $6.6 - $7.6

NPV @ $80 / Bbl ($MM) $4.8 - $5.8

% Oil / Liquids 82% / 90%




Planned Well Spacing (Acres) 40

Net Identified Drilling Locations (1) 700+

Cotulla / Wycross Gross Rigs 1.5

Cotulla Overview

17

1. Assumes 80% of net undeveloped acres are drillable and spaced on 40 acres 2. Well status as of 11/4/14

Wycross Well Economics


Gross Wells On Production 122

Awaiting / Undergoing Completion 8

EURs (MBoe) 450

D&C Costs ($MM) $5.5 - $6.0

F&D Cost ($ / Boe) $12.22 - $13.33

IRR @ $90 / Bbl 45% - 57%

IRR @ $80 / Bbl 32% - 40%

NPV @ $90 / Bbl ($MM) $4.0 - $4.5

NPV @ $80 / Bbl ($MM) $2.6 - $3.1


Cotulla Acreage & Inventory

Operational Update (2)

Alexander R. Well Economics

Alexander Ranch

Wycross

Wright Ranch

Talbutt Trust

Hausser


EURs (MBoe) 450 – 750

D&C Costs ($MM) $7.0 - $7.5

F&D Cost ($ / Boe) $9.33 - $16.67

IRR @ $90 / Bbl 45% - 200%

IRR @ $80 / Bbl 30% - 145%

NPV @ $90 / Bbl ($MM) $4.2 - $13.3

NPV @ $80 / Bbl ($MM) $2.7 - $10.7


EURs (MBoe) 350

D&C Costs ($MM) $6.0 - $7.0

F&D Cost ($ / Boe) $17.14 - $20.00

IRR @ $90 / Bbl 26% - 40%

IRR @ $80 / Bbl 17% - 27%

NPV @$90 / Bbl ($MM) $2.3 - $3.3

NPV @$80 / Bbl ($MM) $1.0 - $2.0


EURs (MBoe) 450

D&C Costs ($MM) $7.0 - $8.0

F&D Cost ($ / Boe) $15.56 - $17.78

IRR @ $90 / Bbl 38% - 53%

IRR @ $80 / Bbl 26% - 37%

NPV @ $90 / Bbl ($MM) $4.2 - $5.2

NPV @ $80 / Bbl ($MM) $2.6 - $3.6







Marquis & Palmetto Overview

181. Assumes 80% of net undeveloped acres are drillable and

spaced on 60 acres 2. Assumes 90% of net undeveloped acres are drillable and

spaced on 40 acres3. Well status as of 11/4/14

Prost / Moulton Well EconomicsMarquis Acreage & Inventory

Palmetto Well Economics



Marquis Operational Update (3)



Palmetto Operational Update (3)






Palmetto Acreage & Inventory

Palmetto

Marquis

Five Mile Creek Well Economics

Marquis Gross Rigs 1.0

Palmetto Gross Rigs 1.0



TMS Acreage Position and Activity

19

~61,000 net acre position in the core of the TMS

Contiguous blocky acreage with 3+ years of average remaining lease term

St. Davis Unit #1H in Amite County, Mississippi is undergoing completion and currently drilling the Morris Unit #2 in

Wilkinson County, Mississippi

SN’s acreage position is highlighted in yellow

EncanaLawson 25H-1

24 HR IP: 498 Boe/d

SNDry Fork East #2H

24 HR IP: 712 Boe/d

EncanaAsh 31H-2

24 HR IP: 730 Boe/d

EncanaAnderson 18H-1

24 HR IP: 1,178 Boe/d30 Day IP: 1,072 Boe/d

GoodrichSmith 5-29H-1

24 HR IP: 1,045 Boe/d


24 HR IP: 1,540 Boe/dEncana

Weyerhaeuser 60H-1

24 HR IP: 1,100 Boe/d

EncanaHorseshoe Hill

10H-124 HR IP: 813 Boe/d30 Day IP: 695 Boe/d

DevonMurphy 63H-1

24 HR IP: 460 Boe/d30 Day IP: 506 Boe/d


24 HR IP: 1,083 Boe/d30 day IP: 933 Boe/d

GoodrichBlades 33H #1

24 HR IP: 1,270 Boe/d

GoodrichCrosby 12-1H

24 HR IP: 1,300 Boe/d30 Day IP: 1,137 Boe/d

GoodrichNunnery 12-1H-1

24 HR IP: 815 Boe/d

GoodrichCH Lewis 30-19H-1

24 HR IP: 1,450 Boe/d

HalconHorseshoe Hill

11-22H 24 HR IP: 1,548 Boe/d

HalcónFassmann 9H-1

Completing

HalcónShuckrow 10H-1

Completing

GoodrichCMR / Foster Creek

24-13H-124 HR IP: 1,215 Boe/d

GoodrichCMR/Foster Creek 31-

22H-124 HR IP: 1,144 Boe/d

EncanaSabine 12H-1 & 2

Drilling

GoodrichBates 25-24-1

24 HR IP: 1,000 Boe/d

GoodrichSpears 31-61H-1

24 HR IP: 1,360 Boe/d

HalcónGeorge Martens

et al. 1HDrilling

HalcónS.D. Smith 1H

24 HR IP: 786 Boe/d

GoodrichSLC, Inc. 81H-1

24 HR IP: 900 Boe/d

EncanaAsh 13H-1 & 2

Drilling

GoodrichDenkmann33-28H-2

24 HR IP: 1,258 Boe/d

EncanaMathis 29-32H-124 HR IP: 1,300

Boe/d

EncanaLewis 7-18H-124 HR IP: 1,500

Boe/d

HalcónBlackstone Minerals 4H-2

24 HR IP: 637 Boe/d

SNSt. Davis #1HCompleting

SNMorris Unit #2H

Drilling

ComstockCMR Foster Creek 28-

40 1HDrilling


Financial Highlights

20


Capitalization

3Q14 liquidity of $896 million

$596 million in cash

$362.5 million borrowing base with an elected commitment of $300 million and $0 million drawn

No debt maturities until 2018

Revolver currently 2018

Senior notes 2021

Common shares outstanding as of 9/30/14:

Basic: 58.6 million

Diluted: 71.1 million

1. Based on a closing stock price of $17.38 as of 11/7/14 and includes convertible preferred stock at book value (~$269 million)2. Liquidity is equal to cash on hand plus availability under our revolving credit facility, which is currently $362.5 million with an elected commitment of $300 million3. As of 9/30/14 pro forma LTM EBITDA includes Wycross and Catarina acquisitions as if SN had owned the assets since 10/1/13

21

3Q14 Capitalization Table & Liquidity ($MM)As of

9/30/14

Cash and Equivalents $596

Revolving Credit Facility ($300 MM Available) -

Senior Notes 1,750

Total Debt $1,750

Net Debt 1,154

Perpetual Convertible Preferred Stock 269

Common Equity 810

Book Capitalization $2,829

Market Value as of 11/7/14

Fully Diluted Market Capitalization (1) 1,286

Enterprise Value $2,440

Liquidity (2)

$896

Total Debt / LTM EBITDA (3) 2.7x

Net Debt / LTM EBITDA (3) 1.8x

Total Debt / Proved Reserves ($/Boe) $15.00

Total Debt / Proved Developed Reserves ($/Boe) $34.39

PV-10 / Total Debt 1.2x

Total Debt / Enterprise Value 72%


Hedging program protects cash flow, development, and capital spend

~45% of anticipated total 2015 production hedged at the mid-point of production guidance range

• Hedging revenue objectives based on ~$90 oil pricing and ~$4 gas pricing environment for 2015 • ~50% of forecasted 2015 revenue hedged if un-hedged positions were firmed up at current price levels

Currently scaling in 2016 hedges with target of ~25% by year end

Use a variety of derivatives (swaps, costless collars, 3-way collars, and enhanced swaps)

Only enter into derivative agreements with counterparties that are “A” rated or better

Actively manage credit exposure per counterparty

Hedge Summary

22

Oil Hedges Gas Hedges

$78.00

$82.00

$86.00

$90.00

$94.00

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

Q1:15 Q2:15 Q3:15 Q4:15 Q1:16 Q2:16 Q3:16 Q4:16

Bb

ls p

er

day

Oil (Bbls) Oil Cap ($/Bbls) Oil Floor ($/Bbls)

$3.50

$3.70

$3.90

$4.10

$4.30

$4.50

$4.70

$4.90

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Q1:15 Q2:15 Q3:15 Q4:15 Q1:16 Q2:16 Q3:16 Q4:16

MC

F p

er

day

Gas (Mcf) Gas Cap ($/Mcf) Gas Floor ($/Mcf)


23

Capitalization Summary Revolving credit facility (due 2018)

─ $362.5 MM borrowing base with an elected commitment of $300 million and an interest rate of LIBOR + 1.50% - 2.50%

─ Restrictive covenant: Net Debt < 4.0x TTM EBITDA

$600 MM of 7.75% senior unsecured notes (due 2021)─ No liquidity or performance based covenants

$1,150 MM of 6.125% senior unsecured notes (due 2023)─ No liquidity or performance based covenants

$92 MM of 4.875% cumulative perpetual convertible preferred stock, series A─ Convertible into 4.3 million shares of common stock ($21.51/share)

─ Mandatorily convertible after 10/5/17 if common stock trades above $27.96 for at least 20 out of 30 trading days

─ No liquidity or performance based covenants

$177 MM of 6.50% cumulative perpetual convertible preferred stock, series B─ Convertible into 8.3 million shares of common stock ($21.40/share)

─ Mandatorily convertible after 4/6/18 if common stock trades above $27.82 for at least 20 out of 30 trading days

─ No liquidity or performance based covenants

Common shares outstanding as of 9/30/14:

─ Basic: 58.6 million

─ Fully diluted: 71.1 million (assuming full conversion of both series of preferred stock)


24

Summary Investment Highlights Deep inventory of high-return, low risk locations underpins growth

─ 2,800+ net drilling locations across ~226,000 net acres in the Eagle Ford

2015 production guidance midpoint: ~50,000 Boe/d

Operational and financial flexibility to respond to changing commodity price environments

─ Ability to satisfy all drilling commitments and continue to grow production

Manufacturing process drives capital efficiency

─ Technically driven corporate culture focused on manufacturing efficiency and returns on capital

Reserve and production growth drivers

─ Catarina acquisition fits operational sweet spot

─ Stacked pay potential across Eagle Ford trend

─ TMS has potential to add high rate of return oil inventory

Self-funded with conservative financial profile

─ Low Net Debt to EBITDA and strong liquidity

Management experienced with Gulf Coast trends and with resource play development


Appendix

25


26

Non–GAAP Reconciliation and Measures

Reconciliation of Net Income (Loss) To Adjusted EBITDA ($M)

Reconciliation of PV-10 To Standardized Measure ($MM)

Explanation of Non-GAAP MeasuresAdjusted EBITDA is defined by the Company as net income (loss) PLUS: (1) interest expense, including net losses (gains) on interest rate derivative contracts; (2) net losses (gains) on commodity derivatives; (3) net settlements received (paid) on commodity derivatives; (4) premiums (paid) on commodity derivative contracts; (5) depletion, depreciation, amortization, and accretion; (6) stock-based compensation expense; (7) acquisition costs included general and administrative; (8) income tax expense (benefit); (9) loss (gain) on sale of oil and natural gas properties; (10) impairment of oil and natural gas properties; and (11) other non-recurring items that we deem appropriate; LESS: (1) interest income; and (2) other non-recurring items that we deem appropriate.

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess our operating performance as compared to that of other companies in our industry, without regard to financing methods, capital structure, or historical cost basis. It is also used to assess our ability to incur and service debt and fund capital expenditures.

Our Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss), cash flow provided by or used in operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities,” as codified in ASC Topic 932, “Extractive Activities—Oil and Gas.” For further information regarding the calculation of the standardized measure, see “Unaudited Supplementary Information” included in the financial statements included in our Annual Report for the fiscal year ended December 31, 2013.

Pro Forma Actual

LTM Ended LTM Ended

9/30/14 12/31/11

Net Income (Loss) $98,114 $1,968

Plus:

Interest Expense 96,667 -

Net Losses On Commodity Derivatives (3,274) 480

Net Settlement On Commodity Derivatives (10,318) -

Premiums Paid On Commodity Derivatives Contracts (1,325) -

Depreciation, Depletion, Amortization, And Accretion 374,842 4,252

Stock-Based Compensation 29,270 -

Acquisition Costs Included in G&A 1,945 -

Income Tax Expense 53,329 -

Less:

Interest Income (100) (1)

Adjusted EBITDA $639,151 $6,699

As of As of

9/30/14 12/31/11

PV-10 $2,082 $152

Present Value of Future Income Taxes

Discounted at 10% (248) (19)

Standardized Measure $1,834 $133

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