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Sanchez Energy Corporation (SN) (the “Company,” “SN,” “Sanchez Energy,” “we,” “our” or similar terms), today announced the Company’s operating and financial results for the third quarter 2014, which included the following highlights:

HIGHLIGHTS FOR THIRD QUARTER 2014

  • Record revenues of $207.4 million, an increase of 120% over the same period a year ago
  • Record production of 3,552 MBOE; an average for the period of 38,613 BOE/D
  • Net income attributable to common stockholders of $42.7 million, as compared to a net loss attributable to common stockholders of $1.6 million reported over the same period a year ago, resulting in basic and diluted earnings per share of $0.77 and $0.69, respectively
  • Adjusted EBITDA, a non-GAAP financial measure defined below, of $148.2 million, an increase of 132% over the same period a year ago
  • Adjusted Net Income, a non-GAAP financial measure defined below, of $12.8 million, a decrease of 5% over the same period a year ago
  • Liquidity of $896 million as of September 30, 2014 consisting of $596 million in cash and cash equivalents and a $362.5 million unused borrowing base (with a $300 million elected commitment amount), under our revolving credit facility

MANAGEMENT COMMENTS

Tony Sanchez, III, President and Chief Executive Officer of Sanchez Energy, commented: “Sanchez Energy reported record production, revenue and cash flow from operations driven by strong organic growth combined with the first quarter of ownership of Catarina.  The Company is in full-scale development mode at Catarina with two rigs drilling off multi-well pads on the western part of the ranch, and a third rig delineating the eastern side.

As previously reported, SN had strong results from completing nine Catarina wells which were drilled by the previous operator in the Upper Eagle Ford and averaged 1,402 BOE/D (64% liquids).  Recently, SN has brought another two Upper Eagle Ford Catarina wells online at 24 hour average production rates of 2,193 and 1,358 BOE/D, with the difference in rates attributable to different choke settings during initial flowback.  All 11 wells have thus far significantly outperformed the Company’s expectations and are tracking type-curves that exceed those used for the Lower Eagle Ford in that area.

For the more recent wells that SN is drilling, the Company is utilizing longer laterals and more frack stages with significantly higher proppant concentrations per stage.  In order to accommodate the longer lead times associated with these updated completions, the company has brought in a second frack spread to work through the inventory of wells to be completed, which currently stands at 21, 11 of which are in the Lower Eagle Ford and 10 of which are in the Upper Eagle Ford.   At Catarina we are already seeing notable improvements in the pipeline network and infrastructure.  SN has already commissioned and installed additional high pressure lines to allow greater flow capacity going into one of our central processing facilities, installed flash gas compression, and made numerous minor changes to our separation and processing facilities.  During the fourth quarter, the Company plans to install additional boost compression in Catarina and add interconnect lines which will yield additional improvements and allow for significant increase of production when a large number of wells are expected to be brought online in early 2015.

Our legacy assets continue to exhibit strong performance and, most recently, at Marquis we brought online three additional Moulton-area wells with average rates of approximately 1,300 BOE/D, bringing the total to six wells, with plans to bring online an additional three well pad in the fourth quarter.

The Company has planned for and is poised to rapidly adapt to a changing commodity price environment.  As of September 30, 2014 SN had approximately $900 million of liquidity, consisting of approximately $600 million in cash and cash equivalents and $300 million in committed revolver capacity, and is currently in the process of going through a redetermination of its credit facility borrowing base, which it expects to increase from existing levels.  The Company’s substantial amount of held by production acreage and long-term leases allow it to treat the majority of capital spending as discretionary. The only significant ongoing capital commitments are Catarina’s continuous drilling provision of 50 wells per year, which can be met with 2 to 2.5 rigs per year, and the TMS where we expect to meet our well carry commitments in early 2015. We expect to have drilled in excess of the required 50 wells per year in our first year of operations at Catarina with the excess allowed to be banked and applied to subsequent years.

In light of the recent downturn in oil prices, SN has revised its preliminary 2015 capital plan range downwards to approximately $850 to $900 million, a reduction of approximately $250 – $300 million from the midpoint of the previous guidance.  Importantly, SN will focus on the development drilling of its existing multi-year inventory of high rate of return projects where it has achieved significant per well cost savings, and deemphasize step-out and appraisal drilling, yet preserve the optionality of its significant land position which is mostly held by production. This temporary reallocation of capital spending away from exploration and appraisal drilling in our Marquis and TMS areas toward development drilling does not diminish our expectations about those areas where the results we and others have experienced continue to improve and are meeting or exceeding our expectations.  As such, total production for 2015 is expected to average approximately 50,000 BOE/D, which represents a growth rate of approximately 70% when compared to expected full-year 2014 production and a fourth quarter 2014 to fourth quarter 2015 increase in excess of 25%. The Company’s anticipated 2015 capital program is expected to be fully funded through cash and cash equivalents on hand and cash flow from operations without drawing down on the Company’s availability under its revolving credit facility, assuming average oil prices of $80 per barrel and natural gas prices of $3.75 per Mmbtu.

With a history of avoiding onerous, long term contracts, we will be able to use this current environment to high grade our services and suppliers while also taking advantage of an expected softness in service costs. Specifically, we have the ability to satisfy all of our drilling commitments and continue to grow production year over year while reducing capital spending by another 25% from this revised capital spending plan if commodity prices fall materially below our current flat price deck of $80 per barrel for oil and $3.75 per Mmbtu for natural gas.  We have strategically built our operational capability to enable us to both flex upward or downward in our spending plans if the situation warrants.  As demonstrated by the revised spending plan we are, and will continue to, continuously assess the most appropriate use of our capital resources without compromising our long term financial position.”

OPERATIONS UPDATE

As detailed in the table below, Sanchez Energy currently has 13 gross rigs (eight operated and five non-operated rigs) running across its Eagle Ford and TMS areas with 458 gross producing wells and 45 gross wells in various stages of completion.

Gross

Gross

Gross

Net

Wells Waiting / 

Project

Producing

Rigs

Rigs

Undergoing

Area

Wells

Running

Running

Completion

Catarina

187

3

3

21

Marquis

79

4

2

13

Cotulla

122

2

2

8

Palmetto

64

1

1

TMS / Other

6

3

1

3

Total

458

13

9

45

The table below summarizes the change in the revised capital spending plan showing gross rigs by each of our areas.

Gross Rigs

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

PRODUCTION VOLUMES, AVERAGE SALES PRICES, OPERATING COSTS PER BOE AND CAPITAL EXPENDITURES

Sanchez Energy’s mix of hydrocarbon production during the third quarter of 2014 consisted of approximately 47% crude oil, 26% natural gas and 27% natural gas liquids.  By area, Catarina, Marquis, Cotulla (excluding Wycross), Palmetto and Wycross comprised approximately 48%, 18%, 16%, 12% and 6%, respectively, of the Company’s total third quarter 2014 production volumes.

Revenue for the three months ended September 30, 2014 totaled $207.4 million, an increase of 120% over the same period a year ago, due to the addition of 339 gross new wells since the second quarter 2013, including 149 gross wells from existing operations and 190 gross wells from the acquisition of new properties.

Production, average sales prices and operating costs and expenses per BOE for the third quarter 2014 as well as guidance for the fourth quarter and full year 2015 are summarized below:

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

Production volumes –

Oil (MBo)

1,682

826

4,257

1,644

NGLs (MBbls)

964

106

1,477

231

Natural gas (MMcf)

5,440

906

8,207

1,595

  Total oil equivalent (MBOE)

3,552

1,083

7,103

2,141

  BOE/Day

38,613

11,774

26,018

7,843

Average sales price, excluding the impact of derivative instruments –

Oil ($ per Bo)

$    93.87

$  105.86

$    97.35

$ 104.41

NGLs ($ per Bbl)

$    28.34

$    30.03

$    29.72

$   26.65

Natural gas ($ per Mcf)

$      4.07

$      3.94

$      4.29

$     4.09

  Oil equivalent ($ per BOE)

$    58.37

$    86.96

$    69.49

$   86.09

Average sales price, including the impact of derivative instruments –

Oil ($ per Bo)

$    92.45

$    99.17

$    95.07

$ 100.15

NGLs ($ per Bbl)

$    28.34

$    30.03

$    29.72

$   26.65

Natural gas ($ per Mcf)

$      4.14

$      3.94

$      4.25

$     4.09

  Oil equivalent ($ per BOE)

$    57.81

$    81.87

$    68.08

$   82.83

Operating costs and expenses ($/BOE):

Oil and natural gas production expenses

$      9.68

$    10.18

$      9.04

$     9.85

Production and ad valorem taxes

$      3.07

$      5.11

$      4.11

$     5.11

General and administrative, excluding

stock based compensation and 

acquisition costs included in G&A (1)

$      3.35

$      7.60

$      4.69

$     8.04

(1) Excludes stock-based compensation of $0 and $6.15 per BOE for the three months ended September 30, 2014 and 2013, respectively, and $3.64 and $6.71 per BOE for the nine months ended September 30, 2014 and 2013, respectively, and excludes acquisition costs included in G&A of $0.26 and $0.28 per BOE for the three months ended September 30, 2014 and 2013, respectively, and $0.25 and $1.86 per BOE for the nine months ended September 30, 2014 and 2013, respectively.

Sanchez Energy announced that internally estimated proved reserves increased to over 125 MMBOE as of September 30, 2014, up more than 8 MMBOE from approximately 117 MMBOE as of June 30, 2014. Crude oil constituted 47% (total liquids constituted 72%) of Sanchez Energy’s internally estimated proved reserves, and 54% of the Company’s proved reserves were classified as proved undeveloped compared to 56% as of June 30, 2014.

Guidance

4Q14

2015

Production (BOE/D)

40,000

44,000

50,000

Operating costs and expenses:

Oil and natural gas production expenses ($/BOE)

$   9.00

$ 10.00

$    9.00

$10.00

Production and ad valorem taxes ($/BOE)

$   3.00

$    4.00

$    2.50

$   3.50

G&A, excluding stock based compensation and

acquisition costs included in G&A ($/BOE)

$   3.00

$    4.00

$    2.50

$   3.50

Preferred stock dividends and interest expense ($/BOE)

(annualized preferred stock dividends and interest 

expense total $16.0 million and $116.9 million, respectively)

$   8.00

$    9.00

$7.30

Capital expenditures, before estimated accruals, for the third quarter 2014 were approximately $204 million, and capital expenditures incurred during the third quarter, including accruals, were approximately $224 million.

HEDGING UPDATE

During the third quarter of 2014 and subsequent to quarter end, Sanchez Energy entered into additional derivative contracts covering anticipated future production in 2014, 2015 and 2016.  As of November 5, 2014, Sanchez Energy has approximately 5.1 million barrels of anticipated crude production and 18.6 Bcf of gas production for 2015 hedged, or approximately 8.2 MBOE, which represents approximately 45% of its anticipated total 2015 production at the mid-point of its guidance range. A schedule of all current hedges for 2014, 2015, and 2016 production is included herein.

SHARE COUNT

As of September 30, 2014, the Company had 58,560,817 total common shares outstanding with a quarterly weighted average outstanding share count of 55,732,098.  If all Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock were assumed to be converted, total outstanding shares as of September 30, 2014 would have been 71,091,512.

CONFERENCE CALL

Sanchez Energy will host a conference call for investors on November 5, 2014 at 2:00 p.m. ET (1:00 p.m. CT, 12:00 p.m. MT and 11:00 a.m. PT, respectively).  Interested investors can listen to the call by visiting our website at www.sanchezenergycorp.com and clicking on the Third Quarter 2014 Conference Call button.  Webcast, both live and rebroadcast, will be available over the internet at:http://edge.media-server.com/m/p/jbx3ggif/lan/en

ABOUT SANCHEZ ENERGY CORPORATION

Sanchez Energy Corporation is an independent exploration and production company focused on the acquisition and development of unconventional oil resources in the onshore U.S. Gulf Coast, with a current focus on the Eagle Ford Shale in South Texas where we have assembled approximately 226,000 net acres and the Tuscaloosa Marine Shale in Mississippi and Louisiana where we have assembled approximately 61,000 net acres.  For more information about Sanchez Energy Corporation, please visit our website:  www.sanchezenergycorp.com

FORWARD LOOKING STATEMENTS

This press release contains, and our officers and representatives may from time to time make, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  All statements, other than statements of historical facts, included in this press release that address activities, events or developments that Sanchez Energy expects, believes or anticipates will or may occur in the future are forward-looking statements, including statements relating to estimates of our future production, estimates of our future hydrocarbon mix, the anticipated benefits of our acquisitions, any planned takeover of operations, and the rate of development of new plays that we enter into. 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 press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model,” “strategy,” “future,” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of Sanchez Energy, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements, including, but not limited to failure of acquired assets to produce as anticipated, failure to successfully integrate acquired assets, failure to continue  to produce  oil and gas at historical rates, costs of operations, delays, and any other difficulties related to producing oil or gas, the price of oil or gas, marketing and sales of produced oil and gas, estimates made in evaluating reserves, competition, general economic conditions and the ability to manage and continue growth and other factors described in Sanchez Energy’s Annual Report for the fiscal year ended December 31, 2013 and any updates to those risk factors set forth in Sanchez Energy’s Quarterly Reports on Form 10-Q.  Further information on such assumptions, risks and uncertainties is available in Sanchez Energy’s filings with the Securities and Exchange Commission (the “SEC”). Sanchez Energy’s filings with the SEC are available on its website atwww.sanchezenergycorp.com and on the SEC’s website at www.sec.gov.  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 occur, 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.

CAUTIONARY NOTE TO U.S. INVESTORS

The SEC permits oil and gas companies, in their filings with the SEC, to disclose proved, probable and possible reserves.  We may use certain terms in our press releases, such as net resource potential and other variations of the foregoing terms that the SEC’s guidelines strictly prohibit us from including in filings with the SEC.  U.S. Investors are urged to consider closely the reserves disclosures in our filings with the SEC available on our website at www.sanchezenergycorp.comand the SEC’s website at www.sec.gov.  You can also obtain this information from the SEC by calling its general information line at 1-800-SEC-0330.

Company contact:

Michael G. Long
Executive Vice President and Chief Financial Officer
Sanchez Energy Corp.
713-783-8000

Gleeson Van Riet
Senior Vice President, Capital Markets and Investor Relations
Sanchez Energy Corp.
713-783-8000

(Financial Highlights to follow)

 

SANCHEZ ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS DATA

(unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

 (in thousands, except per share amounts) 

REVENUES:

Oil sales

$   157,907

$   87,436

$   414,484

$   171,635

Natural gas liquids sales

27,309

3,190

43,918

6,166

Natural gas sales

22,134

3,574

35,171

6,520

  Total revenues

207,350

94,200

493,573

184,321

OPERATING COSTS AND EXPENSES:

Oil and natural gas production expenses

34,380

11,026

64,203

21,098

Production and ad valorem taxes

10,916

5,531

29,161

10,942

Depreciation, depletion, amortization and accretion

93,463

38,372

225,297

76,368

General and administrative (inclusive of stock-based compensation expense of $10 and $6,657, respectively, for the three months ended September 30, 2014 and 2013, and $25,888 and $14,369, respectively, for the nine months ended September 30, 2014 and 2013)

12,821

15,195

60,999

35,564

  Total operating costs and expenses

151,580

70,124

379,660

143,972

Operating income

55,770

24,076

113,913

40,349

Other income (expense):

Interest and other income

82

32

97

104

Interest expense

(27,612)

(9,460)

(58,145)

(17,613)

Net gains (losses) on commodity derivatives

47,416

(14,436)

6,399

(13,812)

Total other income (expense), net

19,886

(23,864)

(51,649)

(31,321)

Income before income taxes

75,656

212

62,264

9,028

Income tax expense (benefit)

26,625

(3,668)

21,946

(3,668)

Net income

49,031

3,880

40,318

12,696

Less:

Preferred stock dividends

(4,274)

(5,485)

(29,599)

(13,041)

Net income allocable to participating securities (1)(3)

(2,068)

(495)

Net income (loss) attributable to common stockholders

$   42,689

$  (1,605)

$   10,224

$       (345)

Net income (loss) per common share – basic

$        0.77

$    (0.05)

$        0.20

$      (0.01)

Net income (loss) per common share – diluted (4)(5)(6)(7)

$        0.69

$    (0.05)

$        0.20

$      (0.01)

Weighted average number of unrestricted common shares used to calculate

net income (loss) per common share – basic 

55,732

34,737

51,153

33,651

Dilutive Shares (4)(5)(6)(7)

12,608

Denominator for diluted net income per common share

68,340

34,737

51,153

33,651

Adjusted EBITDA, as defined (2)

$ 148,189

$ 63,820

$ 356,917

$ 128,025

Adjusted net income attributable to common stockholders, as defined (2)

$   12,840

$ 13,568

$   33,692

$   23,698

Adjusted net income per common share – basic

$        0.23

$      0.39

$        0.66

$        0.70

Adjusted net income per common share – diluted (8)(9)(10)(11)

$        0.23

$      0.36

$        0.66

$        0.70

Weighted average number of unrestricted common shares used to calculate

adjusted net income per common share – basic

55,732

34,737

51,153

33,651

Dilutive Shares (8)(9)(10)(11)

17,492

Denominator for diluted adjusted net income per common share

55,732

52,229

51,153

33,651

(1)

The Company’s restricted shares of common stock are participating securities.

(2)

Adjusted EBITDA, Adjusted Net Income attributable to common stockholders and Adjusted Net Income per common share are defined below.

(3) 

For the three and nine months ended September 30, 2013, no losses were allocated to participating restricted stock because such securities do not have a contractual obligation to share in the Company’s losses.

(4) 

The nine months ended September 30, 2014 excludes 1,290,637 shares of weighted average restricted stock and 13,863,738 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

(5)

The three months ended September 30, 2014 includes 12,607,521 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock in the calculation of the denominator for diluted earnings per common share as these shares were dilutive. In addition, the related preferred stock dividends of $4,274,445 were not deducted from net income in computing the numerator used in the calculation of diluted earnings per common share.

(6)

The three months ended September 30, 2013 excludes 863,412 shares of weighted average restricted stock in the calculation of the denominator for diluted net income per common share as these shares were anti-dilutive.

(7)

The three and nine months ended September 30, 2013 excludes 410,779 and 625,920 shares of weighted average restricted stock and 17,491,500 and 14,141,800 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

(8)

The three and nine months ended September 30, 2014 excludes 863,412 and 1,290,637 shares of weighted average restricted stock and 12,607,521 and 13,863,738 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted Adjusted Net Income per common share as these shares were anti-dilutive.

(9)

The nine months ended September 30, 2013 excludes 625,920 shares of weighted average restricted stock and 14,141,800 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted Adjusted Net Income per common share as these shares were anti-dilutive.

(10) 

The three months ended September 30, 2013 includes 17,491,500 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock in the calculation of the denominator for diluted Adjusted Net Income per common share as these shares were dilutive. In addition, the related preferred stock dividends of $5,484,375 were not deducted from net income in computing the numerator used in the calculation of diluted Adjusted Net Income per common share.

(11)

The three months ended September 30, 2013 excludes 410,779 shares of weighted average restricted stock in the calculation of the denominator for diluted Adjusted Net Income per common share as these shares were anti-dilutive.

 

SANCHEZ ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

September 30,

December 31,

2014

2013

ASSETS:

(In thousands)

Cash and cash equivalents

$       596,272

$      153,531

Oil and natural gas receivables

93,865

51,960

Joint interest billing receivables

16,855

5,803

Fair value of derivative instruments, current

9,748

Deferred tax asset, current

4,717

6,882

Other current assets

12,103

1,386

Oil and natural gas properties, net

2,302,899

1,385,488

Fair value of derivative instruments, noncurrent

3,075

1,304

Debt issuance costs, net

50,003

19,806

Other assets

14,813

2,993

TOTAL ASSETS

$    3,104,350

$   1,629,153

LIABILITIES AND STOCKHOLDERS’ EQUITY:

Accounts payable

$         17,306

$        46,900

Accounts payable – related entities

1,218

961

Other payables

4,708

2,963

Accrued liabilities

196,108

102,455

Deferred premium liability, current

4,017

717

Fair value of derivative instruments, current

38

4,623

Long term debt, net of premium (discount)

1,746,162

593,258

Asset retirement obligations

24,048

4,130

Deferred tax liability, noncurrent

30,649

10,868

Deferred premium liability, noncurrent

1,233

4,891

Fair value of derivative instruments, noncurrent

131

78

Stockholders’ equity

1,078,732

857,309

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

$    3,104,350

$   1,629,153

SANCHEZ ENERGY CORPORATION
HEDGING ACTIVITY SUMMARY

As of September 30, 2014, the Company had the following crude oil swaps, collars and put spreads covering anticipated future production:

Contract Period

Instrument

Barrels

Purchased

Sold

Pricing Index

October 1, 2014 – December 31, 2014

Swap

69,000

$92.00

n/a

NYMEX WTI

October 1, 2014 – December 31, 2014

Swap

69,000

$91.35

n/a

NYMEX WTI

October 1, 2014 – December 31, 2014

Swap

69,000

$92.45

n/a

NYMEX WTI

October 1, 2014 – December 31, 2014

Swap

92,000

$95.45

n/a

NYMEX WTI

October 1, 2014 – December 31, 2014

Swap

92,000

$93.25

n/a

NYMEX WTI

January 1, 2015 – December 31, 2015 (1)

Swap

365,000

$89.65

n/a

NYMEX WTI

January 1, 2015 – December 31, 2015 (1)

Swap

365,000

$90.05

n/a

NYMEX WTI

January 1, 2015 – December 31, 2015 (1)

Swap

365,000

$88.48

n/a

NYMEX WTI

January 1, 2015 – December 31, 2015

Swap

365,000

$88.35

n/a

NYMEX WTI

October 1, 2014 – December 31, 2014

Collar

92,000

$90.00

$99.10

NYMEX WTI

October 1, 2014 – December 31, 2014

Put Spread

92,000

$90.00

$75.00

NYMEX WTI

(1)In October 2014, the Company modified these crude oil swaps to create crude oil enhanced swaps.  See below for a description of the modified transactions covering anticipated future production.

As of September 30, 2014, the Company had the following crude oil enhanced swaps covering anticipated future production:

Contract Period

Barrels

Purchased

Put

Pricing Index

January 1, 2015 – December 31, 2015

365,000

$91.46

$75.00

NYMEX WTI

January 1, 2015 – December 31, 2015

365,000

$93.13

$75.00

NYMEX WTI

January 1, 2015 – December 31, 2015

365,000

$92.20

$75.00

NYMEX WTI

January 1, 2015 – December 31, 2015

365,000

$91.46

$75.00

NYMEX WTI

January 1, 2015 – December 31, 2015

182,500

$92.00

$75.00

NYMEX WTI

As of September 30, 2014, the Company had the following natural gas swaps and collars covering anticipated future production:

Derivative 

Contract Period

Instrument

Mmbtu

Purchased

Sold

Pricing Index

October 1, 2014 – December 31, 2014

Swap

184,000

$4.23

 n/a 

NYMEX NG

October 1, 2014 – December 31, 2014

Swap

184,000

$4.23

 n/a 

NYMEX NG

October 1, 2014 – December 31, 2014

Swap

184,000

$4.24

 n/a 

NYMEX NG

October 1, 2014 – December 31, 2014

Swap

184,000

$4.61

 n/a 

NYMEX NG

January 1, 2015 – December 31, 2015

Swap

3,650,000

$4.01

n/a

NYMEX NG

October 1, 2014 – December 31, 2014

Collar

184,000

$4.00

$4.50

NYMEX NG

As of September 30, 2014, the Company had the following natural gas enhanced swaps covering anticipated future production:

Contract Period

Mmbtu

Purchased

Put

Pricing Index

January 1, 2015 – December 31, 2015

2,190,000

$4.44

$3.75

NYMEX NG

January 1, 2015 – December 31, 2015

1,095,000

$4.40

$3.75

NYMEX NG

January 1, 2015 – December 31, 2015

730,000

$4.50

$3.75

NYMEX NG

January 1, 2015 – December 31, 2015

3,650,000

$4.21

$3.75

NYMEX NG

As of September 30, 2014, the Company had the following three-way crude oil collar contracts that combine a long and short put with a short call:

Contract Period

Barrels

Short Put

Long Put

Short call

Pricing Index

October 1, 2014 – December 31, 2014

138,000

$65.00

$85.00

$102.25

NYMEX WTI

October 1, 2014 – December 31, 2014

92,000

$75.00

$95.00

$107.50

LLS

October 1, 2014 – December 31, 2014

92,000

$75.00

$90.00

$96.22

NYMEX WTI

January 1, 2015 – December 31, 2015

365,000

$70.00

$85.00

$95.00

NYMEX WTI

January 1, 2015 – December 31, 2015

365,000

$70.00

$85.00

$95.00

NYMEX WTI

January 1, 2015 – December 31, 2015

365,000

$70.00

$85.00

$94.75

NYMEX WTI

January 1, 2015 – December 31, 2015

365,000

$75.00

$90.00

$97.00

NYMEX WTI

January 1, 2015 – December 31, 2015

365,000

$75.00

$90.00

$97.25

NYMEX WTI

As of September 30, 2014, the Company had the following three-way natural gas collar contracts that combine a long and short put with a short call:

Contract Period

Mmbtu

Short Put

Long Put

Short Call

Pricing Index

October 1, 2014 – December 31, 2015

2,285,000

$3.50

$4.00

$4.90

NYMEX NG

October 1, 2014 – December 31, 2015

2,285,000

$3.50

$4.00

$4.90

NYMEX NG

In October 2014, the Company entered into the following crude oil swaps:

Contract Period

Instrument

Barrels

Purchased

Sold

Pricing Index

January 1, 2015 – December 31, 2015

 Swap 

182,500

$85.50

n/a

NYMEX WTI

January 1, 2016 – December 31, 2016

 Swap 

366,000

$80.00

n/a

NYMEX WTI

January 1, 2016 – December 31, 2016

 Swap 

183,000

$80.15

n/a

NYMEX WTI

January 1, 2016 – December 31, 2016

 Swap 

366,000

$80.15

n/a

NYMEX WTI

January 1, 2016 – December 31, 2016

 Swap 

183,000

$80.15

n/a

NYMEX WTI

In October 2014, the Company entered into the following natural gas swap:

Contract Period

Instrument

Mmbtu

Purchased

Sold

Pricing Index

January 1, 2015 – December 31, 2015

 Swap 

3,650,000

$3.91

n/a

NYMEX NG

January 1, 2016 – December 31, 2016

 Swap 

3,660,000

$3.92

n/a

NYMEX NG

As noted above, in October 2014, the Company modified certain crude oil swaps to create the following crude oil enhanced swaps:

Contract Period

Instrument

Barrels

Purchased

Sold

Pricing Index

January 1, 2015 – December 31, 2015

 Enhanced Swap 

365,000

$92.15

$72.50

NYMEX WTI

January 1, 2015 – December 31, 2015

 Enhanced Swap 

365,000

$92.60

$72.50

NYMEX WTI

January 1, 2015 – December 31, 2015

 Enhanced Swap 

365,000

$90.93

$72.50

NYMEX WTI

The modifications to these derivative transactions did not change the contract periods, volumes or counterparties.  Further, there were no changes to the respective fair values of each crude oil swap on the condensed consolidated balance sheet as of September 30, 2014.

SANCHEZ ENERGY CORPORATION

RECONCILIATION OF NON-GAAP MEASURES

(unaudited)

I.

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 costs basis.  It is also used to assess our ability to incur and service debt and fund capital expenditures.  We define Adjusted EBITDA as net income (loss):

Plus:

  • Interest expense, including net losses (gains) on interest rate derivative contracts;
  • Net losses (gains) on commodity derivative contracts;
  • Net settlements received (paid) on commodity derivative contracts;
  • Depreciation, depletion, amortization and accretion;
  • Stock-based compensation expense;
  • Acquisition costs included in general and administrative;
  • Income tax expense (benefit);
  • Loss (gain) on sale of oil and natural gas properties;
  • Impairment of oil and natural gas properties; and
  • Other non-recurring items that we deem appropriate.

Less:

  • Premiums paid on commodity derivative contracts;
  • Interest income; and
  • Other non-recurring items that we deem appropriate.

 

The following table presents a reconciliation of our net income to Adjusted EBITDA (in thousands):

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

Net income 

$   49,031

$   3,880

$   40,318

$   12,696

Plus:

Interest expense

27,612

9,460

58,145

17,613

Net losses (gains) on commodity derivative contracts

(47,416)

14,436

(6,399)

13,812

Net settlements received (paid) on commodity derivative contracts

(1,635)

(4,565)

(9,652)

(5,121)

Depreciation, depletion, amortization and accretion

93,463

38,372

225,297

76,368

Stock-based compensation expense

10

6,657

25,888

14,369

Acquisition costs included in general & administrative

916

305

1,806

3,990

Income tax expense (benefit)

26,625

(3,668)

21,946

(3,668)

Less:

Premiums paid on commodity derivative contracts

(359)

(966)

(359)

(1,871)

Interest income

(58)

(91)

(73)

(163)

Adjusted EBITDA

$ 148,189

$ 63,820

$ 356,917

$ 128,025

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.

II.

We present Adjusted Net Income attributable to common stockholders (“Adjusted Net Income”) in addition to our reported net income (loss) in accordance with GAAP. This information is provided because management believes exclusion of the impact of our unrealized derivatives not accounted for as cash flow hedges and stock-based compensation expense will help investors compare results between periods and identify operating trends that could otherwise be masked by these items and to highlight the impact that commodity price volatility has on our results. We define Adjusted Net Income as net income (loss):

Plus:

  • Non-cash preferred stock dividends associated with conversion;
  • Net losses (gains) on commodity derivative contracts;
  • Net settlements received (paid) on commodity derivative contracts;
  • Stock-based compensation expense;
  • Acquisition costs included in general and administrative;
  • Other non-recurring items that we deem appropriate; and
  • Tax impact of adjustments to net income.

Less:

  • Premiums paid on commodity derivative contracts;
  • Preferred stock dividends; and
  • Other non-recurring items that we deem appropriate.

The following table presents a reconciliation of our net income to Adjusted Net Income (in thousands, except per share data):

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

Net income

$ 49,031

$   3,880

$ 40,318

$ 12,696

Less: Preferred stock dividends

(4,274)

(5,485)

(29,599)

(13,041)

Net income (loss) attributable to common shares and

participating securities

44,757

(1,605)

10,719

(345)

Plus:

Non-cash preferred stock dividends associated with conversion

284

17,297

Net losses (gains) on commodity derivative contracts

(47,416)

14,436

(6,399)

13,812

Net settlements received (paid) on commodity derivative contracts

(1,635)

(4,565)

(9,652)

(5,121)

Premiums paid on commodity derivative contracts

(359)

(966)

(359)

(1,871)

Stock-based compensation expense

10

6,657

25,888

14,369

Acquisition costs included in general and administrative

916

305

1,806

3,990

Tax impact of adjustments to net income (6)

16,905

(3,978)

Adjusted net income

13,462

14,262

35,322

24,834

Adjusted net income allocable to participating securities (1)

(622)

(694)

(1,630)

(1,136)

Adjusted net income attributable to common stockholders

$ 12,840

$ 13,568

$ 33,692

$ 23,698

Adjusted net income per common share – basic 

$    0.23

$    0.39

$    0.66

$    0.70

Adjusted net income per common share – diluted (2)(3)(4)(5)

$    0.23

$    0.36

$    0.66

$    0.70

Weighted average number of unrestricted outstanding common shares

 used to calculate Adjusted net income per common share- basic

55,732

34,737

51,153

33,651

Dilutive shares (2)(3)(4)(5)

17,492

Denominator for diluted adjusted net income per common share

55,732

52,229

51,153

33,651

(1)

The Company’s restricted shares of common stock are participating securities.

(2)

The three and nine months ended September 30, 2014 excludes 863,412 and 1,290,637 shares of weighted average restricted stock and 12,607,521 and 13,863,738 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted Adjusted Net Income per common share as these shares were anti-dilutive.

(3)

The nine months ended September 30, 2013 excludes 625,920 shares of weighted average restricted stock and 14,141,800 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted Adjusted Net Income per common share as these shares were anti-dilutive.

(4)

The three months ended September 30, 2013 includes 17,491,500 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock in the calculation of the denominator for diluted Adjusted Net Income per common share as these shares were dilutive. In addition, the related preferred stock dividends of $5,484,375 were not deducted from net income in computing the numerator used in the calculation of diluted Adjusted Net Income per common share.

(5)

The three months ended September 30, 2013 excludes 410,779 shares of weighted average restricted stock in the calculation of the denominator for diluted adjusted net income per common share as these shares were anti-dilutive.

(6)

The tax impact is computed by utilizing the Company’s effective tax rate on the adjustments to reconcile net income to Adjusted Net Income.