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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended September 30, 2012

 

OR

 

o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission file number: 1-35372

 

Sanchez Energy Corporation

(Exact name of registrant as specified in its charter)

 

Delaware

 

45-3090102

(State or other jurisdiction of
incorporation or organization)

 

(I.R.S. Employer
Identification No.)

 

1111 Bagby Street, Suite 1800
Houston, Texas

(Address of principal executive offices)

 

77002

(Zip Code)

 

(713) 783-8000
(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x  No o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer o

 

Accelerated filer o

 

 

 

Non-accelerated filer x

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o  No x

 

Number of shares of registrant’s common stock, par value $0.01 per share, outstanding as of November 8, 2012: 33,531,900.

 

 

 



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We are an “emerging growth company” as defined under the Jumpstart Our Business Startups Act of 2012, commonly referred to as the “JOBS Act”.  We will remain an “emerging growth company” for up to five years from the date of the completion of our initial public offering (the “IPO”), or until the earlier of (1) the last day of the fiscal year in which our total annual gross revenues exceed $1 billion, (2) the date that we become a “large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which would occur if the market value of our common equity that is held by non-affiliates is $700 million or more as of the last business day of our most recently completed second fiscal quarter or (3) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three year period.

 

As an “emerging growth company”, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to:

 

·                  not being required to comply with the auditor attestation requirements related to our internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act;

 

·                  reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements; and

 

·                  exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved.

 

In addition, Section 107 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards. Under this provision, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected to avail ourselves of this exemption from new or revised accounting standards and, therefore, we will not be subject to new or revised accounting standards at the same time as other public companies that are not emerging growth companies.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act.  These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control.  All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, 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 Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

 

Forward-looking statements may include statements about our:

 

·            business strategies;

 

·            entry into our anticipated credit facilities;

 

·            ability to replace the reserves we produce through drilling and property acquisitions;

 

·            expected benefits of the acquisition of SN Marquis LLC (“Marquis LLC”);

 

·            drilling plans and locations;

 

·            oil and natural gas reserves;

 

·            technology;

 

·            financial strategy, budget, projections and operating results;

 

·            realized oil and natural gas prices;

 

·            production volumes;

 

·            oil and natural gas production expenses;

 

·            general and administrative expenses;

 

·            future operating results;

 

·            cash flows and liquidity;

 

·            availability of drilling and production equipment;

 

·            availability of qualified personnel;

 

·            capital expenditures;

 

·            availability and terms of capital;

 

·            drilling of wells;

 

·            transportation and marketing of oil and natural gas;

 

·            general economic conditions;

 

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·            competition in the oil and natural gas industry;

 

·            effectiveness of our risk management activities;

 

·            environmental liabilities;

 

·            counterparty credit risk;

 

·            governmental regulation and taxation;

 

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

 

·            estimated future net reserves and present value thereof; and

 

·            plans, objectives, expectations and intentions contained in this report that are not historical.

 

 All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q.  We disclaim any obligation to update or revise these statements except as required by law, and you should not place undue reliance on these forward-looking statements.  Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved.  We disclose important factors that could cause our actual results to differ materially from our expectations under “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Part II, Item 1A. Risk Factors” and elsewhere in this Quarterly Report on Form 10-Q and in our other public filings with the Securities and Exchange Commission (the “SEC”).  These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

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Sanchez Energy Corporation

Form 10-Q

For the Quarterly Period Ended September 30, 2012

 

Table of Contents

 

 

PART I

 

 

 

 

 

 

Item 1.

Unaudited Financial Statements

 

6

 

 

 

 

 

Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011

 

6

 

 

 

 

 

Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011

 

7

 

 

 

 

 

Condensed Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2012

 

8

 

 

 

 

 

Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011

 

9

 

 

 

 

 

Notes to the Condensed Consolidated Financial Statements

 

10

 

 

 

 

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

23

 

 

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

 

35

 

 

 

 

Item 4.

Controls and Procedures

 

36

 

 

 

 

 

PART II

 

 

 

 

 

 

Item 1.

Legal Proceedings

 

37

 

 

 

 

Item 1A.

Risk Factors

 

37

 

 

 

 

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

 

37

 

 

 

 

Item 3.

Defaults Upon Senior Securities

 

38

 

 

 

 

Item 4.

Mine Safety Disclosures

 

38

 

 

 

 

Item 5.

Other Information

 

38

 

 

 

 

Item 6.

Exhibits

 

39

 

 

 

 

 

SIGNATURES

 

40

 

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PART 1 — FINANCIAL INFORMATION

 

Item 1. Unaudited Financial Statements

 

Sanchez Energy Corporation

Condensed Consolidated Balance Sheets (Unaudited)

(in thousands, except share amounts)

 

 

 

September 30,

 

December 31,

 

 

 

2012

 

2011

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

133,367

 

$

63,041

 

Available-for-sale investments

 

11,583

 

 

Oil and natural gas receivables

 

4,327

 

1,193

 

Fair value of derivative instruments

 

3,348

 

1,461

 

Other current assets

 

541

 

327

 

Total current assets

 

153,166

 

66,022

 

Oil and natural gas properties, at cost, using the full cost method:

 

 

 

 

 

Unproved oil and natural gas properties

 

131,216

 

126,201

 

Proved oil and natural gas properties

 

139,031

 

31,836

 

Total oil and natural gas properties

 

270,247

 

158,037

 

Less: Accumulated depreciation, depletion, amortization and impairment

 

(15,985

)

(6,703

)

Total oil and natural gas properties, net

 

254,262

 

151,334

 

 

 

 

 

 

 

Fair value of derivative instruments

 

868

 

 

 

 

 

 

 

 

Total assets

 

$

408,296

 

$

217,356

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable - related entities

 

$

15,008

 

$

1,606

 

Accrued liabilities

 

24,999

 

526

 

Derivative premium liabilities

 

563

 

 

Total current liabilities

 

40,570

 

2,132

 

Asset retirement obligation

 

297

 

83

 

Total liabilities

 

40,867

 

2,215

 

 

 

 

 

 

 

Commitments and contingencies (Note 12)

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

Preferred stock ($0.01 par value, 15,000,000 shares authorized; 3,000,000 and zero shares of 4.875% Cumulative Perpetual Convertible Preferred Stock, Series A, issued and outstanding as of September 30, 2012 and December 31, 2011, respectively)

 

30

 

 

Common stock ($0.01 par value, 150,000,000 shares authorized; 33,510,300 and 33,000,000 shares issued and outstanding as of September 30, 2012 and December 31, 2011, respectively)

 

335

 

330

 

Additional paid-in capital

 

384,392

 

215,115

 

Accumulated deficit

 

(17,328

)

(304

)

Total stockholders’ equity

 

367,429

 

215,141

 

 

 

 

 

 

 

Total liabilities and stockholders’ equity

 

$

408,296

 

$

217,356

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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Sanchez Energy Corporation

Condensed Consolidated Statements of Operations (Unaudited)

(in thousands, except per share amounts)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

REVENUES:

 

 

 

 

 

 

 

 

 

Oil sales

 

$

12,308

 

$

2,633

 

$

25,858

 

$

9,433

 

Natural gas sales

 

185

 

61

 

604

 

437

 

Total revenues

 

12,493

 

2,694

 

26,462

 

9,870

 

 

 

 

 

 

 

 

 

 

 

OPERATING COSTS AND EXPENSES:

 

 

 

 

 

 

 

 

 

Oil and natural gas production expenses

 

610

 

440

 

2,015

 

1,208

 

Production and ad valorem taxes

 

613

 

157

 

1,569

 

551

 

Depreciation, depletion and amortization

 

4,576

 

800

 

9,282

 

2,761

 

Accretion

 

4

 

2

 

9

 

4

 

General and administrative (inclusive of stock-based compensation expense of $836 and $24,800, respectively, for the three and nine months ended September 30, 2012)

 

2,844

 

980

 

31,451

 

3,504

 

 

 

 

 

 

 

 

 

 

 

Total operating costs and expenses

 

8,647

 

2,379

 

44,326

 

8,028

 

 

 

 

 

 

 

 

 

 

 

Operating income (loss)

 

3,846

 

315

 

(17,864

)

1,842

 

 

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Interest and other income

 

12

 

 

31

 

 

Realized and unrealized gains (losses) on derivative instruments

 

(2,191

)

1,759

 

809

 

1,558

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

1,667

 

2,074

 

(17,024

)

3,400

 

 

 

 

 

 

 

 

 

 

 

Less:

 

 

 

 

 

 

 

 

 

Preferred stock dividends

 

(264

)

 

(264

)

 

Net income allocable to participating securities

 

(21

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to common stockholders

 

$

1,382

 

$

2,074

 

$

(17,288

)

$

3,400

 

 

 

 

 

 

 

 

 

 

 

Net earnings (loss) per common share - basic and diluted

 

$

0.04

 

$

0.09

 

$

(0.52

)

$

0.15

 

 

 

 

 

 

 

 

 

 

 

Weighted average number of shares used to calculate net income (loss) attributable to common stockholders - basic and diluted

 

33,000

 

22,091

 

33,000

 

22,091

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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Sanchez Energy Corporation

Condensed Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2012 (Unaudited)

(in thousands)

 

 

 

Series A

 

 

 

 

 

Additional

 

 

 

Total

 

 

 

Preferred Stock

 

Common Stock

 

Paid-in

 

Accumulated

 

Stockholders’

 

 

 

Shares

 

Amount

 

Shares

 

Amount

 

Capital

 

Deficit

 

Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE, December 31, 2011

 

 

$

 

33,000

 

$

330

 

$

215,115

 

$

(304

)

$

215,141

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of preferred shares, net of offering costs of $5,488

 

3,000

 

30

 

 

 

144,482

 

 

144,512

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock awards, net of forfeitures and cancellations

 

 

 

510

 

5

 

(5

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock-based compensation

 

 

 

 

 

24,800

 

 

24,800

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

 

 

 

 

 

(17,024

)

(17,024

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE, September 30, 2012

 

3,000

 

$

30

 

33,510

 

$

335

 

$

384,392

 

$

(17,328

)

$

367,429

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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Sanchez Energy Corporation

Condensed Consolidated Statements of Cash Flows (Unaudited)

(in thousands)

 

 

 

Nine Months Ended September 30,

 

 

 

2012

 

2011

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

Net income (loss)

 

$

(17,024

)

$

3,400

 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

9,282

 

2,761

 

Asset retirement obligation accretion

 

9

 

4

 

Stock-based compensation

 

24,800

 

 

Unrealized gain on derivative instruments

 

(1,594

)

(1,558

)

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

(3,114

)

1,337

 

Other current assets

 

(214

)

 

Price risk management activities, net

 

1,771

 

 

Accounts payable - related entities

 

13,402

 

(3,746

)

Accrued liabilities

 

1,266

 

 

Net cash provided by operating activities

 

28,584

 

2,198

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Additions to oil and natural gas properties

 

(88,798

)

(12,515

)

Proceeds from sale of oil and natural gas properties

 

 

1,598

 

Investment in available-for-sale securities

 

(11,583

)

 

Purchase and settlement on derivative contracts

 

(2,389

)

 

Net cash used in investing activities

 

(102,770

)

(10,917

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Issuance of preferred stock

 

150,000

 

 

Payments for offering costs

 

(5,488

)

(439

)

Net investment by parent

 

 

9,158

 

Net cash provided by financing activities

 

144,512

 

8,719

 

 

 

 

 

 

 

Increase in cash and cash equivalents

 

70,326

 

 

Cash and cash equivalents, beginning of period

 

63,041

 

 

Cash and cash equivalents, end of period

 

$

133,367

 

$

 

 

 

 

 

 

 

NON-CASH INVESTING AND FINANCING ACTIVITIES:

 

 

 

 

 

Asset retirement obligation

 

$

205

 

$

9

 

Change in accrued capital expenditures

 

23,207

 

2,151

 

Deferred premium liabilities

 

563

 

1,941

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

 

Note 1.   Organization

 

Sanchez Energy Corporation (together with its consolidated subsidiaries, the “Company,” “we,” “our,” “us” or similar terms) is an independent exploration and production company focused on the acquisition, exploration, and development of unconventional oil and natural gas resources primarily in the Eagle Ford Shale in South Texas. As of September 30, 2012, the Company had accumulated acreage in the Eagle Ford Shale in Gonzales, Zavala, Frio, Fayette, Lavaca, Atascosa, Webb and DeWitt Counties of South Texas.  In addition, the Company has properties located in the Haynesville Shale in north central Louisiana, which is primarily a natural gas play, and an undeveloped acreage position in Northern Montana, which the Company believes may be prospective for the Heath, Three Forks and Bakken Shales.  The principal markets for the Company’s products are the sale of such products at the wellhead or by transporting production to purchasers’ purchase points.

 

The Company was formed in August 2011 to acquire, explore and develop unconventional oil and natural gas assets.  On December 19, 2011, the Company completed its initial public offering (“IPO”) of 10.0 million shares of common stock, par value $0.01 per share, at a price to the public of $22.00 per share and received net proceeds of approximately $203.3 million in cash (net of expenses and underwriting discounts and commissions).

 

In connection with its IPO, on December 19, 2011, the Company entered into a contribution, conveyance and assumption agreement whereby Sanchez Energy Partners I, LP (“SEP I”) contributed to the Company 100% of the limited liability company interests in SEP Holdings III, LLC (“SEP Holdings III”), which owns interests in unconventional oil and natural gas assets consisting of undeveloped leasehold, proved oil and natural gas reserves and related equipment and other assets (the “SEP I Assets”) in exchange for approximately 22.1 million shares of the Company’s common stock and $50.0 million in cash.  The acquisition of oil and natural gas properties from SEP I was a transaction among entities under common control and, accordingly, the Company recorded the assets and liabilities acquired at their historical carrying values and presented the historical operations of the SEP I Assets on a retrospective basis for all prior periods presented in its financial statements.  In addition, the $50.0 million payment was reflected as a distribution to SEP I in the financial statements.

 

Also in connection with its IPO, the Company entered into a contribution agreement whereby it acquired 100% of the limited liability company interests of Marquis LLC, which owns unevaluated properties in Fayette, Lavaca, Atascosa, Webb and DeWitt Counties of South Texas (the “Marquis Assets”) in exchange for 909,091 shares of the Company’s common stock, valued at $20.0 million, and approximately $89.0 million in cash from the proceeds of the IPO. The acquisition was accounted for as a purchase of assets and recorded at cost at the acquisition date.

 

Also in connection with its IPO, on December 19, 2011, the Company entered into a services agreement and other related agreements with Sanchez Oil & Gas Corporation (“SOG”) pursuant to which SOG (directly or through its subsidiaries) agreed to provide the Company with the services and data that the Company believes are necessary to manage, operate and grow its business, and the Company agreed to reimburse SOG for all direct and indirect costs incurred on its behalf.

 

On June 19, 2012 and September 17, 2012, SEP I distributed substantially all of the approximately 22.1 million shares of the Company’s common stock that SEP I owned to the partners of SEP I (the “Distribution”).  The 21,932,659 shares of common stock distributed to SEP I’s partners constituted 66.5% of the issued and outstanding shares of the Company’s common stock.  The Distribution was a return on SEP I’s partners’ capital contributions to SEP I, thus no consideration was paid to SEP I for the shares of the Company’s common stock distributed.

 

On September 17, 2012, the Company completed a private placement of 3,000,000 shares of 4.875% Cumulative Perpetual Convertible Preferred Stock, Series A (the “Convertible Preferred Stock”), which were sold to a group of qualified institutional buyers pursuant to the Rule 144A exemption from registration under the Securities Act. The private placement included 500,000 shares of Convertible Preferred Stock issued pursuant to the exercise of the initial purchasers’ option to cover over-allotments. The issue price of each share of the Convertible Preferred Stock was $50.00. The Company received net proceeds from the private placement of approximately $144.5 million, after deducting initial purchasers’ discounts and commissions and offering costs payable by the Company of approximately $5.5 million.

 

Note 2.   Summary of Significant Accounting Policies

 

The accompanying condensed consolidated financial statements are unaudited and were prepared from the Company’s records.  The condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP” or “U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X.  The Company derived the condensed consolidated balance sheet as of December 31, 2011 from the

 

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

 

audited financial statements filed in its Annual Report on Form 10-K for the fiscal year ended December 31, 2011 (the “2011 Annual Report”).  Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. GAAP.  These condensed consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the 2011 Annual Report, which contains a summary of the Company’s significant accounting policies and other disclosures.  In the opinion of management, these financial statements include the adjustments and accruals, all of which are of a normal recurring nature, which are necessary for a fair presentation of the results for the interim periods.  These interim results are not necessarily indicative of results to be expected for the entire year.

 

As of September 30, 2012, the Company’s significant accounting policies are consistent with those discussed in Note 2 in the notes to the Company’s consolidated financial statements contained in its 2011 Annual Report.

 

Available-for-Sale Investments

 

At September 30, 2012, the Company held certain investments in marketable securities as a means of temporarily investing the proceeds from its Convertible Preferred stock offering until the funds are needed for operating purposes. These investments are being accounted for as “available-for-sale” investments.  As a result, the investments are reflected at their fair value, based on quoted market prices, with unrealized gains and losses recorded in accumulated other comprehensive income until the investments are sold, at which time the realized gains and losses are included in the results of operations.  As of September 30, 2012, there were no gains or losses recorded in accumulated other comprehensive income due to the fact that the fair value of these investments approximated the costs paid for these securities.  The Company did not have similar type investments during prior periods.

 

Basis of Presentation

 

The acquisition of oil and natural gas properties from SEP I was a transaction among entities under common control and accordingly, the Company recorded the assets and liabilities acquired at their historical carrying values and has presented the historical accounts of the SEP I Assets on a retrospective basis for all prior periods presented in the consolidated financial statements.

 

For periods prior to December 19, 2011, the consolidated financial statements were prepared on a “carve-out” basis from SEP I’s accounts and reflect the historical accounts directly attributable to the SEP I Assets together with allocations of costs and expenses. The financial statements for periods prior to December 19, 2011 may not be indicative of future performance and may not reflect what their results of operations, financial position, and cash flows would have been had the SEP I Assets been operated as an independent company.

 

SOG is a private oil and gas company engaged in the exploration for and development of oil and natural gas. SOG has historically acted as the operator of a significant portion of SEP I’s oil and natural gas properties. SOG provided all employee, management, and administrative support to SEP I and, for periods prior to December 19, 2011, a proportionate share of SOG’s general and administrative costs were allocated to the SEP I Assets. The costs of these services associated with the SEP I Assets were allocated to the SEP I Assets primarily based on the ratio of capital expenditures between the entities to which SOG provides services and the SEP I Assets. However, other factors, such as time spent on general management services and producing property activities, were also considered in the allocation of these costs. Management believes such allocations were reasonable; however, they may not be indicative of the actual expense that would have been incurred had the SEP I Assets been operated as an independent company for periods prior to December 19, 2011. On December 19, 2011, SOG began providing similar types of services to the Company under the services agreement as described below (Note 7).

 

Principles of Consolidation

 

The Company’s condensed consolidated financial statements include the accounts of the Company and its subsidiaries.  All intercompany balances and transactions have been eliminated.

 

Use of Estimates

 

The condensed consolidated financial statements are prepared in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.

 

11



Table of Contents

 

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

 

Note 3.  Oil and Natural Gas Properties

 

The Company’s oil and natural gas properties are accounted for using the full cost method of accounting.  All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Once evaluated, these costs, as well as the estimated costs to retire the assets, are included in the amortization base and amortized to expense using the units-of-production method.  Amortization is calculated based on estimated proved oil and natural gas reserves.  Proceeds from the sale or disposition of oil and natural gas properties are applied to reduce net capitalized costs unless the sale or disposition causes a significant change in the relationship between capitalized costs and the estimated quantity of proved reserves.

 

Capitalized costs (net of accumulated depreciation, depletion and amortization and deferred income taxes) of proved oil and natural gas properties are subject to a full cost ceiling limitation.  The ceiling limits these costs to an amount equal to the present value, discounted at 10%, of estimated future net cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future income taxes.  In accordance with SEC rules, the oil and natural gas prices used to calculate the full cost ceiling are the 12-month average prices, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials.  Price is held constant over the life of the reserves.  If unamortized costs capitalized within the cost pool exceed the ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off are not reinstated for any subsequent increase in the cost center ceiling. No impairment expense was recorded for the three and nine month periods ended September 30, 2012 or 2011.

 

Investments in unproved properties and major development projects are capitalized and excluded from the amortization base until proved reserves associated with the projects can be determined or until impairment occurs.  Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool subject to periodic amortization.  The Company assesses the carrying value of its unproved properties that are not subject to amortization for impairment periodically.  If the results of an assessment indicate that the properties are impaired, the amount of the asset impaired is added to the full cost pool subject to both periodic amortization and the ceiling test.

 

Note 4.  Derivative Instruments

 

To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, or to protect the economics of property acquisitions, the Company periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or, through options, modify the future prices to be realized. These transactions may include price swaps whereby the Company will receive a fixed price for its production and pay a variable market price to the contract counterparty. Additionally, the Company may enter into collars, whereby it receives the excess, if any, of the fixed floor over the floating rate or pays the excess, if any, of the floating rate over the fixed ceiling price. In addition, the Company enters into option transactions, such as puts or put spreads, as a way to manage its exposure to fluctuating prices. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes.

 

Under Accounting Standards Codification (“ASC”) Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the condensed consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The Company will net derivative assets and liabilities for counterparties where it has a legal right of offset.  Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met.  The Company has elected not to designate its current derivative contracts as hedges.  Therefore, changes in the fair value of these instruments are recognized in earnings and included as realized and unrealized gains (losses) on derivative instruments in the condensed consolidated statements of operations.

 

12



Table of Contents

 

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

 

As of September 30, 2012, the Company had oil derivative instruments covering anticipated future production as follows:

 

 

 

Derivative

 

 

 

 

 

 

 

Contract Period

 

Instrument

 

Barrels

 

Purchased

 

Sold

 

October 1, 2012 - December 31, 2012 (1)

 

Put Spread

 

92,000

 

$

90.00

 

n/a

 

October 1, 2012 - December 31, 2012

 

Put Spread

 

115,000

 

$

100.00

 

$

80.00

 

January 1, 2013 - December 31, 2013

 

Put Spread

 

365,000

 

$

95.00

 

$

75.00

 

January 1, 2013 - December 31, 2013

 

Swap

 

182,500

 

$

97.10

 

n/a

 

 


(1) In March 2012, the Company modified its existing put spread transaction by re-purchasing the $70 per barrel put for the period from July through December 2012.

 

The Company deferred the payment of premiums associated with certain of its oil derivative instruments.  At September 30, 2012, the balance of deferred payments totaled approximately $0.6 million. These premiums will be paid to the counterparty with each monthly settlement.

 

Balance Sheet Presentation

 

The Company’s derivatives are presented on a net basis as “Fair value of derivative instruments” on the condensed consolidated balance sheets.  The following information summarizes the fair value of derivative instruments as of September 30, 2012 and December 31, 2011 (in thousands):

 

 

 

September 30,

 

December 31,

 

 

 

2012

 

2011

 

Current asset

 

$

3,348

 

$

1,461

 

Long-term asset

 

868

 

 

 

 

 

 

 

 

Total fair value at period end

 

$

4,216

 

$

1,461

 

 

Gain (Loss) on Derivatives

 

Gains and losses on derivatives are reported on the condensed consolidated statements of operations as “Realized and unrealized gains (losses) on derivative instruments.”  Realized gains (losses) represent amounts related to the settlement of derivative instruments or the expiration of contracts.  Unrealized gains (losses) represent the change in fair value of the derivative instruments to be settled in the future and are non-cash items which fluctuate in value as commodity prices change.  The following summarizes the Company’s realized and unrealized gains (losses) on derivative instruments for the three and nine months ended September 30, 2012 and 2011 (in thousands):

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Realized losses on derivative instruments

 

$

(87

)

$

 

$

(785

)

$

 

Unrealized gains (losses) on derivative instruments

 

(2,104

)

1,759

 

1,594

 

1,558

 

Total realized and unrealized gains (losses) on derivative instruments

 

$

(2,191

)

$

1,759

 

$

809

 

$

1,558

 

 

Note 5.         Fair Value of Financial Instruments

 

Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. Fair value is the price that would be received upon the sale of an asset or

 

13



Table of Contents

 

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

 

paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:

 

Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

 

Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that can be valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.

 

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). The valuation models used to value derivatives associated with the Company’s oil and natural gas production are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although third party quotes are utilized to assess the reasonableness of the prices and valuation techniques, there is not sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.

 

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

 

Fair Value on a Recurring Basis

 

The following tables set forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2012 and December 31, 2011 (in thousands):

 

 

 

September 30, 2012

 

 

 

Active Market

 

 

 

 

 

 

 

 

 

for Identical

 

Observable

 

Unobservable

 

Total

 

 

 

Assets

 

Inputs

 

Inputs

 

Carrying

 

 

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

Value

 

Description

 

 

 

 

 

 

 

 

 

LTIP (1)

 

$

 

$

(2,492

)

$

 

$

(2,492

)

Available-for-sale marketable securities

 

11,583

 

 

 

11,583

 

Oil derivative instruments

 

 

618

 

3,598

 

4,216

 

Total

 

$

11,583

 

$

(1,874

)

$

3,598

 

$

13,307

 

 


(1) See Note 10 for further discussion on stock-based compensation expenses for certain grants accounted for under ASC 505-50 and 718.

 

 

 

December 31, 2011

 

 

 

Active Market

 

 

 

 

 

 

 

 

 

for Identical

 

Observable

 

Unobservable

 

Total

 

 

 

Assets

 

Inputs

 

Inputs

 

Carrying

 

 

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

Value

 

Description

 

 

 

 

 

 

 

 

 

Oil derivative instruments

 

$

 

$

 

$

1,461

 

$

1,461

 

Total

 

$

 

$

 

$

1,461

 

$

1,461

 

 

14



Table of Contents

 

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

 

The Company’s oil derivative instruments are accounted for at fair value on a recurring basis.  The net fair value at September 30, 2012 and December 31, 2011 of $4.2 million and $1.5 million, respectively, were classified as Level 3.  The fair values of derivative instruments are based on a third-party pricing model which utilizes inputs that include (a) quoted forward prices for oil and gas, (b) discount rates, (c) volatility factors and (d) current market and contractual prices, as well as other relevant economic measures. The estimates of fair value are compared to the values provided by the counterparty for reasonableness. Derivative instruments are subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of the Company’s derivative instruments, but to date has not had a material impact on estimates of fair values. Significant changes in the quoted forward prices for commodities and changes in market volatility generally lead to corresponding changes in the fair value measurement of the Company’s oil derivative instruments.

 

The following table sets forth a reconciliation of changes in the fair value of the Company’s oil derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):

 

 

 

Significant Unobservable Inputs

 

 

 

(Level 3)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Beginning balance

 

$

7,369

 

$

1,740

 

$

1,461

 

$

 

Realized and unrealized gains (losses) included in earnings

 

(2,191

)

1,759

 

809

 

1,558

 

Settlements

 

(962

)

 

(1,190

)

 

Purchase of derivative contracts

 

 

 

2,952

 

1,941

 

Buy out of derivative contracts

 

 

 

184

 

 

Ending balance

 

$

4,216

 

$

3,499

 

$

4,216

 

$

3,499

 

 

 

 

 

 

 

 

 

 

 

Change in unrealized gains (losses) included in earnings related to derivatives still held as of September 30, 2012 and 2011

 

$

(1,994

)

$

1,759

 

$

1,523

 

$

1,558

 

 

Fair Value on a Non-Recurring Basis

 

The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis.  As it relates to the Company, the statement applies to the initial recognition of asset retirement obligations for which fair value is used.

 

The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments.  As there is no corroborating market activity to support the assumptions, the Company has designated these liabilities as Level 3.  A reconciliation of the beginning and ending balances of the Company’s asset retirement obligations is presented in Note 6.

 

Note 6.         Asset Retirement Obligations

 

Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment, remediation costs, and well life. The inputs are calculated based on historical data as well as current estimates. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, any gain or loss is treated as an adjustment to the full cost pool.

 

15



Table of Contents

 

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

 

The changes in the asset retirement obligation for the nine months ended September 30, 2012 and 2011 were as follows (in thousands):

 

 

 

2012

 

2011

 

Abandonment liability as of January 1,

 

$

83

 

$

60

 

Liabilities incurred during period

 

205

 

9

 

Accretion expense

 

9

 

4

 

Abandonment liability as of September 30,

 

$

297

 

$

73

 

 

Note 7.         Related Party Transactions

 

SOG, headquartered in Houston, Texas, is a private full service oil and natural gas company engaged in the exploration and development of oil and natural gas primarily in the South Texas and onshore Gulf Coast areas on behalf of its affiliates.  The Company refers to SOG, SEP I, and their affiliates (but excluding the Company) collectively as the “Sanchez Group.”

 

Services and Other Agreements

 

The Company does not have any employees.  On December 19, 2011 it entered into a services agreement with SOG pursuant to which specified employees of SOG provide certain services with respect to the Company’s business under the direction, supervision and control of SOG. Pursuant to this arrangement, SOG performs centralized corporate functions for the Company, such as general and administrative services, geological, geophysical and reserve engineering, lease and land administration, marketing, accounting, operational services, information technology services, compliance, insurance maintenance and management of outside professionals. The Company compensates SOG for the services at a price equal to SOG’s cost of providing such services, including all direct costs and indirect administrative and overhead costs (including the allocable portion of salary, bonus, incentive compensation and other amounts paid to persons that provide the services on SOG’s behalf) allocated in accordance with SOG’s regular and consistent accounting practices, including for any such costs arising from amounts paid directly by other members of the Sanchez Group on SOG’s behalf or borrowed by SOG from other members of the Sanchez Group, in each case, in connection with the performance by SOG of services on the Company’s behalf. The Company also reimburses SOG for sales, use or other taxes, or other fees or assessments imposed by law in connection with the provision of services to the Company (other than income, franchise or margin taxes measured by SOG’s net income or margin and other than any gross receipts or other privilege taxes imposed on SOG) and for any costs and expenses arising from or related to the engagement or retention of third party service providers.

 

The initial term of the services agreement is five years. The term will automatically extend for additional 12-month periods unless either party provides 180 days written notice otherwise prior to the expiration of the applicable 12-month period. Either party may terminate the agreement at any time upon 180 days written notice.

 

In connection with the services agreement, SOG also entered into a licensing agreement with the Company pursuant to which it granted to the Company a license to the unrestricted use of proprietary seismic, geological and geophysical information related to the Company’s properties owned by SOG, and all such information related to the Company’s properties not otherwise licensed to the Company will be interpreted and used by SOG for the Company’s benefit under the services agreement. In addition, SOG entered into a contract operating agreement with the Company under which SOG agreed to develop, manage and operate the Company’s properties or engage a responsible unaffiliated industry operator and joint owner for such development, management and operation.  No costs, fees or other expenses are payable by the Company under these agreements. The licensing agreement and contract operating agreement will terminate concurrently with the termination or expiration of the services agreement.

 

Prior to entering into the services agreement, SOG incurred general and administrative expenses that were allocated to the Company based on the ratio of capital expenditures between the entities to which SOG provided services and the SEP I Assets.  Other factors, such as time spent on general management services and producing property activities, were also considered in the allocation of these costs.  Beginning December 19, 2011, the costs were allocated to the Company according to the terms of the services agreement.  Salaries and associated benefit costs of SOG employees are allocated to the Company based on the actual time spent by the professional staff on the properties and business activities of the Company. General and administrative costs, such as office rent, utilities, supplies, and other overhead costs, are allocated to the Company based on a fixed percentage that is reviewed quarterly and adjusted, if needed, based on the activity levels of services provided to the Company. General and administrative costs that are specifically incurred by or for the specific benefit of the Company are charged directly to the Company.  Expenses allocated to the Company for general and administrative expenses for the three and nine months ended September 30, 2012 and 2011 (in thousands) are as follows:

 

16



Table of Contents

 

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Administrative fees

 

$

1,341

 

$

740

 

$

3,586

 

$

3,181

 

Third-party expenses

 

667

 

240

 

3,065

 

323

 

Total included in general and administrative expenses

 

$

2,008

 

$

980

 

$

6,651

 

$

3,504

 

 

As of September 30, 2012, the Company had a payable to SOG of $15.0 million which is reflected as “Accounts payable — related entities” in the condensed consolidated balance sheets.  This amount consists primarily of obligations for general and administrative costs and operating expenses for the Company’s oil and natural gas properties operated by SOG.

 

Note 8.         Accrued Liabilities

 

The following information summarizes accrued liabilities as of September 30, 2012 and December 31, 2011 (in thousands):

 

 

 

September 30,

 

December 31,

 

 

 

2012

 

2011

 

Capital expenditures

 

$

23,456

 

$

249

 

General and administrative costs

 

744

 

170

 

Production taxes

 

202

 

56

 

Ad valorem taxes

 

353

 

5

 

Lease operating expenses

 

244

 

46

 

Total accrued liabilities

 

$

24,999

 

$

526

 

 

Note 9.         Stockholders’ Equity

 

Common Stock Offering - On December 19, 2011, the Company completed its IPO of 10.0 million shares of common stock, par value $0.01 per share, at a price to the public of $22.00 per share.  The Company received net proceeds of approximately $203.3 million from the sale of the shares of common stock (net of expenses and underwriting discounts and commissions).

 

Preferred Stock Offering - On September 17, 2012, the Company completed a private placement of 3,000,000 shares of Convertible Preferred Stock, which were sold to a group of qualified institutional buyers pursuant to the Rule 144A exemption from registration under the Securities Act. The private placement included 500,000 shares of Convertible Preferred Stock issued pursuant to the exercise of the initial purchasers’ option to cover over-allotments. The issue price of each share of the Convertible Preferred Stock was $50.00. The Company received net proceeds from the private placement of approximately $144.5 million, after deducting initial purchasers’ discounts and commissions and offering costs payable by the Company of approximately $5.5 million.

 

Pursuant to the Certificate of Designations for the Convertible Preferred Stock (the “Certificate of Designations), each share of Convertible Preferred Stock is convertible at any time at the option of the holder thereof at an initial conversion rate of 2.3250 shares of common stock per share of Convertible Preferred Stock (which is equal to an initial conversion price of approximately $21.51 per share of common stock) and is subject to specified adjustments. Based on the initial conversion price, approximately 6,975,000 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Convertible Preferred Stock.

 

The annual dividend on each share of Convertible Preferred Stock is 4.875% on the liquidation preference of $50 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, commencing on January 1, 2013, when, as and if declared by the Company’s Board of Directors (the “Board”). No dividends were accrued or accumulated prior to September 17, 2012. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof.  As of September 30, 2012, cumulative, undeclared dividends on the Convertible Preferred Stock amounted to approximately $0.3 million.

 

17



Table of Contents

 

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

 

Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, holders of the Convertible Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such arrearage is paid in full, the holders will be entitled to elect two directors and the number of directors on the Company’s Board will increase by that same number.

 

At any time on or after October 5, 2017, the Company may at its option cause all outstanding shares of the Convertible Preferred Stock to be automatically converted into common stock at the then-prevailing conversion price, if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130% of the then-prevailing conversion price for a specified period prior to the conversion.

 

If a holder elects to convert shares of Convertible Preferred Stock upon the occurrence of certain specified fundamental changes, the Company will be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option time value of the shares of Convertible Preferred Stock as a result of the fundamental change.

 

Earnings (Loss) Per Share — Shares issued to SEP I in exchange for the SEP I Assets have been retroactively reflected as outstanding for all periods presented. The shares of common stock issued in exchange for the Marquis Assets as well as the shares issued in the IPO were considered outstanding since the date of these transactions.

 

Basic net earnings (loss) per common share are computed using the two-class method.  The two-class method is required for those entities that have participating securities.  The two-class method is an earnings allocation formula that determines net earnings (loss) per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. The Company’s restricted shares of common stock (see Note 10) are participating securities under ASC 260, “Earnings per Share,” because they may participate in undistributed earnings with common stock.  Participating securities do not have a contractual obligation to share in the Company’s losses.  Therefore, in periods of net loss, no portion of the loss is allocated to participating securities.

 

Diluted net earnings (loss) per common share reflect the dilutive effects of the participating securities using the two-class method or the treasury stock method, whichever is more dilutive.  They also reflect the effects of the potential conversion of the Convertible Preferred Stock using the if-converted method, if the effect is dilutive.

 

18



Table of Contents

 

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

 

The following table shows the computation of basic and diluted net earnings (loss) per share for the three and nine months ended September 30, 2012 and 2011 (in thousands, except per share amounts):

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

1,667

 

$

2,074

 

$

(17,024

)

$

3,400

 

Less:

 

 

 

 

 

 

 

 

 

Preferred stock dividends

 

(264

)

 

(264

)

 

Net income allocable to participating securities(1)(4)

 

(21

)

 

 

 

Net income (loss) attributable to common stockholders

 

$

1,382

 

$

2,074

 

$

(17,288

)

$

3,400

 

 

 

 

 

 

 

 

 

 

 

Weighted average number of unrestricted outstanding common shares used to calculate basic net earnings (loss) per share(2)

 

33,000

 

22,091

 

33,000

 

22,091

 

Dilutive shares (3)(4)

 

 

 

 

 

Denominator for diluted earnings (loss) per common share

 

33,000

 

22,091

 

33,000

 

22,091

 

 

 

 

 

 

 

 

 

 

 

Net earnings (loss) per common share - basic and diluted

 

$

0.04

 

$

0.09

 

$

(0.52

)

$

0.15

 

 


(1) For the nine months ended September 30, 2012, no losses were allocated to participating restricted stock because such securities do not have a contractual obligation to share in the Company’s losses.

(2) For purposes of this calculation, the weighted average number of unrestricted outstanding common shares includes: (i) the 22,090,909 shares issued for the SEP I Assets, (ii) the 909,091 shares issued for the Marquis Assets and (iii) the 10,000,000 shares issued in the IPO for the three and nine months ended September 30, 2012.

(3) The three and nine months ended September 30, 2012 exclude 71,842 and 254,757 shares, respectively, of weighted average restricted stock and 996,429 and 330,931 shares, respectively, of common stock resulting from an assumed conversion of the Company’s Convertible Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

(4) The Company had no outstanding stock awards prior to its initial grants in January 2012.

 

Note 10.  Stock-Based Compensation

 

At the Annual Meeting of Stockholders of the Company held on May 23, 2012, the Company’s stockholders approved the Sanchez Energy Corporation Amended and Restated 2011 Long Term Incentive Plan (the “LTIP”). The Company’s Board had previously approved the amendment of the Sanchez Energy Corporation 2011 Long Term Incentive Plan on April 16, 2012, subject to stockholder approval.

 

The LTIP provides for the award of stock options, stock appreciation rights, restricted stock, phantom stock, other stock-based awards or stock awards, or any combination thereof.  Any director or consultant of the Company or any employee of the Company, a subsidiary of the Company or a Sanchez Group Member (as defined in the LTIP) is eligible to participate in the LTIP. The LTIP provides that the number of shares of the Company’s common stock available for incentive awards is 15% of the issued and outstanding shares of common stock.

 

The Company records stock-based compensation expense for awards granted to its directors (for their services as directors) in accordance with the provisions of ASC 718, “Compensation — Stock Compensation.”  Stock-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. The fair value of restricted stock awards is based on the closing sales price of the Company’s common stock on the grant date.

 

Awards granted to employees of the Sanchez Group (including those employees of the Sanchez Group who also serve as the Company’s officers) and consultants in exchange for services are considered awards to non-employees and the Company records stock-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, “Equity-Based Payments to Non-Employees.”   For awards granted to non-employees, the Company records compensation expenses equal to the fair value of the stock-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date.  Compensation expense for unvested awards to non-employees is revalued at each period end and is

 

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

 

amortized over the vesting period of the stock-based award.  Stock-based payments are measured based on the fair value of goods or services received or the equity instruments granted, whichever is more determinable.

 

During the nine months ended September 30, 2012, the Company issued 17,200 shares of restricted common stock pursuant to the LTIP to two directors of the Company that vest one year from the date of grant.  Pursuant to ASC 718, stock based compensation expense for these awards was based on their grant date fair value of $17.57 and $23.91 per share and is being amortized over the one year vesting period.

 

The Company also issued approximately 1.6 million shares of restricted common stock pursuant to the LTIP to certain employees of SOG (including the Company’s officers), with whom the Company has a services agreement.  Approximately 1.1 million shares of restricted common stock were to vest equally over a two-year period and approximately 0.5 million shares of restricted common stock vest in equal annual amounts over a three-year period.  On June 15, 2012, at the recommendation of the Company’s President and Chief Executive Officer and with the consent of the recipients of these awards, the 1.1 million shares of restricted common stock that were to vest equally over a two-year period were rescinded and cancelled by the Board.  All other grants previously made to employees of SOG were not modified or cancelled as a result of the rescissions.

 

For the restricted stock awards granted to non-employees that were not rescinded and cancelled, stock-based compensation expense is based on fair value remeasured at each reporting period and recognized over the vesting period using the straight-line method.  Compensation expense for these awards will be revalued at each period end until vested.

 

For the restricted stock awards granted to non-employees that were rescinded and cancelled, stock-based compensation expense was based on the fair value at the date of cancellation, and all of the associated unrecognized compensation expense was accelerated and recognized as stock-based compensation expense.  At the date of cancellation, the fair value of the stock awards cancelled was approximately $22.3 million, or $20.28 per restricted share.

 

The Company recognized the following stock-based compensation expense (in thousands) for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Restricted stock awards, directors

 

$

91

 

$

 

$

184

 

$

 

Restricted stock awards, non-employees

 

745

 

 

2,308

 

 

Restricted stock awards, cancelled

 

 

 

22,308

 

 

Total stock-based compensation expense

 

$

836

 

$

 

$

24,800

 

$

 

 

Based on the $20.43 per share closing price of the Company’s common stock on September 30, 2012, there was approximately $7.9 million of unrecognized compensation cost related to these non-vested restricted shares outstanding.  The cost is expected to be recognized over an average period of approximately 2.3 years.

 

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

 

A summary of the status of the non-vested shares as of September 30, 2012 is presented below:

 

 

 

Number of

 

 

 

Non-Vested

 

 

 

Shares

 

Non-vested common stock at December 31, 2011

 

 

Granted

 

1,622,200

 

Cancelled

 

(1,100,000

)

Forfeited

 

(11,900

)

Non-vested common stock at September 30, 2012

 

510,300

 

 

As of September 30, 2012, approximately 4.4 million shares remain available for future issuance to participants.

 

Note 11.  Income Taxes

 

The SEP I Assets contributed by SEP I were historically owned by a limited partnership that is not a taxable entity and is a disregarded entity for federal income tax purposes.  SEP I’s taxable income or loss was allocated to the limited and general partners of SEP I.  With the transfer of the properties to the Company, the SEP I Assets’ operations are now subject to federal and state income taxes.

 

The Company’s estimated annual effective income tax rates are used to allocate expected annual income tax expense to interim periods. The rates are determined based on the ratio of estimated annual income tax expense to estimated annual income before income taxes by taxing jurisdiction, except for discrete items, which are significant, unusual or infrequent items for which income taxes are computed and recorded in the interim period in which the specific transaction occurs. The estimated annual effective income tax rates are applied to the year-to-date income before income taxes by taxing jurisdiction to determine the income tax expense allocated to the interim period. The Company updates its estimated annual effective income tax rate at the end of each quarterly period considering the geographic mix of income based on the tax jurisdictions in which the Company operates. Actual results that are different from the assumptions used in estimating the annual effective income tax rate will impact future income tax expense. The Company’s estimated annual effective income tax rate differs from the U.S. federal statutory corporate income tax rate of 35% due to the expectation that the Company will continue to provide a full valuation allowance against its deferred tax assets.  The following table sets forth a reconciliation of the statutory federal income tax with the income tax provision (in thousands):

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2012

 

2012

 

 

 

 

 

 

 

Income tax expense (benefit)

 

$

584

 

$

(5,958

)

Rescission of restricted stock

 

 

7,808

 

Valuation allowance

 

(584

)

(1,850

)

Net income tax provision

 

$

 

$

 

 

At September 30, 2012, the Company had estimated net operating loss carryforwards of $76.3 million which begin to expire in 2031.

 

In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized.  The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible.  The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and therefore has established a full valuation allowance to reduce the net deferred tax asset to zero at September 30, 2012 and December 31, 2011.  The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

 

At September 30, 2012, the Company had no material uncertain tax positions.

 

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

 

Note 12. Commitments and Contingencies

 

From time to time, the Company may be involved in lawsuits that arise in the normal course of its business. It is the opinion of management and counsel that the outcome of any such lawsuits will not materially affect the financial position and operations of the Company.

 

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our condensed consolidated financial statements and related notes appearing in Item 1 of this Quarterly Report on Form 10-Q and information contained in our 2011 Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance.  We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material.  Some of the key factors which could cause actual results to vary from our expectations include: changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and in our 2011 Annual Report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict.  In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

 

Business Overview

 

We are an independent exploration and production company focused on the exploration, acquisition and development of unconventional oil and natural gas resources in the Eagle Ford Shale in South Texas.  As of September 30, 2012, we had accumulated approximately 95,000 net leasehold acres in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale in Gonzales, Zavala, Frio, Fayette, Lavaca, Atascosa, Webb and DeWitt Counties of South Texas.

 

Initial Public Offering

 

On December 19, 2011, we completed our IPO of 10.0 million shares of common stock, par value $0.01 per share, at a price to the public of $22.00 per share.  We received net proceeds of approximately $203.3 million from the sale of the shares of common stock (net of expenses and underwriting discounts and commissions).  We paid $50 million of the net proceeds from the offering as partial consideration (together with our issuance to SEP I of approximately 22.1 million shares of our common stock) for the contribution by SEP I of the limited liability company interests in SEP Holdings III and approximately $89 million of the net proceeds as partial consideration (together with our issuance of 909,091 shares of our common stock) for the acquisition of the limited liability company interests in Marquis LLC.  SEP Holdings III and Marquis LLC each own interests in certain oil, natural gas and related assets.

 

Distribution

 

On June 19, 2012 and September 17, 2012, SEP I distributed substantially all of the approximately 22.1 million shares of our common stock that SEP I owned to the partners of SEP I (the “Distribution”).  The 21,932,659 shares of common stock distributed to SEP I’s partners constituted 66.5% of the issued and outstanding shares of our common stock.  The Distribution was a return on SEP I’s partners’ capital contributions to SEP I, thus no consideration was paid to SEP I for the shares of our common stock distributed.

 

Preferred Stock Offering

 

On September 17, 2012, we completed a private placement of 3,000,000 shares of Convertible Preferred Stock, which were sold to a group of qualified institutional buyers pursuant to the Rule 144A exemption from registration under the Securities Act. The private placement included 500,000 shares of Convertible Preferred Stock issued pursuant to the exercise of the initial purchasers’ option to cover over-allotments.  The issue price of each share of the Convertible Preferred Stock was $50.00. We received net proceeds from the private placement of approximately $144.5 million, after deducting initial purchasers’ discounts and commissions and offering costs payable by us of approximately $5.5 million.

 

Basis of Presentation

 

Prior to the Distribution, SEP I was under common control with us.  Because the SEP I Assets were acquired from an “entity under common control with us,” we recorded the SEP I Assets retrospectively at their historical carrying values, and no goodwill or other intangible assets were recognized.  We acquired the Marquis Assets from parties not under common control with us, and accordingly, the Marquis Assets were recorded at cost and have been included in our historical financial statements since December 

 

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19, 2011.  Likewise, our reserve and historical operations data for periods prior to December 19, 2011 provided in this Quarterly Report on Form 10-Q reflect the SEP I Assets.

 

Our historical financial statements as of and for the periods prior to December 19, 2011, the date SEP I contributed the SEP I Assets to us, were prepared on a “carve-out” basis from SEP I’s accounts.  As such, they reflect the historical accounts directly attributable to the SEP I Assets together with allocations of costs and expenses.

 

SOG is a private oil and gas company engaged in the exploration for and development of oil and natural gas. SOG has historically acted as the operator of a significant portion of SEP I’s oil and natural gas properties. SOG provided all employee, management, and administrative support to SEP I and, for periods prior to December 19, 2011, a proportionate share of SOG’s general and administrative costs were allocated to the SEP I Assets. The costs of these services associated with the SEP I Assets were allocated to the SEP I Assets primarily based on the ratio of capital expenditures between the entities to which SOG provides services and the SEP I Assets. However, other factors, such as time spent on general management services and producing property activities, were also considered in the allocation of these costs. Management believes such allocations were reasonable; however, they may not be indicative of the actual expense that would have been incurred had the SEP I Assets been operated as an independent company for periods prior to December 19, 2011.  On December 19, 2011, SOG began providing similar types of services to the Company under the services agreement as described in Note 7 of the notes to the condensed consolidated financial statements.

 

Our Properties

 

Our Eagle Ford Shale acreage is comprised of approximately 9,500 net acres in Gonzales County, Texas, which we refer to as our Palmetto area, approximately 28,500 net acres in Zavala and Frio Counties, Texas, which we refer to as our Maverick area, and approximately 57,100 net acres in Fayette, Lavaca, Atascosa, Webb and DeWitt Counties, South Texas, which we refer to as our Marquis area.  We own all rights and depths on the majority of our Eagle Ford Shale acreage. We believe this acreage to be prospective for other zones, including the Buda Limestone, Austin Chalk and Pearsall Shale formations that lie above and below the Eagle Ford Shale.  We are currently evaluating these other zones, which may present us with additional drilling locations. Several of our existing wells are either producing from or have logged pay in the Buda Limestone and the Austin Chalk formations.

 

In addition, we have approximately 1,000 net acres in the Haynesville Shale in Natchitoches Parish, Louisiana. We do not currently anticipate spending any capital on our Haynesville acreage in the near future. The majority of our Haynesville leases extend through 2013, giving us and our partners the option to accelerate drilling should natural gas prices increase. Finally, we have amassed approximately 82,000 net acres in northern Montana, which we believe may be prospective for the Heath, Three Forks and Bakken Shales.  Our lease terms are for five years with an option in 2013 to renew for another five years at $10 per acre, giving us time to allow the industry activity to develop the trend before we devote significant drilling capital to our acreage position.

 

Outlook

 

Beginning in the second half of 2008, the United States and other industrialized countries experienced a significant economic slowdown, which led to a substantial decline in worldwide energy demand. During this same period, North American natural gas supply was increasing as a result of the rise in domestic unconventional natural gas production. The combination of lower energy demand due to the economic slowdown and higher North American natural gas supply resulted in significant declines in oil, natural gas liquids (“NGL”) and natural gas prices. While oil and NGL prices started to steadily increase beginning in the second quarter of 2009, natural gas prices remained depressed, recently hitting a 10-year low, due to a continued increase in natural gas supply and weak offsetting demand growth. The outlook for a worldwide economic recovery in 2013 remains uncertain, and the timing of a recovery in worldwide demand for energy is difficult to predict. As a result, it is likely that commodity prices will continue to be volatile during the remainder of 2012 and 2013. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce, the price of our common stock and our access to capital.

 

Significant factors that may impact future commodity prices include the political and economic developments currently impacting Iran, Egypt, Libya and the Middle East in general; the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas; the impact of sovereign debt issues in Europe; and overall North American oil and natural gas supply and demand fundamentals. Although we cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will be affected, the prices for any oil, natural gas or NGLs that we produce will generally approximate market prices in the geographic region of the production.

 

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As an oil and natural gas company, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. Our future growth will depend on our ability to continue to add estimated reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through acquisitions and development projects and improving the economics of producing oil and natural gas from our properties. We expect these acquisition opportunities may come from SEP I and its respective affiliates, as well as from unrelated third parties. Our ability to add estimated reserves through acquisitions and development projects is dependent on many factors, including our ability to raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel.

 

Results of Operations

 

Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011

 

Revenue and Production

 

The following table summarizes production, average sales prices and operating revenue for our oil and natural gas operations for the periods indicated (in thousands, except average sales price and percentages):

 

 

 

Three Months Ended

 

Increase (Decrease)

 

 

 

September 30,

 

2012 vs 2011

 

 

 

2012

 

2011

 

$

 

%

 

Net Production:

 

 

 

 

 

 

 

 

 

Oil (mbo)

 

122.3

 

30.4

 

91.9

 

302

%

Natural gas (mmcf)

 

67.9

 

12.5

 

55.4

 

443

%

Total oil equivalent (mboe)

 

133.7

 

32.5

 

101.2

 

311

%

 

 

 

 

 

 

 

 

 

 

Average Sales Price:

 

 

 

 

 

 

 

 

 

Oil ($ per bo)(1)

 

$

100.61

 

$

86.55

 

$

14.06

 

16

%

Natural gas ($ per mcf)

 

$

2.73

 

$

4.89

 

$

(2.16

)

-44

%

Oil equivalent ($ per boe)(1)

 

$

93.48

 

$

82.89

 

$

10.59

 

13

%

 

 

 

 

 

 

 

 

 

 

REVENUES:

 

 

 

 

 

 

 

 

 

Oil sales

 

$

12,308

 

$

2,633

 

$

9,675

 

367

%

Natural gas sales

 

185

 

61

 

124

 

203

%

Total revenues

 

$

12,493

 

$

2,694

 

$

9,799

 

364

%

 


(1) Excludes the impact of oil derivative instruments.

 

Net Production. Our total production for the three months ended September 30, 2012 increased by 71% compared to the second quarter of 2012 and was 311% higher than the same period of 2011 due primarily to production from seven wells that had first sales in the third quarter of 2012.  Approximately 47% of our third quarter 2012 production is from the Palmetto area where we added one producing well during the period for a total of eleven wells producing during the period compared to five wells during the same period of 2011. In our Maverick area, we added production from six new wells for a total of nine producing wells during the third quarter of 2012 compared to three wells in the comparable 2011 period.  Approximately 32% of our third quarter production is from the Maverick area.  In our Marquis area, which accounted for approximately 19% of our third quarter production, we added two producing wells. These wells represented our first production from the Marquis area.  In the third quarter of 2012, 92% of our production was oil and 8% was natural gas compared to 94% oil and 6% natural gas in the same period of 2011.

 

Average Sales Price. Our average realized oil price for the three months ended September 30, 2012 was $100.61 per bo, which is 16% higher than the comparable period in 2011.  The average price realized for our natural gas production in the third quarter of 2012 was $2.73 per mcf, which is 44% lower than the average sales price in the third quarter of 2011 of $4.89 per mcf.

 

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Revenues.  Oil and natural gas revenues totaled approximately $12.5 million and $2.7 million for the three months ended September 30, 2012 and 2011, respectively. Oil sales revenue for the three months ended September 30, 2012 increased $9.7 million, $8.0 million attributable to the increase in production and $1.7 million due to the higher average sales price compared to the same period in 2011.  Natural gas sales revenue for the three months ended September 30, 2012 increased compared to the same period in 2011, but the impact of our increased production was partially offset by the impact of lower average realized prices compared to the third quarter of 2011.

 

Costs and Operating Expenses

 

The table below presents a detail of expenses for the periods indicated (in thousands, except percentages):

 

 

 

Three Months Ended

 

Increase (Decrease)

 

 

 

September 30,

 

2012 vs 2011

 

 

 

2012

 

2011

 

$

 

%

 

OPERATING COSTS AND EXPENSES:

 

 

 

 

 

 

 

 

 

Oil and natural gas production expenses

 

$

610

 

$

440

 

$

170

 

39

%

Production and ad valorem taxes

 

613

 

157

 

456

 

290

%

Depreciation, depletion and amortization

 

4,576

 

800

 

3,776

 

472

%

Accretion

 

4

 

2

 

2

 

*

 

General and administrative (inclusive of stock-based compensation expense of $836 for the three months ended September 30, 2012)

 

2,844

 

980

 

1,864

 

190

%

Total operating costs and expenses

 

8,647

 

2,379

 

6,268

 

263

%

 

 

 

 

 

 

 

 

 

 

Interest and other income

 

12

 

 

12

 

*

 

Realized and unrealized gains (losses) on derivative instruments

 

(2,191

)

1,759

 

(3,950

)

-225

%

Income tax expense

 

 

 

 

*

 

 


* Not meaningful.

 

Oil and Natural Gas Production Expenses.  Oil and natural gas production expenses are the costs incurred to produce our oil and natural gas, as well as the daily costs incurred to maintain our producing properties. Such costs also include field personnel costs, utilities, chemical additives, salt water disposal, maintenance, repairs and occasional well workover expenses related to our oil and natural gas properties. Our oil and natural gas production expenses increased 39% to approximately $0.6 million for the three months ended September 30, 2012 as compared to $0.4 million for the same period in 2011. The increase in oil and natural gas production expenses in the third quarter of 2012 compared to the same period of 2011 is directly attributable to the increase in production from our increased drilling activities in the Eagle Ford Shale.

 

Production and Ad Valorem Taxes.  Production and ad valorem taxes are paid on produced oil and natural gas based upon a percentage of gross revenues sold at market prices or at fixed rates established by state or local taxing authorities. Our production and ad valorem taxes totaled $0.6 million and $0.2 million for the three months ended September 30, 2012 and 2011, respectively. The increase in production and ad valorem taxes in the third quarter of 2012 compared to the same period in 2011 was due to the significant increase in production volumes.

 

Depreciation, Depletion and Amortization.  Depletion, depreciation and amortization (“DD&A”) reflects the systematic expensing of the capitalized costs incurred in the acquisition, exploration and development of oil and natural gas properties. We use the full-cost method of accounting and accordingly, we capitalize all costs associated with the acquisition, exploration and development of oil and natural gas properties, including unproved and unevaluated property costs. Internal costs are capitalized only to the extent they are directly related to acquisition, exploration and development activities and do not include any costs related to production, selling or general corporate administrative activities. Capitalized costs of oil and natural gas properties are amortized using the units of production method based upon production and estimates of proved oil and natural gas reserve quantities. Unproved and unevaluated property costs are excluded from the amortizable base used to determine DD&A expense. Our DD&A expense for

 

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the third quarter of 2012 increased approximately $3.8 million to $4.6 million ($34.24 per boe) from $0.8 million ($24.62 per boe) in the third quarter of 2011.  This increase in the depletion rate primarily resulted from a substantial increase in the basis of our oil and natural gas properties.  Higher production for the third quarter of 2012 as compared to the same period in 2011 resulted in a $2.5 million increase in expense and the change in the depletion rate resulted in a $1.3 million increase in expense.

 

General and Administrative Expenses.  Our general and administrative (“G&A”) expenses, including stock-based compensation expense, totaled $2.8 million for the three months ended September 30, 2012 compared to $1.0 million for the same period in 2011.  Excluding the stock-based compensation in the third quarter of 2012, G&A expenses were $2.0 million, an increase of 105% over the prior year third quarter.  This increase was due to higher costs associated with the new public entity, consisting primarily of legal expenses, investor relation costs and consulting services.  For the three months ended September 30, 2012, we recorded non-cash stock-based compensation expense of approximately $0.8 million.

 

Commodity Derivative Transactions.  We apply mark-to-market accounting to our derivative contracts; therefore the full volatility of the non-cash change in fair value of our outstanding contracts is reflected in other income and expense.  During the three months ended September 30, 2012, we recognized a $2.1 million unrealized loss on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $0.1 million realized loss associated with settlements and/or expirations on our commodity derivative contracts.  During the three months ended September 30, 2011, we recognized a $1.8 million unrealized gain related to the change in fair value of our derivative contracts.  Because our outstanding contracts at September 30, 2011 related to 2012 production, no settlements were recognized in the prior year period.

 

Income Tax Expense.   The properties contributed by SEP I were historically owned by a limited partnership that is not a taxable entity and is a disregarded entity for federal income tax purposes.  Their taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statements of operations, was allocated to the limited and general partners of SEP I.  With the transfer of the SEP I Assets to us, the SEP I Assets’ operations are now subject to federal and state income taxes.  At the date of acquisition, we estimated that the aggregate net tax basis of the SEP I Assets exceeded the aggregate net book basis by $24.9 million, resulting in a deferred tax asset of $8.7 million, which was fully offset by a valuation allowance.

 

Effective December 19, 2011, we began accounting for income taxes using the asset and liability method.  Deferred tax assets and liabilities arise from the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.  Valuation allowances are established when necessary to reduce the deferred tax asset to the amount more likely than not to be recovered.  We believe that after considering all the available evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, we are not able to determine that it is more likely than not that the deferred tax assets will be realized and therefore we have established a full valuation allowance to reduce the net deferred tax asset to zero at September 30, 2012 and December 31, 2011.  We will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

 

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Table of Contents

 

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

 

Revenue and Production

 

The following table summarizes production, average sales prices and operating revenue for our oil and natural gas operations for the periods indicated (in thousands, except average sales price and percentages):

 

 

 

Nine Months Ended

 

Increase (Decrease)

 

 

 

September 30,

 

2012 vs 2011

 

 

 

2012

 

2011

 

$

 

%

 

Net Production:

 

 

 

 

 

 

 

 

 

Oil (mbo)

 

253.5

 

102.2

 

151.3

 

148

%

Natural gas (mmcf)

 

257.1

 

93.1

 

164.0

 

176

%

Total oil equivalent (mboe)

 

296.4

 

117.7

 

178.7

 

152

%

 

 

 

 

 

 

 

 

 

 

Average Sales Price:

 

 

 

 

 

 

 

 

 

Oil ($ per bo)(1)

 

$

101.99

 

$

92.31

 

$

9.68

 

10

%

Natural gas ($ per mcf)

 

$

2.35

 

$

4.69

 

$

(2.34

)

-50

%

Oil equivalent ($ per boe)(1)

 

$

89.28

 

$

83.85

 

$

5.43

 

6

%

 

 

 

 

 

 

 

 

 

 

REVENUES:

 

 

 

 

 

 

 

 

 

Oil sales

 

$

25,858

 

$

9,433

 

$

16,425

 

174

%

Natural gas sales

 

604

 

437

 

167

 

38

%

Total revenues

 

$

26,462

 

$

9,870

 

$

16,592

 

168

%

 


(1) Excludes the impact of oil derivative instruments.

 

Net Production. Since the third quarter of 2011, we have drilled and completed fourteen wells, resulting in an increase in production for the nine months ended September 30, 2012 of 152% compared to the same period in 2011.  Approximately 68% of our current year production is from the Palmetto area, where we added six producing wells since the prior year third quarter for a total of eleven wells producing during the nine months ended September 30, 2012 compared to five wells during the same period of 2011. In our Maverick area, we added production from six new wells for a total of nine producing wells during the nine months ended September 30, 2012 compared to three wells in the comparable 2011 period.  Approximately 20% of our production in the nine months ended September 30, 2012 is from the Maverick area.  In our Marquis area, which accounted for approximately 9% of our 2012 year-to-date production, we added two producing wells. These wells represented our first production from the Marquis area.  In the nine months ended September 30, 2012, 86% of our production was oil and 14% was natural gas compared to 87% oil and 13% natural gas in the same period of 2011.

 

Average Sales Price. Our average realized oil price for the nine months ended September 30, 2012 increased 10% to $101.99 per bo as compared to $92.31 per bo for the comparable 2011 period.  The average price realized for our natural gas production for the nine months ended September 30, 2012 was $2.35 per mcf, which is 50% lower than the average sales price in the comparable 2011 period of 2011 of $4.69 per mcf.

 

Revenues.  Oil and natural gas revenues totaled approximately $26.5 million and $9.9 million for the nine months ended September 30, 2012 and 2011, respectively. Oil sales revenue for the nine months ended September 30, 2012 increased 174% with $13.9 million attributable to the increase in production and $2.5 million due to the higher average sales price compared to the same period in 2011.  Natural gas sales revenue for the nine months ended September 30, 2012 increased approximately 38% with the higher revenue from our increased production partially offset by the impact of lower average realized prices compared to the nine months ended September 30, 2011.

 

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Costs and Operating Expenses

 

The table below presents a detail of expenses for the periods indicated (in thousands, except percentages):

 

 

 

Nine Months Ended

 

Increase (Decrease)

 

 

 

September 30,

 

2012 vs 2011

 

 

 

2012

 

2011

 

$

 

%

 

OPERATING COSTS AND EXPENSES:

 

 

 

 

 

 

 

 

 

Oil and natural gas production expenses

 

$

2,015

 

$

1,208

 

$

807

 

67

%

Production and ad valorem taxes

 

1,569

 

551

 

1,018

 

185

%

Depreciation, depletion and amortization

 

9,282

 

2,761

 

6,521

 

236

%

Accretion

 

9

 

4

 

5

 

*

 

General and administrative (inclusive of stock-based compensation expense of $24,800 for the nine months ended September 30, 2012)

 

31,451

 

3,504

 

27,947

 

798

%

Total operating costs and expenses

 

44,326

 

8,028

 

36,298

 

452

%

 

 

 

 

 

 

 

 

 

 

Interest and other income

 

31

 

 

31

 

*

 

Realized and unrealized gains on derivative instruments

 

809

 

1,558

 

(749

)

-48

%

Income tax expense

 

 

 

 

*

 

 


* Not meaningful.

 

Oil and Natural Gas Production Expenses.   Our oil and natural gas production expenses increased by $0.8 million to approximately $2.0 million for the nine months ended September 30, 2012, as compared to $1.2 million for the same period in 2011. The increase in oil and natural gas production expenses in the nine months ended September 30, 2012 compared to the same period of 2011 is directly attributable to the increase in production from our increased drilling activities in the Eagle Ford Shale.

 

Production and Ad Valorem Taxes.  Our production and ad valorem taxes totaled $1.6 million and $0.6 million for the nine months ended September 30, 2012 and 2011, respectively. The increase in production and ad valorem taxes in the nine months ended September 30, 2012 compared to the same period in 2011 was due to the significant increase in production volumes.

 

Depreciation, Depletion and Amortization.  Our DD&A expenses increased from $2.8 million ($23.46 per boe) for the nine months ended September 30, 2011 to $9.3 million ($31.31 per boe) in the comparable 2012 period.  This increase in the depletion rate primarily resulted from a substantial increase in the basis of our oil and natural gas properties.  Higher production for the nine months ended September 30, 2012 as compared to the same period in 2011 resulted in a $4.2 million increase in expense and the change in the depletion rate resulted in a $2.3 million increase in expense.

 

General and Administrative Expenses.  Our G&A expenses, including stock-based compensation, totaled $31.5 million for the nine months ended September 30, 2012 compared to $3.5 million for the same period in 2011.  G&A expenses, excluding stock-based compensation expense, totaled $6.7 million, an increase of 90% over the prior year comparable period.  This increase was due to higher costs associated with the new public entity, consisting primarily of audit fees, legal expenses, investor relation costs, consulting and insurance.  For the nine months ended September 30, 2012, we recorded a non-cash stock-based compensation expense of approximately $24.8 million.  The expense was due primarily to the rescission and cancellation of 1.1 million shares of restricted stock during the second quarter of 2012.  For the restricted stock awards granted to non-employees that were rescinded and cancelled, stock-based compensation expense was based on the fair value at the date of cancellation, and the associated unrecognized compensation expense was accelerated and recognized as stock-based compensation expense.  At the date of cancellation, the fair value of the stock awards cancelled was approximately $22.3 million, or $20.28 per restricted share.

 

Commodity Derivative Transactions.  During the nine months ended September 30, 2012, we recognized a $1.6 million unrealized gain on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $0.8 million realized loss associated with settlements and/or expirations on our commodity derivative contracts.  During the nine months ended September 30, 2011, we recognized a $1.6 million unrealized gain related to the change in fair value of our derivative contracts.

 

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Table of Contents

 

Because our outstanding contracts at September 30, 2011 related to 2012 production, no settlements were recognized in the prior year period.

 

Income Tax Expense.   For a discussion of our income tax expense, see “- Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011 — Costs and Operating Expenses — Income Tax Expense.”

 

Critical Accounting Policies and Estimates

 

The preparation of financial statements in accordance with U.S. GAAP requires our management to select and apply accounting policies that best provide the framework to report our results of operations and financial position.  The selection and application of those policies requires our management to make difficult subjective or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements.  As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.

 

As of September 30, 2012, our critical accounting policies were consistent with those discussed in our 2011 Annual Report.

 

Use of Estimates

 

The condensed consolidated financial statements are prepared in conformity with U.S. GAAP, which requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.

 

Liquidity and Capital Resources

 

As of September 30, 2012, we had approximately $133.4 million in cash, $11.6 million invested in available-for-sale securities and no indebtedness.  We have largely completed the process of negotiating our new credit facilities and expect to complete that process during the fourth quarter of 2012.  Our current liquidity position gives us flexibility with respect to the timing of entering into these anticipated new credit facilities.  We expect to use our cash and securities, our internally generated cash flow and borrowings under our anticipated new credit facilities to fund our planned capital expenditures through the end of 2013.  At mid-year 2012, we established an eighteen month capital budget covering the period from July 2012 through December 2013 of approximately $495 million to drill 55 net wells plus approximately $35 million for facilities, new leases and seismic data.  We currently believe that this capital budget accurately reflects our future plans and that it can be funded utilizing our cash and securities on hand, expected cash flow from operations and borrowings under our anticipated new credit facilities, including anticipated increases in the borrowing bases of our anticipated new credit facilities, while maintaining a conservative capital structure.

 

Cash Flows

 

Our cash flows for the nine months ended September 30, 2012 and 2011(in thousands) are as follows:

 

 

 

Nine Months Ended

 

 

 

September 30,

 

 

 

2012

 

2011

 

Cash Flow Data:

 

 

 

 

 

Net cash provided by operating activities

 

$

28,584

 

$

2,198

 

Net cash used in investing activities

 

$

(102,770

)

$

(10,917

)

Net cash provided by financing activities

 

$

144,512

 

$

8,719

 

 

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Table of Contents

 

Net Cash Provided by (Used in) Operating Activities.  Net cash provided by operating activities was approximately $28.6 million for the nine months ended September 30, 2012 compared to $2.2 million for the same period in 2011. The increase in net cash provided by operating activities for the nine months ended September 30, 2012 was due primarily to higher revenue resulting from an increase in production as well as higher average oil prices for the current year compared to the same period in 2011.

 

Net Cash Provided by (Used in) Investing Activities.  Net cash flows used in investing activities totaled approximately $102.8 million for the nine months ended September 30, 2012 compared to $10.9 million for the same period in 2011.  The increase was due primarily to capital expenditures for leasehold and drilling activities that increased from $12.5 million in the nine months ended September 30, 2011 to $88.8 million in the nine months ended September 30, 2012.  For the nine months ended September 30, 2012, we also paid $2.4 million for premiums on our derivative contracts and invested $11.6 million in available-for-sale securities.  For the nine months ended September 30, 2011, capital expenditures were partially offset by $1.6 million in proceeds from the sale of certain non-core undeveloped leases.

 

Net Cash Provided by (Used in) Financing Activities.  During the third quarter of 2012, we received net proceeds from the private placement of preferred stock of approximately $144.5 million, after deducting initial purchasers’ discounts and commissions and offering costs payable by us of approximately $5.5 million.  For the nine months ended September 30, 2011, our financing activities included capital contributions of $9.2 million partially offset by offering costs of $0.4 million.

 

Off-Balance Sheet Arrangements

 

At September 30, 2012, we did not have any off-balance sheet arrangements.

 

Commitments and Contractual Obligations

 

At September 30, 2012, we did not have any material contractual obligations.

 

Non-GAAP Financial Measures

 

FASB Accounting Standards require use of the “two-class” method of computing earnings per share for all periods presented.  The “two-class” method is an earnings allocation formula that determines earnings per share for each class of common share and participating security as if all earnings for the period had been distributed.  Unvested restricted stock awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation.  Diluted per share amounts reflect the dilutive effects of the participating securities using the two-class method or the treasury stock method, whichever is more dilutive.  They also reflect the effects of the potential conversion of the Convertible Preferred Stock using the if-converted method, if the effect is dilutive.

 

Adjusted EBITDA

 

We present Adjusted EBITDA attributable to common stockholders (“Adjusted EBITDA”) in addition to our reported net income (loss) in accordance with U.S. GAAP.  Adjusted EBITDA is a non-GAAP financial measure that 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 realized and unrealized losses on interest rate derivative contracts;

·                  Income tax expense (benefit);

·                  Depletion, depreciation and amortization;

·                  Accretion of asset retirement obligations;

·                  Loss (gain) on sale of oil and natural gas properties;

·                  Unrealized losses on derivatives;

·                  Impairment of oil and natural gas properties;

 

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Table of Contents

 

·                  Stock-based compensation expense; and

·                  Other non-recurring items that we deem appropriate.

 

Less:

 

·                  Interest income;

·                  Unrealized gains on derivatives; and

·                  Other non-recurring items that we deem appropriate.

 

Our Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss), cash flows provided by or used in operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. 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.

 

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

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

1,667

 

$

2,074

 

$

(17,024

)

$

3,400

 

Less: Preferred stock dividends

 

(264

)

 

(264

)

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to common shares and participating securities

 

1,403

 

2,074

 

(17,288

)

3,400

 

Plus:

 

 

 

 

 

 

 

 

 

Unrealized (gains) losses on derivative instruments

 

2,104

 

(1,759

)

(1,594

)

(1,558

)

Depreciation, depletion, amortization and accretion

 

4,580

 

802

 

9,291

 

2,765

 

Stock-based compensation

 

836

 

 

24,800

 

 

Less:

 

 

 

 

 

 

 

 

 

Interest income

 

(12

)

 

(31

)

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA

 

8,911

 

1,117

 

15,178

 

4,607

 

Adjusted EBITDA allocable to participating securities

 

(134

)

 

(497

)

 

Adjusted EBITDA attributable to common stockholders

 

$

8,777

 

$

1,117

 

$

14,681

 

$

4,607

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA per common share:

 

 

 

 

 

 

 

 

 

Basic

 

$

0.27

 

$

0.05

 

$

0.44

 

$

0.21

 

Diluted

 

$

0.27

 

$

0.05

 

$

0.44

 

$

0.21

 

 

 

 

 

 

 

 

 

 

 

Weighted average number of unrestricted outstanding common shares used to calculate basic EBITDA per share

 

33,000

 

22,091

 

33,000

 

22,091

 

Dilutive shares

 

996

 

 

 

 

Denominator for diluted EBITDA per common share

 

33,996

 

22,091

 

33,000

 

22,091

 

 

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Table of Contents

 

The following table presents a reconciliation of net cash provided by operating activities to Adjusted EBITDA (in thousands):

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by (used in) operating activities

 

$

13,083

 

$

(1,771

)

$

28,584

 

$

2,198

 

Plus:

 

 

 

 

 

 

 

 

 

Net change in operating assets and liabilities

 

(3,896

)

2,888

 

(13,111

)

2,409

 

Preferred stock dividends

 

(264

)

 

(264

)

 

Less:

 

 

 

 

 

 

 

 

 

Interest income

 

(12

)

 

(31

)

 

Adjusted EBITDA

 

$

8,911

 

$

1,117

 

$

15,178

 

$

4,607

 

 

Adjusted Net Income