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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10‑Q

 

 

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

For the quarterly period ended March 31, 2016

OR

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
(State or other jurisdiction of
incorporation or organization)

45‑3090102
(I.R.S. Employer
Identification No.)

1000 Main Street, Suite 3000
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   No 

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   No 

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 

Accelerated filer 

Non‑accelerated filer 
(Do not check if a
smaller reporting company)

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   No 

Number of shares of registrant’s common stock, par value $0.01 per share, outstanding as of May 6, 2016: 65,220,112.

 

 

 


 

CAUTIONARY NOTE REGARDING FORWARD‑LOOKING STATEMENTS

 

This Quarterly Report on Form 10‑Q contains “forward‑looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Quarterly Report on Form 10‑Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward‑looking statements. These statements are based on certain assumptions we made based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this Quarterly Report on Form 10‑Q, words such as “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model,” “strategy,” “future” or their negatives or the statements that include these words or other words that convey the uncertainty of future events or outcomes, are intended to identify forward‑looking statements, although not all forward‑looking statements contain such identifying words. In particular, statements, express or implied, concerning our future operating results and returns or our ability to replace or increase reserves, increase production, or generate income or cash flows are forward‑looking statements. Forward‑looking statements are not guarantees of performance. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Although we believe that the expectations reflected in our forward‑looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Important factors that could cause our actual results to differ materially from the expectations reflected in the forward‑looking statements include, among others:

 

·

our ability to successfully execute our business and financial strategies;

 

·

our ability to utilize the services, personnel and other assets of Sanchez Oil & Gas Corporation (“SOG”) pursuant to existing services agreements;

 

·

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

 

·

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

 

·

the realized benefits of the acreage acquired in our various acquisitions and other assets and liabilities assumed in connection therewith;

 

·

the realized benefits of our joint ventures, including with respect to our joint ventures with Targa Resources Partners LP (“Targa”);

 

·

the realized benefits of our transactions with Sanchez Production Partners LP (“SPP”), including with respect to the Palmetto escalating working interest sale and divestiture of Western Catarina midstream assets referred to herein;

 

·

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

 

·

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

 

·

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

 

·

our ability to successfully execute our hedging strategy and the resulting realized prices therefrom;

 

·

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

 

2


 

·

our ability to access the credit and capital markets to obtain financing on terms we deem acceptable, if at all, and to otherwise satisfy our capital expenditure requirements;

 

·

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

 

·

our ability to compete with other companies in the oil and natural gas industry;

 

·

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

 

·

developments in oil‑producing and natural gas‑producing countries, the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and other factors affecting the supply of oil and natural gas;

 

·

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

 

·

the extent to which our crude oil and natural gas properties operated by others are operated successfully and economically;

 

·

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

 

·

unexpected results of litigation filed against us;

 

·

the extent to which we incur uninsured losses and liabilities or losses and liabilities in excess of our insurance coverage; and

 

·

the other factors described 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”).

 

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

3


 

Sanchez Energy Corporation

Form 10‑Q

For the Quarterly Period Ended March 31, 2016

 

Table of Contents

 

 

 

 

 

PART I

 

Item 1. 

Unaudited Financial Statements

5

 

Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015

5

 

Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2016 and 2015

6

 

Condensed Consolidated Statement of Stockholders’ Equity (Deficit) for the Three Months Ended March 31, 2016

7

 

Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2016 and 2015

8

 

Notes to the Condensed Consolidated Financial Statements

9

Item 2. 

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

35

Item 3. 

Quantitative and Qualitative Disclosures About Market Risk

50

Item 4. 

Controls and Procedures

51

 

PART II

 

Item 1. 

Legal Proceedings

52

Item 1A. 

Risk Factors

52

Item 2. 

Unregistered Sales of Equity Securities and Use of Proceeds

52

Item 3. 

Defaults Upon Senior Securities

52

Item 4. 

Mine Safety Disclosures

52

Item 5. 

Other Information

52

Item 6. 

Exhibits

53

SIGNATURES 

55

 

 

4


 

PART I—FINANCIAL INFORMATION

 

Item 1.  Unaudited Financial Statements

 

Sanchez Energy Corporation

 

Condensed Consolidated Balance Sheets (Unaudited)

 

(in thousands, except share amounts)

 

 

 

 

 

 

 

 

 

 

 

March 31, 

 

December 31, 

 

 

    

2016

    

2015

 

ASSETS

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

362,221

 

$

435,048

 

Oil and natural gas receivables

 

 

33,596

 

 

30,668

 

Joint interest billings receivables

 

 

547

 

 

1,259

 

Accounts receivable - related entities

 

 

3,636

 

 

3,697

 

Fair value of derivative instruments

 

 

136,479

 

 

172,494

 

Other current assets

 

 

22,043

 

 

23,452

 

Total current assets

 

 

558,522

 

 

666,618

 

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

 

 

 

 

 

 

 

Unproved oil and natural gas properties

 

 

281,106

 

 

253,529

 

Proved oil and natural gas properties

 

 

2,978,732

 

 

2,914,867

 

Total oil and natural gas properties

 

 

3,259,838

 

 

3,168,396

 

Less: Accumulated depreciation, depletion, amortization and impairment

 

 

(2,480,381)

 

 

(2,412,293)

 

Total oil and natural gas properties, net

 

 

779,457

 

 

756,103

 

 

 

 

 

 

 

 

 

Other assets:

 

 

 

 

 

 

 

Debt issuance costs, net

 

 

125

 

 

 —

 

Fair value of derivative instruments

 

 

5,299

 

 

5,789

 

Investments

 

 

55,721

 

 

49,985

 

Other assets

 

 

22,079

 

 

22,809

 

Total assets

 

$

1,421,203

 

$

1,501,304

 

LIABILITIES AND STOCKHOLDERS' EQUITY

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

Accounts payable

 

$

1,600

 

$

4,184

 

Other payables

 

 

1,599

 

 

2,004

 

Accrued liabilities:

 

 

 

 

 

 

 

Capital expenditures

 

 

57,580

 

 

51,983

 

Other

 

 

60,570

 

 

69,974

 

Deferred premium liability

 

 

20,523

 

 

24,548

 

Other current liabilities

 

 

14,921

 

 

14,813

 

Total current liabilities

 

 

156,793

 

 

167,506

 

Long term debt, net of premium, discount and debt issuance costs

 

 

1,706,367

 

 

1,705,927

 

Asset retirement obligations

 

 

26,467

 

 

25,907

 

Other liabilities

 

 

54,699

 

 

58,133

 

Total liabilities

 

 

1,944,326

 

 

1,957,473

 

Commitments and contingencies (Note 16)

 

 

 

 

 

 

 

Stockholders' equity:

 

 

 

 

 

 

 

Preferred stock ($0.01 par value, 15,000,000 shares authorized; 1,838,985 shares issued and outstanding as of March 31, 2016 and December 31, 2015 of 4.875% Convertible Perpetual Preferred Stock, Series A; 3,527,830 shares issued and outstanding as of March 31, 2016 and December 31, 2015 of 6.500% Convertible Perpetual Preferred Stock, Series B)

 

 

53

 

 

53

 

Common stock ($0.01 par value, 150,000,000 shares authorized; 64,296,945 and 61,928,089 shares issued and outstanding as of March 31, 2016 and December 31, 2015, respectively)

 

 

646

 

 

619

 

Additional paid-in capital

 

 

1,082,293

 

 

1,079,513

 

Accumulated deficit

 

 

(1,606,115)

 

 

(1,536,354)

 

Total stockholders' deficit

 

 

(523,123)

 

 

(456,169)

 

Total liabilities and stockholders' deficit

 

$

1,421,203

 

$

1,501,304

 

 

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

5


 

Sanchez Energy Corporation

 

Condensed Consolidated Statements of Operations (Unaudited)

 

(in thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

March 31, 

 

    

2016

    

2015

REVENUES:

 

 

 

 

 

 

Oil sales

 

$

42,682

 

$

75,524

Natural gas liquid sales

 

 

15,045

 

 

13,853

Natural gas sales

 

 

22,089

 

 

21,216

Total revenues

 

 

79,816

 

 

110,593

OPERATING COSTS AND EXPENSES:

 

 

 

 

 

 

Oil and natural gas production expenses

 

 

44,693

 

 

34,163

Production and ad valorem taxes

 

 

3,943

 

 

8,670

Depreciation, depletion, amortization and accretion

 

 

46,965

 

 

102,657

Impairment of oil and natural gas properties

 

 

22,084

 

 

441,450

General and administrative (inclusive of stock-based compensation expense of $3,344 and $7,694, respectively, for the three months ended March 31, 2016 and 2015)

 

 

19,480

 

 

21,477

Total operating costs and expenses

 

 

137,165

 

 

608,417

Operating loss

 

 

(57,349)

 

 

(497,824)

Other income (expense):

 

 

 

 

 

 

Interest income and other expense

 

 

(88)

 

 

(1,824)

Interest expense

 

 

(31,606)

 

 

(31,558)

Earnings from equity investments

 

 

512

 

 

 —

Net gains on commodity derivatives

 

 

22,757

 

 

41,303

Total other income (expense)

 

 

(8,425)

 

 

7,921

Income (loss) before income taxes

 

 

(65,774)

 

 

(489,903)

Income tax expense

 

 

 —

 

 

7,442

Net loss

 

 

(65,774)

 

 

(497,345)

Less:

 

 

 

 

 

 

Preferred stock dividends

 

 

(3,987)

 

 

(3,991)

Net income allocable to participating securities

 

 

 —

 

 

 —

Net loss attributable to common stockholders

 

$

(69,761)

 

$

(501,336)

 

 

 

 

 

 

 

Net loss per common share - basic and diluted

 

$

(1.20)

 

$

(8.83)

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

 

 

58,099

 

 

56,805

 

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

 

6


 

 

Sanchez Energy Corporation

 

Condensed Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2016 (Unaudited)

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Series A

 

Series B

 

 

 

 

 

 

Additional

 

 

 

 

Total

 

 

 

Preferred Stock

 

Preferred Stock

 

Common Stock

 

Paid-in

 

Accumulated

 

Stockholders'

 

 

    

Shares

    

Amount

    

Shares

    

Amount

    

Shares

    

Amount

    

Capital

    

Deficit

    

Deficit

 

BALANCE, December 31, 2015

 

1,839

 

$

18

 

3,528

 

$

35

 

61,928

 

$

619

 

$

1,079,513

 

$

(1,536,354)

 

$

(456,169)

 

Preferred stock dividends

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

 —

 

 

(3,987)

 

 

(3,987)

 

Restricted stock awards, net of forfeitures

 

 —

 

 

 —

 

 —

 

 

 —

 

2,369

 

 

27

 

 

(27)

 

 

 —

 

 

 —

 

Stock-based compensation

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

2,807

 

 

 —

 

 

2,807

 

Net loss

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

 —

 

 

(65,774)

 

 

(65,774)

 

BALANCE, March 31, 2016

 

1,839

 

$

18

 

3,528

 

$

35

 

64,297

 

$

646

 

$

1,082,293

 

$

(1,606,115)

 

$

(523,123)

 

 

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

7


 

 

Sanchez Energy Corporation

 

Condensed Consolidated Statements of Cash Flows (Unaudited)

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

March 31, 

 

 

    

2016

    

2015

  

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

Net income (loss)

 

$

(65,774)

 

$

(497,345)

 

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

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

 

46,965

 

 

102,657

 

Impairment of oil and natural gas properties

 

 

22,084

 

 

441,450

 

Stock-based compensation expense

 

 

3,344

 

 

7,694

 

Net gains on commodity derivative contracts

 

 

(22,757)

 

 

(41,303)

 

Net cash settlement received on commodity derivative contracts

 

 

50,221

 

 

29,355

 

Losses incurred on premiums for derivative contracts

 

 

6,103

 

 

121

 

Amortization of deferred gain on Western Catarina Midstream Divestiture

 

 

(3,703)

 

 

 —

 

Amortization of debt issuance costs

 

 

1,915

 

 

1,815

 

Accretion of debt discount, net

 

 

158

 

 

227

 

Deferred taxes

 

 

 —

 

 

7,442

 

Loss on inventory market adjustment

 

 

478

 

 

 —

 

Earnings from equity investments

 

 

(512)

 

 

 —

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Accounts receivable

 

 

(2,216)

 

 

29,922

 

Other current assets

 

 

322

 

 

873

 

Accounts payable

 

 

(2,584)

 

 

(4,168)

 

Accounts receivable - related entities

 

 

61

 

 

(2,847)

 

Other payables

 

 

(405)

 

 

566

 

Accrued liabilities

 

 

(9,404)

 

 

(8,660)

 

Other current liabilities

 

 

(159)

 

 

(5,166)

 

Other liabilities

 

 

 —

 

 

1,167

 

Net cash provided by operating activities

 

 

24,137

 

 

63,800

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

Payments for oil and natural gas properties

 

 

(85,767)

 

 

(270,584)

 

Payments for other property and equipment

 

 

(228)

 

 

828

 

Proceeds from sale of oil and natural gas properties

 

 

 —

 

 

81,958

 

Acquisition of oil and natural gas properties

 

 

 —

 

 

13

 

Payments for investments

 

 

(5,224)

 

 

 —

 

Net cash used in investing activities

 

 

(91,219)

 

 

(187,785)

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Financing costs

 

 

(1,758)

 

 

(400)

 

Preferred dividends paid

 

 

(3,987)

 

 

(3,991)

 

Net cash used in financing activities

 

 

(5,745)

 

 

(4,391)

 

 

 

 

 

 

 

 

 

Decrease in cash and cash equivalents

 

 

(72,827)

 

 

(128,376)

 

Cash and cash equivalents, beginning of period

 

 

435,048

 

 

473,714

 

Cash and cash equivalents, end of period

 

$

362,221

 

$

345,338

 

 

 

 

 

 

 

 

 

NON-CASH INVESTING AND FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Change in asset retirement obligations

 

$

78

 

$

979

 

Change in accrued capital expenditures

 

 

5,597

 

 

(58,068)

 

Purchase of oil and natural gas properties in exchange for common stock

 

 

 —

 

 

7,520

 

SUPPLEMENTAL DISCLOSURE:

 

 

 

 

 

 

 

Cash paid for taxes

 

$

160

 

 

 —

 

Cash paid for interest

 

$

35,517

 

$

38,978

 

 

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

8


 

Sanchez Energy Corporation

 

Notes to the Condensed Consolidated Financial Statements

 

(Unaudited)

 

Note 1. Organization

 

Sanchez Energy Corporation (together with our consolidated subsidiaries, the “Company,” “we,” “our,” “us” or similar terms), a Delaware corporation formed in August 2011, is an independent exploration and production company, focused on the acquisition and development of unconventional oil and natural gas resources in the onshore U.S. Gulf Coast, with a current focus on the Eagle Ford Shale in South Texas and the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana. We have accumulated net leasehold acreage in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale and in what we believe to be the core of the TMS. We are currently focused on the horizontal development of significant resource potential from the Eagle Ford Shale.

 

 

Note 2. Basis of Presentation and 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, 2015 from the audited financial statements filed in its Annual Report on Form 10-K for the fiscal year ended December 31, 2015 (the “2015 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 2015 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 March 31, 2016, the Company’s significant accounting policies are consistent with those discussed in Note 2, “Basis of Presentation and Summary of Significant Accounting Policies,” in the notes to the Company’s consolidated financial statements contained in its 2015 Annual Report.

 

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 calculation of 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.

 

Recent Accounting Pronouncements

 

In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09 “Improvements to Employee Share-Based Payment Accounting,” effective for annual and interim

9


 

periods for public companies beginning after December 15, 2016, with a cumulative-effect and prospective approach to be used for implementation. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions including accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, minimum statutory tax withholding requirements and classification of employee taxes paid on the statement of cash flows when an employer withholds shares for tax-withholding purposes. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements.

 

In February 2016, the FASB issued ASU No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. ASU 2016-02 updates the previous lease guidance by requiring the recognition of a right-to-use asset and lease liability on the statement of financial position for those leases previously classified as operating leases under the old guidance. In addition, ASU 2016-02 updates the criteria for a lessee’s classification of a finance lease. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements.

 

In April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under the International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. During the first quarter 2016, the Company adopted ASU 2015-03 retrospectively to the comparable periods in this Form 10-Q. Adoption of this guidance affected the balance sheets as of December 31, 2015 as follows (in thousands):

 

Decrease in Long term debt, net of premium, discount and debt issuance costs of approximately $41,039

Decrease in Debt issuance costs, net (Other Assets) of approximately $41,039

 

In February 2015, the FASB issued ASU 2015-02, “Consolidation—Amendments to the Consolidation Analysis.” This ASU will simplify existing requirements by reducing the number of acceptable consolidation models and placing more emphasis on risk of loss when determining a controlling financial interest. The provisions of this new standard will affect how limited partnerships and similar entities are assessed for consolidation, including the elimination of the presumption that a general partner should consolidate a limited partnership. This guidance is effective for fiscal years and interim periods beginning in 2016. During the first quarter 2016, the Company adopted ASU 2015-02 retrospectively to the comparable periods in this Form 10-Q. See further disclosure around the adoption of ASU 2015-02, and the impact on the Company’s consolidated financial statements in Note 19, “Variable Interest Entities.”

 

In July 2015, FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory,” effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.

 

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is not permitted. The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. 

 

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Note 3. Acquisitions and Divestitures

 

Our acquisitions are accounted for under the acquisition method of accounting in accordance with Accounting Standards Codification (“ASC”) Topic 805, “Business Combinations.” A business combination may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the condensed consolidated financial statements since the closing dates of the acquisitions.

 

Catarina Acquisition

 

On June 30, 2014, we completed our acquisition of contiguous acreage in Dimmit, LaSalle and Webb Counties, Texas with 176 gross producing wells (the “Catarina Acquisition”) for an aggregate adjusted purchase price of $557.1 million. The effective date of the transaction was January 1, 2014. The purchase price was funded with a portion of the proceeds from the Original 6.125% Notes (as defined below in Note 6, “Long-Term Debt”) and cash on hand. The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands):

 

 

 

 

 

 

Proved oil and natural gas properties

    

$

446,906

  

Unproved properties

 

 

122,224

 

Other assets acquired

 

 

2,682

 

Fair value of assets acquired

 

 

571,812

 

Asset retirement obligations

 

 

(14,723)

 

Fair value of net assets acquired

 

$

557,089

 

 

Palmetto Disposition

 

On March 31, 2015, we sold escalating working interests in 59 wellbores located in Gonzales County, Texas to a subsidiary of SPP for an adjusted purchase price of approximately $83.4 million (the “Palmetto Disposition”). The effective date of the transaction was January 1, 2015. The aggregate average working interest percentage initially conveyed was 18.25% per wellbore and, upon January 1 of each subsequent year after the closing, the purchaser’s working interest will automatically increase in incremental amounts according to the purchase agreement until January 1, 2019, at which point the purchaser will own a 47.5% working interest and we will own a 2.5% working interest in each of the wellbores. We received consideration consisting of approximately $83.0 million (approximately $81.4 million as adjusted) cash and 1,052,632 common units of SPP valued at approximately $2.0 million as of the date of the closing (as discussed further in Note 8, “Investments”). The Company did not record any gains or losses related to the Palmetto Disposition. On August 4, 2015, the common units of SPP were subject to a 1-for-10 reverse split, at which time we owned 105,263 common units of SPP.

 

Western Catarina Midstream Divestiture

 

On October 14, 2015, the Company and SN Catarina, LLC (“SN Catarina”) completed the sale of SN Catarina’s interests in Catarina Midstream, LLC, a wholly-owned subsidiary of SN Catarina (“Catarina Midstream”), which as of the closing date, owned certain midstream gathering and processing assets located in Dimmit County and Webb County, Texas and 105,263 common units of SPP, to SPP for an adjusted purchase price of $345.8 million in cash (the “Western Catarina Midstream Divestiture”). In connection with the closing of the Western Catarina Midstream Divestiture, SN Catarina and Catarina Midstream entered into a Firm Gathering and Processing Agreement effective October 14, 2015 (the “Gathering Agreement”) for an initial term of 15 years pursuant to which production from approximately 35,000 acres that we operate in Dimmit County and Webb County, Texas will be dedicated for gathering by Catarina Midstream, LLC (“Catarina Midstream”). In addition, for the first five years of the Gathering Agreement, SN Catarina will be required to meet a minimum quarterly volume delivery commitment of 10,200 barrels per day of crude oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments.  SN Catarina will be required to pay gathering and processing fees of $0.96 per barrel for crude oil and condensate and $0.74 per Mcf for natural gas that are tendered through the gathering system, in each case, subject to an annual escalation for a positive

11


 

increase in the consumer price index. In addition, SN Catarina has, under certain circumstances, a right of first refusal during the term of the Gathering Agreement and afterwards with respect to dispositions by Catarina Midstream of its ownership interest in the gathering system. The Company recorded a deferred gain of approximately $74.1 million as a result of Gathering Agreement being accounted for as an operating lease. This deferred gain will be amortized straight-line over the firm commitment term of five years as an offset to the transportation fees paid to SPP under the Gathering Agreement.

 

Note 4. Cash and Cash Equivalents

 

As of March 31, 2016 and December 31, 2015, cash and cash equivalents consisted of the following (in thousands):

 

 

 

 

 

 

 

 

 

 

 

March 31, 

 

December 31, 

 

 

    

2016

    

2015

  

Cash at banks

 

$

336,250

 

$

35,600

 

Money market funds

 

 

25,971

 

 

399,448

 

Total cash and cash equivalents

 

$

362,221

 

$

435,048

 

 

 

Note 5. 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 depletion expense using the units‑of‑production method. Depletion 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 costs and the estimated quantity of proved reserves.

 

Full Cost Ceiling Test—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. Prices are 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. During the three month period ended March 31, 2016, the Company recorded a full cost ceiling test impairment after income taxes of $22.1 million. Based on a current expectation that prices will remain unfavorable during the first half of 2016 based upon the current NYMEX forward prices, absent a material addition to proved reserves and/or a material reduction in future development costs, we believe that there is a reasonable likelihood that the Company will incur additional impairments to our full cost pool in 2016. The Company recorded impairment expense of $441.5 million for the three month period ended March 31, 2015.

 

Costs associated with unproved properties and properties under development, including costs associated with seismic data, leasehold acreage and the current drilling of wells, are excluded from the full cost amortization base until the properties have been evaluated. Unproved properties are identified on a project basis, with a project being an area in which significant leasehold interests are acquired within a contiguous area. Unproved properties are reviewed periodically by management and when management determines that a project area has been evaluated through drilling operations or a thorough geologic evaluation, the project area is transferred into the full cost pool subject to 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.

 

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Note 6. Long‑Term Debt

 

Long-term debt on March 31, 2016, consisted of $1.15 billion face value of 6.125% senior notes (consisting of $850 million in Original 6.125% Notes (defined below) and $300 million in Additional 6.125% Notes (defined below), which were issued at a premium to face value of $2.3 million) maturing on January 15, 2023, and $600 million principal amount of 7.75% senior notes (consisting of $400 million in Original 7.75% Notes (defined below) and $200 million in Additional 7.75% Notes (defined below), which were issued at a discount to face value of $7.0 million), maturing on June 15, 2021. During the first quarter 2016, the Company adopted ASU 2015-03 retrospectively to the comparable periods in this Form 10-Q. Adoption of this guidance affected the balance sheets as of December 31, 2015 as follows (in thousands):

 

Decrease in Long term debt, net of premium, discount and debt issuance costs of approximately $41,039

Decrease in Debt issuance costs, net (Other Assets) of approximately $41,039

 

As of March 31, 2016, and December 31, 2015, the Company’s long‑term debt consisted of the following:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amount Outstanding

 

 

 

 

 

 

 

(in thousands) as of

 

 

 

 

 

 

 

March 31, 

 

December 31, 

 

 

    

Interest Rate

    

Maturity date

    

2016

    

2015

 

Second Amended and Restated Credit Agreement

 

Variable

 

June 30, 2019

 

$

 —

 

$

 —

 

7.75% Notes

 

7.75%

 

June 15, 2021

 

 

600,000

 

 

600,000

 

6.125% Notes

 

6.125%

 

January 15, 2023

 

 

1,150,000

 

 

1,150,000

 

 

 

 

 

 

 

 

1,750,000

 

 

1,750,000

 

Unamortized discount on Additional 7.75% Notes

 

 

 

 

 

 

(4,708)

 

 

(4,933)

 

Unamortized premium on Additional 6.125% Notes

 

 

 

 

 

 

1,832

 

 

1,899

 

Unamortized debt issuance costs

 

 

 

 

 

 

(40,757)

 

 

(41,039)

 

Total long-term debt

 

 

 

 

 

$

1,706,367

 

$

1,705,927

 

 

The components of interest expense are (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

    

March 31, 

 

  

 

 

2016

    

2015

    

 

Interest on Senior Notes

 

$

(29,235)

 

$

(29,235)

 

 

Interest expense and commitment fees on credit agreement

 

 

(297)

 

 

(281)

 

 

Amortization of debt issuance costs

 

 

(1,915)

 

 

(1,815)

 

 

Amortization of discount on Additional 7.75% Notes

 

 

(226)

 

 

(226)

 

 

Amortization of premium on Additional 6.125% Notes

 

 

67

 

 

(1)

 

 

Total interest expense

 

$

(31,606)

 

$

(31,558)

 

 

 

Credit Facility

 

Previous Credit Agreement:  On May 31, 2013, we and our subsidiaries, SEP Holdings III, LLC (“SEP III”), SN Marquis LLC (“SN Marquis”) and SN Cotulla Assets, LLC (“SN Cotulla”), collectively, as the borrowers, entered into a revolving credit facility represented by a  $500 million Amended and Restated Credit Agreement with Royal Bank of Canada as the administrative agent, Capital One, National Association as the syndication agent and RBC Capital Markets as sole lead arranger and sole book runner and each of the other lenders party thereto (the “Amended and Restated Credit Agreement”). The Amended and Restated Credit Agreement was to mature on May 31, 2018.

 

On May 12, 2014, the Company borrowed $100 million under the Amended and Restated Credit Agreement. The Company used proceeds from the issuance of the Original 6.125% Notes to repay the $100 million outstanding.

 

Second Amended and Restated Credit Agreement:  On June 30, 2014, the Company, as borrower, and SEP III, SN Marquis, SN Cotulla, SN Operating, LLC, SN TMS, LLC and SN Catarina, LLC as loan parties, entered into a revolving credit facility represented by a $1.5 billion Second Amended and Restated Credit Agreement with Royal Bank

13


 

of Canada as the administrative agent, Capital One, National Association as the syndication agent, Compass Bank and SunTrust Bank as co-documentation agents, RBC Capital Markets as sole lead arranger and sole book runner and the lenders party thereto (together with all subsequent amendments, the ‘‘Second Amended and Restated Credit Agreement’’). The Company has elected an available commitment amount under the Second Amended and Restated Credit Agreement of $300 million. Additionally, the Second Amended and Restated Credit Agreement provides for the issuance of letters of credit, limited in the aggregate to the lesser of $80 million and the total availability thereunder. As of March 31, 2016, there were no borrowings and no letters of credit outstanding under the Second Amended and Restated Credit Agreement, which had a borrowing base of $350 million. Availability under the Second Amended and Restated Credit Agreement is at all times subject to customary conditions and the then applicable borrowing base and aggregate elected commitment amount. All of the $300 million aggregate elected commitment amount was available for future revolver borrowings as of March 31, 2016.

 

The Second Amended and Restated Credit Agreement matures on June 30, 2019. The borrowing base under the Second Amended and Restated Credit Agreement is redetermined semi-annually by the lenders based on, among other things, an evaluation of the Company’s and its restricted subsidiaries’ oil and natural gas reserves. Semi-annual redeterminations of the borrowing base are generally scheduled to occur on or before April 1 and October 1 of each year. The borrowing base is also subject to (i) automatic reduction by 25% of the amount of any increase in the aggregate amount of the Company’s high yield debt and second lien debt, other than high yield or second lien debt issued in exchange for or to refinance existing high yield debt, permitted second lien debt incurred to refinance or replace permitted second lien debt, and permitted second lien debt representing the payment of interest in kind, (ii) interim redetermination at the election of the Company once between each scheduled redetermination, (iii) interim redetermination at the election of a majority of the lenders once between each scheduled redetermination, and (iv) if the required lenders so direct, in connection with asset sales and swap terminations during the period since the most recent borrowing base determination with a combined borrowing base value of more than 10% of the value of the proved developed oil and gas properties included in the most recent reserve report, a reduction in an amount equal to the borrowing base value, as determined by the administrative agent in its reasonable judgment, of such assets and swaps.

 

The Company’s obligations under the Second Amended and Restated Credit Agreement are secured by a first priority lien on substantially all of the Company’s assets and the assets of its existing and future subsidiaries other than subsidiaries designated as “unrestricted subsidiaries”, including a first priority lien on all ownership interests in existing and future subsidiaries, other than subsidiaries (other than the SPV, as defined below) designated as “unrestricted subsidiaries”.

 

The obligations under the Second Amended and Restated Credit Agreement are guaranteed by all of the Company’s existing and future subsidiaries not designated as ‘‘unrestricted subsidiaries.’’ At the Company’s election, borrowings under the Second Amended and Restated Credit Agreement may be made on an alternate base rate or an adjusted eurodollar rate basis, plus an applicable margin. The applicable margin varies from 1.00% to 2.00% for alternate base rate borrowings and from 2.00% to 3.00% for eurodollar borrowings and letters of credit, if any, depending on the utilization of the borrowing base. The Company is also required to pay a commitment fee of 0.50% per annum on any unused aggregate elected commitment amount.

 

The Second Amended and Restated Credit Agreement contains various affirmative and negative covenants and events of default that limit the Company’s ability to, among other things, incur indebtedness, make restricted payments, grant liens, consolidate or merge, dispose of certain assets, make certain investments, engage in transactions with affiliates, hedge transactions and make certain acquisitions. The Second Amended and Restated Credit Agreement also provides for cross default between the Second Amended and Restated Credit Agreement and the other debt (including debt under the 6.125% Notes and the 7.75% Notes) and obligations in respect of hedging agreements (on a mark-to-market basis), of the Company and its restricted subsidiaries, in an aggregate principal amount in excess of $10 million. Furthermore, the Second Amended and Restated Credit Agreement contains financial covenants that require the Company to satisfy the following tests: (i) current assets plus undrawn borrowing capacity on the Second Amended and Restated Credit Agreement to current liabilities of at least 1.0 to 1.0 at all times, and (ii) net first lien debt (defined as the excess of first lien debt over cash) to consolidated last twelve months EBITDA of not greater than 2.00 to 1.0 as of the last day of any fiscal quarter. As of March 31, 2016, the Company was in compliance with the covenants of the Second Amended and Restated Credit Agreement.

 

The Second Amended and Restated Credit Amendment, among other things, also (a) permits the repurchase by the Company and its restricted subsidiaries, or by a special purpose unrestricted subsidiary of the Company (the “SPV”),

14


 

of the Company’s senior unsecured notes and common and preferred equity securities, from cash in excess of lender credit exposure in an aggregate amount up to approximately $298.5 million subject to certain caps on purchases of the Company’s common and preferred equity securities and other limitations; (b) permits (i) the formation and capitalization of the SPV with up to $150 million, (ii) the SPV to purchase, hold and dispose of, including by way of distribution to its immediate parent, up to $150 million of the Company’s senior unsecured notes and common and preferred equity securities, (iii) the SPV to hold cash received from its immediate parent in a deposit account maintained with a lender under the Second Amended and Restated Credit Agreement, and (iv) the SPV to distribute cash to its immediate parent; (c) requires (i) the Company to cause the SPV to distribute all cash held by it or in its name as of the close of business on December 31, 2016 to its immediate parent, (ii) the equity interests in the SPV to be pledged in favor of the secured parties, (iii) the closing of deposit, securities and commodity accounts maintained by the Company with persons other than lenders or affiliates of lenders under the Second Amended and Restated Credit Agreement, and (iv) the Company to enter into account control agreements in favor of the administrative agent for the benefit of the secured parties in respect of each of the Company’s deposit, securities and commodity accounts; (d) provides that, in the event of a borrowing base deficiency, the Company shall use unrestricted cash of the Company and its subsidiaries in excess of $35 million to prepay borrowings and cash collateralize letter of credit exposure, as applicable; and (f) restricts the Company from increasing its aggregate elected commitment amount until the lenders’ next regularly scheduled borrowing base redetermination, which is expected to occur in the fourth quarter 2016.

 

From time to time, the agents, arrangers, book runners and lenders under the Second Amended and Restated Credit Agreement and their affiliates have provided, and may provide in the future, investment banking, commercial lending, hedging and financial advisory services to the Company and its affiliates in the ordinary course of business, for which they have received, or may in the future receive, customary fees and commissions for these transactions.

 

7.75% Senior Notes Due 2021

 

On June 13, 2013, we completed a private offering of $400 million in aggregate principal amount of the Company’s 7.75% senior notes that will mature on June 15, 2021 (the “Original 7.75% Notes”). Interest on the notes is payable on each June 15 and December 15. We received net proceeds from this offering of approximately $388 million, after deducting initial purchasers’ discounts and offering expenses, which we used to repay outstanding indebtedness under our credit facilities. The Original 7.75% Notes are senior unsecured obligations and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of our existing and future subsidiaries.

 

On September 18, 2013, we issued an additional $200 million in aggregate principal amount of our 7.75% senior notes due 2021 (the “Additional 7.75% Notes” and, together with the Original 7.75% Notes, the “7.75% Notes”) in a private offering at an issue price of 96.5% of the principal amount of the Additional 7.75% Notes. We received net proceeds of $188.8 million (after deducting the initial purchasers’ discounts and offering expenses of $4.2 million) from the sale of the Additional 7.75% Notes. The Company also received cash for accrued interest from June 13, 2013 through the date of issuance of $4.1 million, for total net proceeds of $192.9 million from the sale of the Additional 7.75% Notes. The Additional 7.75% Notes were issued under the same indenture as the Original 7.75% Notes, and are, therefore, treated as a single class of securities under the indenture. We used the net proceeds from the offering to partially fund our acquisition of contiguous acreage in McMullen County, Texas with 13 gross producing wells (the “Wycross Acquisition”) completed in October 2013, a portion of the 2013 and 2014 capital budgets and for general corporate purposes.

 

The 7.75% Notes are senior unsecured obligations and rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The 7.75% Notes rank senior in right of payment to our future subordinated indebtedness. The 7.75% Notes are effectively junior in right of payment to all of our existing and future secured debt (including under our Second Amended and Restated Credit Agreement) to the extent of the value of the assets securing such debt. The 7.75% Notes are fully and unconditionally guaranteed (except for customary release provisions) on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the 7.75% Notes. To the extent set forth in the indenture governing the 7.75% Notes, certain of our subsidiaries will be required to fully and unconditionally guarantee the 7.75% Notes on a joint and several senior unsecured basis in the future.

 

The indenture governing the 7.75% Notes, among other things, restricts our ability and our restricted subsidiaries’ ability to: (i) incur, assume, or guarantee additional indebtedness or issue certain types of equity securities; (ii) pay distributions on, purchase or redeem shares or purchase or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create or incur liens on their assets; (vi) sell assets;

15


 

(vii) consolidate, merge or transfer all or substantially all of their assets; (viii) restrict distributions or other payments from the Company’s restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries.

 

We have the option to redeem all or a portion of the 7.75% Notes at any time on or after June 15, 2017 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. We may also redeem the 7.75% Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium, together with accrued and unpaid interest and additional interest, if any, to the redemption date, at any time prior to June 15, 2017. In addition, we may redeem up to 35% of the 7.75% Notes prior to June 15, 2016 under certain circumstances with an amount not greater than the net cash proceeds of one or more equity offerings at the redemption price specified in the indenture. We may also be required to repurchase the 7.75% Notes upon a change of control or if we sell certain of our assets.

 

On July 18, 2014, we completed an exchange offer of $600 million aggregate principal amount of the 7.75% Notes that had been registered under the Securities Act of 1933, as amended (the “Securities Act”), for an equal amount of the 7.75% Notes that had not been registered under the Securities Act.

 

6.125% Senior Notes Due 2023

 

On June 27, 2014, the Company completed a private offering of $850 million in aggregate principal amount senior unsecured 6.125% notes due 2023 (the “Original 6.125% Notes”). Interest on the notes is payable on each July 15 and January 15. The Company received net proceeds from this offering of approximately $829 million, after deducting initial purchasers’ discounts and estimated offering expenses, which the Company used to repay all of the $100 million in borrowings outstanding under its Amended and Restated Credit Agreement and to finance a portion of the purchase price of the Catarina Acquisition. We used the remaining proceeds from the offering to fund a portion of the remaining 2014 capital budget and for general corporate purposes. The Original 6.125% Notes are the senior unsecured obligations of the Company and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of the Company’s existing and future subsidiaries.

 

On September 12, 2014, we issued an additional $300 million in aggregate principal amount of our 6.125% senior notes due 2023 (the “Additional 6.125% Notes” and, together with the Original 6.125% Notes, the “6.125% Notes” and, together with the 7.75% Notes, the “Senior Notes”) in a private offering at an issue price of 100.75% of the principal amount of the Additional 6.125% Notes. We received net proceeds of $295.9 million, after deducting the initial purchasers’ discounts, adding premiums to face value of $2.3 million and deducting estimated offering expenses of $6.4 million.  The Company also received cash for accrued interest from June 27, 2014 through the date of the issuance of $3.8 million, for total net proceeds of $299.7 million from the sale of the Additional 6.125% Notes. The Additional 6.125% Notes were issued under the same indenture as the Original 6.125% Notes, and are, therefore, treated as a single class of securities under the indenture. We used a portion of the net proceeds from the offering to fund a portion of the 2014 capital budget and intend to use the remainder of the net proceeds to fund a portion of the 2015 capital budget, and for general corporate purposes.

 

The 6.125% Notes are senior unsecured obligations and rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The 6.125% Notes rank senior in right of payment to the Company’s future subordinated indebtedness. The 6.125% Notes are effectively junior in right of payment to all of the Company’s existing and future secured debt (including under the Second Amended and Restated Credit Agreement) to the extent of the value of the assets securing such debt. The 6.125% Notes are fully and unconditionally guaranteed (except for customary release provisions) on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the 6.125% Notes. To the extent set forth in the indenture governing the 6.125% Notes, certain of our subsidiaries will be required to fully and unconditionally guarantee the 6.125% Notes on a joint and several senior unsecured basis in the future.

 

The indenture governing the 6.125% Notes, among other things, restricts our ability and our restricted subsidiaries’ ability to: (i) incur, assume or guarantee additional indebtedness or issue certain types of equity securities; (ii) pay distributions on, purchase or redeem shares or purchase or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create or incur liens on their assets; (vi) sell assets; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) restrict distributions or other payments from the Company’s restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries.

 

16


 

The Company has the option to redeem all or a portion of the 6.125% Notes, at any time on or after July 15, 2018 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. The Company may also redeem the 6.125% Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium, together with accrued and unpaid interest and additional interest, if any, to the redemption date, at any time prior to July 15, 2018. In addition, the Company may redeem up to 35% of the 6.125% Notes prior to July 15, 2017 under certain circumstances with an amount not greater than the net cash proceeds of one or more equity offerings at the redemption price specified in the indenture. The Company may also be required to repurchase the 6.125% Notes upon a change of control or if we sell certain Company assets.

 

On February 27, 2015, we completed an exchange offer of $1.15 billion aggregate principal amount of the 6.125% Notes that had been registered under the Securities Act for an equal amount of the 6.125% Notes that had not been registered under the Securities Act.

 

Note 7. Derivative Instruments

 

To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, and to protect the economics of property acquisitions at the time of execution, 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. In addition, the Company periodically enters into option transactions as a way to manage its exposure to fluctuating prices and/or enhance the value of fixed price swaps. 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. 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 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 since the Company has elected not to designate its current derivative contracts as hedges.

 

As of March 31, 2016, the Company had the following NYMEX WTI crude oil swaps and puts, respectively, covering anticipated future production:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Calendar Year

    

Volumes (Bbls)

    

Average Price per Bbl

    

Price Range per Bbl

 

2016

 

1,925,000

 

$

70.11

 

$

62.00

 - 

$

80.15

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Calendar Year

 

Volumes (Bbls)

 

Put  Price per Bbl

 

Put Price Range per Bbl

 

2016

    

3,025,000

    

$

60.00

    

$

60.00

 - 

$

60.00

 

 

As of March 31, 2016, the Company had the following NYMEX Henry Hub natural gas swaps covering anticipated future production:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Calendar Year

    

Volumes 
(MMBtu)

    

Average Price
 per MMBtu

    

Price Range
 per MMBtu

  

2016

 

26,735,000

 

$

3.13

 

$

2.54

-

$

3.92

 

2017

 

27,945,000

 

$

3.00

 

$

2.89

-

$

3.65

 

 

 

17


 

The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the three months ended March 31, 2016, and the year ended December 31, 2015 (in thousands):

 

 

 

 

 

 

 

Three Months Ended

 

 

March 31, 

 

    

2016

Beginning fair value of commodity derivatives

 

$

178,283

Net gains on crude oil derivatives

 

 

5,126

Net gains on natural gas derivatives

 

 

11,528

Net settlements on derivative contracts:

 

 

 

Crude oil

 

 

(49,827)

Natural gas

 

 

(9,435)

Net premiums on derivative contracts:

 

 

 

Crude oil

 

 

6,103

Ending fair value of commodity derivatives

 

$

141,778

 

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 gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s condensed consolidated balance sheets (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2016

 

 

 

 

 

 

Gross Amounts

 

Net Amounts

 

 

 

Gross Amount

 

Offset in the

 

Presented in the

 

 

 

of Recognized

 

Consolidated

 

Consolidated

 

 

    

Assets

    

Balance Sheets

    

Balance Sheets

  

Offsetting Derivative Assets:

 

 

 

 

 

 

 

 

 

 

Current asset

 

$

136,507

 

$

(28)

 

$

136,479

 

Long-term asset

 

 

5,325

 

 

(26)

 

 

5,299

 

Total asset

 

$

141,832

 

$

(54)

 

$

141,778

 

Offsetting Derivative Liabilities:

 

 

 

 

 

 

 

 

 

 

Current liability

 

$

(28)

 

$

28

 

$

 —

 

Long-term liability

 

 

(26)

 

 

26

 

 

 —

 

Total liability

 

$

(54)

 

$

54

 

$

 —

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

 

 

 

 

 

 

Gross Amounts

 

Net Amounts

 

 

 

Gross Amount

 

Offset in the

 

Presented in the

 

 

 

of Recognized

 

Consolidated

 

Consolidated

 

 

    

Assets

    

Balance Sheets

    

Balance Sheets

  

Offsetting Derivative Assets:

 

 

 

 

 

 

 

 

 

 

Current asset

 

$

172,518

 

$

(24)

 

$

172,494

 

Long-term asset

 

 

5,821

 

 

(32)

 

 

5,789

 

Total asset

 

$

178,339

 

$

(56)

 

$

178,283

 

Offsetting Derivative Liabilities:

 

 

 

 

 

 

 

 

 

 

Current liability

 

$

(24)

 

$

24

 

$

 —

 

Long-term liability

 

 

(32)

 

 

32

 

 

 —

 

Total liability

 

$

(56)

 

$

56

 

$

 —

 

 

 

 

18


 

Note 8. Investments

 

On October 2, 2015, the Company, through SN Midstream LLC, a wholly-owned subsidiary of the Company (“SN Midstream”), entered into joint venture agreements with an affiliate of Targa to, among other things, construct a new cryogenic natural gas processing plant (the “Processing Plant”) and associated high pressure gathering pipelines near the Company’s Catarina asset in the Eagle Ford Shale. The Processing Plant, which will be located in La Salle County, Texas, is expected to have initial capacity of 200 MMcf per day with the ability to increase to 260 MMcf per day. In connection with the Processing Plant joint venture agreement, SN Midstream has committed to invest approximately $80 million and received a 50% ownership interest in the joint venture owning the Processing Plant. Construction is expected to be completed in 2017. In connection with the gathering pipelines joint venture agreement, SN Midstream has committed to invest approximately $35 million and received a 50% ownership interest in the joint venture owning the gathering pipelines that will connect the Company's existing Catarina gathering system to the Processing Plant. Construction on the gathering pipelines is scheduled to be completed in two phases, with both phases expected to be completed in 2016. The first phase, which connected the Company’s existing Catarina gathering system to the SOII Facility (defined below), was completed in February 2016. The second phase will connect the Company’s existing gathering system to the Processing Plant, and is expected to be completed later this year. As of March 31, 2016, the Company had invested $22.7 million in the gathering pipelines joint venture. The Company is accounting for these joint ventures as equity method investments as Targa is the operator of the joint ventures and has the most influence with respect to the normal day-to-day construction and operating decisions. As of March 31, 2016, the Company had invested approximately $20.0 million in the Processing Plant joint venture. We have included these equity method investment balances in the “Other Assets - Investments” long-term asset line on the balance sheet. The Company recorded earnings of approximately $523 thousand from equity investments from the gathering pipelines joint venture and recorded losses of approximately $12 thousand from equity investments from the Processing Plant joint venture for the quarter ended March 31, 2016. We have included these equity method earnings and losses in the “Earnings from equity investments” line on the statement of operations.

 

On October 2, 2015, the Company, via SN Catarina, purchased from a subsidiary of Targa a 10% undivided interest in the Silver Oak II Gas Processing Facility (the “SOII Facility”) in Bee County, Texas for a purchase price of $12.5 million. Targa owns the remaining undivided 90% interest in the SOII Facility, which is operated by Targa. Concurrently with the execution of the purchase and sale agreement for the SOII Facility, the Company entered into a firm gas processing agreement, whereby Targa began processing a firm quantity, 125,000 Mcf per day, on March 1, 2016 until the in-service date of the Processing Plant discussed above. The Company is accounting for the investment in the SOII Facility as an equity method investment as Targa is the operator and majority interest owner of the SOII Facility. As of March 31, 2016, the Company had invested $12.5 million in the SOII Facility. The Company did not record earnings from the equity interest in the SOII Facility for the quarter ended March 31, 2016.

 

 

Note 9. 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 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

19


 

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 March 31, 2016 and December 31, 2015 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of March 31, 2016

 

 

 

Active Market

 

 

 

 

 

 

 

 

 

 

 

 

for Identical

 

Observable

 

Unobservable

 

Total

 

 

 

Assets

 

Inputs

 

Inputs

 

Carrying

 

 

    

(Level 1)

    

(Level 2)

    

(Level 3)

    

Value

 

Cash and cash equivalents:

 

 

 

 

 

 

 

 

 

 

 

 

 

Money market funds

 

$

25,971

 

$

 —

 

$

 —

 

$

25,971

 

Oil derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

Swaps

 

 

 —

 

 

54,520

 

 

 —

 

 

54,520

 

Puts

 

 

 —

 

 

56,353

 

 

 —

 

 

56,353

 

Gas derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

Swaps

 

 

 —

 

 

30,905

 

 

 —

 

 

30,905

 

Total

 

$

25,971

 

$

141,778

 

$

 —

 

$

167,749

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2015

 

 

 

Active Market

 

 

 

 

 

 

 

 

 

 

 

 

for Identical

 

Observable

 

Unobservable

 

Total

 

 

 

Assets

 

Inputs

 

Inputs

 

Carrying

 

 

    

(Level 1)

    

(Level 2)

    

(Level 3)

    

Value

 

Cash and cash equivalents:

 

 

 

 

 

 

 

 

 

 

 

 

 

Money market funds

 

$

399,448

 

$

 —

 

$

 —

 

$

399,448

 

Oil derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

Swaps

 

 

 —

 

 

72,887

 

 

 —

 

 

72,887

 

Puts

 

 

 —

 

 

76,583

 

 

 —

 

 

76,583

 

Gas derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

Swaps

 

 

 —

 

 

28,813

 

 

 —

 

 

28,813

 

Total

 

$

399,448

 

$

178,283

 

$

 —

 

$

577,731

 

 

Financial Instruments:  The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s condensed consolidated balance sheets at March 31, 2016, and December 31, 2015. The Company’s money market funds represent cash equivalents backed by the assets of high-quality banks and financial institutions. The Company identified the money market funds as Level 1 instruments due to the fact that the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active markets for the underlying investments.

 

The Company’s derivative instruments, which consist of swaps and puts, are classified as Level 2 as of March 31, 2016 and December 31, 2015, in the table above. The fair values of the Company’s derivatives are based on third-party pricing models which utilize inputs that are either readily available in the public market, such as forward curves, or can be corroborated from active markets of broker quotes. Since swaps do not include optionality and, therefore,

20


 

generally have no unobservable inputs, they are classified as Level 2. As of December 31, 2015, the Company believes that substantially all of the inputs required to calculate the fair value of swaps and puts are observable in the marketplace throughout the term of these derivative instruments or supported by observable levels at which transactions are executed in the marketplace, and are, therefore, classified as Level 2. Derivative instruments are also 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 derivative instruments.

 

There were no derivative instruments classified as Level 3 as of March 31, 2016 and December 31, 2015. 

 

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. Fair value measurements of assets acquired and liabilities assumed in business combinations are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties is based on market and cost approaches. Our purchase price allocations for the Catarina Acquisition is presented in Note 3, “Acquisitions and Divestitures.” Liabilities assumed include asset retirement obligations existing at the date of acquisition. 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 10, “Asset Retirement Obligations.”

 

In connection with the exchange agreements entered into in February, May and August 2014 by the Company with certain holders of the Company’s Series A Convertible Perpetual Preferred Stock (“Series A Preferred Stock”) and Series B Convertible Perpetual Preferred Stock (“Series B Preferred Stock”), the Company issued common stock according to the conversion rate pursuant to each agreement and additional shares to induce the holders of the preferred stock to convert prior to the date the Company could mandate conversion. In addition, on November 20, 2015, a holder of our Series B Preferred Stock exercised its right to convert 4,500 shares our Series B Preferred Stock, at the prescribed initial conversion rate of 2.337 shares of common stock per share of Series B Preferred Stock, in exchange for 10,517 shares of our common stock. The fair value of the common stock issued is based on the price of the Company’s common stock on the date of issuance. As there is an active market for the Company’s common stock, the Company has designated this fair value measurement as Level 1. A detailed description of the Company’s common stock and preferred stock issuances and redemptions is presented in Note 13, “Stockholders’ Equity.”

 

Fair Value of Other Financial Instruments

 

Financial instruments not carried at fair value consist of oil and natural gas receivables, accounts payable and accrued liabilities and long-term debt. The carrying amounts of our oil and natural gas receivables, accounts payable and accrued liabilities approximate fair value due to the highly liquid nature of these short-term instruments. The registered 7.75% Notes are traded in an active market, and as such, are classified as Level 1 financial instruments. The estimated fair value of the 7.75% Notes was $348.0 million as of March 31, 2016, and were calculated using quoted market prices based on trades of such debt as of that date. The registered 6.125% Notes are traded in an active market, and as such, are classified as Level 1 financial instruments. The estimated fair value of the 6.125% Notes was $609.5 million as of March 31, 2016, and were calculated using quoted market prices based on trades of such debt as of that date.

 

Note 10. 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 and remediation costs, well life, inflation and credit‑adjusted risk‑free rate. The inputs are calculated based on third-party historical data as well as current estimates. When the liability is initially recorded, the carrying amount of the related long‑lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is

21


 

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.

 

Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs. Revisions in estimated liabilities can also include, but are not limited to, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlement. The changes in the asset retirement obligation for the three months ended March 31, 2016 and the year ended December 31, 2015 were as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31, 2016

 

Year Ended December 31, 2015

 

Abandonment liability, beginning of period

 

$

25,907

 

$

25,694

 

Liabilities incurred during period

 

 

210

 

 

6,021

 

Acquisitions

 

 

 —

 

 

 —

 

Divestitures

 

 

(131)

 

 

(379)

 

Revisions

 

 

 —

 

 

(7,623)

 

Accretion expense

 

 

481

 

 

2,194

 

Abandonment liability, end of period

 

$

26,467

 

$

25,907

 

 

 

 

Note 11. 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, Sanchez Energy Partners I, LP (“SEP I”), and their affiliates (but excluding the Company) collectively as the “Sanchez Group.” 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.

 

Salaries and associated benefits of SOG employees and are allocated to the Company based on a fixed percentage that is reviewed quarterly and adjusted, if needed, based on a detailed analysis of actual time spent by the professional staff on Company projects and activities. General and administrative expenses such as office rent, utilities, supplies and other overhead costs, are allocated on the same percentages as the SOG employee salaries. Expenses allocated to the Company for general and administrative expenses for the three months ended March 31, 2016 and 2015, are as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

March 31, 

 

 

    

2016

    

2015

    

Administrative fees

 

$

12,084

 

$

6,252

 

Third-party expenses