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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549


FORM 10-Q

(Mark One)


x

QUARTERLY REPORT UNDER 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


For the transition period from ___________ to ______________.


Commission File Number 001-35241


SARATOGA RESOURCES, INC.

(Exact name of registrant as specified in its charter)


Texas

 

76-0314489

(State or other jurisdiction of incorporation or organization)

 

(IRS Employer Identification No.)


7500 San Felipe, Suite 675, Houston, Texas 77063

 (Address of principal executive offices)(Zip Code)


(713) 458-1560

(Registrant's telephone number, including area code)


 

 (Former name, former address and former fiscal year, if changed since last report)


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 ¨


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 ¨


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 definition of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer  ¨

Accelerated filer  ¨

Non-accelerated filer  ¨

Smaller reporting company  x


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


Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.  Yes x   No ¨


As of October 29, 2012, we had 30,905,101 shares of $0.001 par value Common Stock outstanding.


 




SARATOGA RESOURCES, INC.


FORM 10-Q


INDEX


 

 

Page No.

PART I   FINANCIAL INFORMATION

 

 

 

 

ITEM 1.   Financial Statements (Unaudited)

 

 

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

3

 

Consolidated Statements of Operations for the three and nine months ended September 30, 2012 and 2011

4

 

Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011

5

 

Notes to Consolidated Financial Statements

6

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

13

ITEM 3.   Quantitative and Qualitative Disclosures About Market Risk

21

ITEM 4.   Controls and Procedures

22

 

 

 

PART II

OTHER INFORMATION

23

 

 

 

ITEM 6.   Exhibits

23





2




PART I - FINANCIAL INFORMATION


ITEM 1

Financial Statements


SARATOGA RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

 

 

September 30,

 

December 31,

 

2012

 

2011

ASSETS

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

$

8,288,106 

 

$

15,874,680 

Accounts receivable

 

6,304,451 

 

 

10,539,757 

Prepaid expenses and other

 

1,980,173 

 

 

1,189,406 

Deferred tax asset, net

 

 

 

1,400,000 

Other current asset

 

150,000 

 

 

150,000 

Total current assets

 

16,722,730 

 

 

29,153,843 

 

 

 

 

 

 

Property and equipment:

 

 

 

 

 

Oil and gas properties - proved (successful efforts method)

 

249,984,720 

 

 

196,101,827 

Other

 

713,251 

 

 

658,113 

 

 

250,697,971 

 

 

196,759,940 

Less: Accumulated depreciation, depletion and amortization

 

(68,045,627)

 

 

(53,830,820)

Total property and equipment, net

 

182,652,344 

 

 

142,929,120 

 

 

 

 

 

 

Deferred tax asset, net

 

6,948,628 

 

 

5,147,962 

Other assets, net

 

18,923,094 

 

 

20,531,218 

Total assets

$

225,246,796 

 

$

197,762,143 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS' EQUITY

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

$

8,867,682 

 

$

4,598,534 

Revenue and severance tax payable

 

4,167,429 

 

 

5,709,773 

Accrued liabilities

 

7,908,539 

 

 

8,451,655 

Derivative liabilities – short term

 

189,060 

 

 

Short-term notes payable

 

933,403 

 

 

344,256 

Asset retirement obligation – current

 

1,158,532 

 

 

1,548,945 

Total current liabilities

 

23,224,645 

 

 

20,653,163 

 

 

 

 

 

 

Long-term liabilities:

 

 

 

 

 

Asset retirement obligation

 

11,323,077 

 

 

9,852,920 

Long-term debt, net of unamortized discount of $1,849,867 and $2,115,195, respectively

 

125,650,133 

 

 

125,384,805 

Total long-term liabilities

 

136,973,210 

 

 

135,237,725 

 

 

 

 

 

 

Commitment and contingencies (see notes)

 

 

 

 

 

 

 

 

 

 

 

Stockholders' equity:

 

 

 

 

 

Common stock, $0.001 par value; 100,000,000 shares authorized 30,867,513 and  26,714,815 shares issued and outstanding at September 30, 2012 and December 31, 2011, respectively

 

30,867 

 

 

26,714 

Additional paid-in capital

 

76,864,136 

 

 

52,674,252 

Accumulated other comprehensive income(loss)

 

(182,569)

 

 

Retained deficit

 

(11,663,493)

 

 

(10,829,711)

 

 

 

 

 

 

Total stockholders' equity

 

65,048,941 

 

 

41,871,255 

 

 

 

 

 

 

Total liabilities and stockholders' equity

$

225,246,796 

 

$

197,762,143 


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



3





SARATOGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

September 30,

 

For the Nine Months Ended

September 30,

 

2012

 

2011

 

2012

 

2011

Revenues:

 

 

 

 

 

 

 

 

 

 

 

Oil and gas revenues

$

16,454,125 

 

$

18,885,950 

 

$

59,588,443 

 

$

53,459,141 

Oil and gas hedging

 

(6,490)

 

 

 

 

(6,490)

 

 

Other revenues

 

269,810 

 

 

938,385 

 

 

1,467,403 

 

 

4,368,436 

Total revenues

 

16,717,445 

 

 

19,824,335 

 

 

61,049,356 

 

 

57,827,577 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expense:

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

4,622,010 

 

 

4,590,675 

 

 

13,860,709 

 

 

12,683,787 

Workover expense

 

306,745 

 

 

32,549 

 

 

3,846,046 

 

 

458,286 

Exploration expense

 

213,733 

 

 

166,688 

 

 

369,419 

 

 

573,077 

Loss on plugging and abandonment

 

 

 

 

 

2,468,969 

 

 

Dry hole costs

 

 

 

3,787,911 

 

 

93,353 

 

 

3,787,911 

Depreciation, depletion and amortization

 

3,658,002 

 

 

4,009,462 

 

 

14,170,532 

 

 

12,377,089 

Impairment expense

 

44,276 

 

 

 

 

44,276 

 

 

Accretion expense

 

555,504 

 

 

399,634 

 

 

1,666,512 

 

 

1,248,478 

General and administrative

 

1,971,634 

 

 

2,616,072 

 

 

7,042,299 

 

 

6,516,360 

Severance taxes

 

1,502,134 

 

 

1,431,567 

 

 

5,375,259 

 

 

4,096,641 

Total operating expenses

 

12,874,038 

 

 

17,034,558 

 

 

48,937,374 

 

 

41,741,629 

 

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

3,843,407 

 

 

2,789,777 

 

 

12,111,982 

 

 

16,085,948 

 

 

 

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

Interest income

 

11,204 

 

 

37,492 

 

 

20,046 

 

 

237,078 

Interest expense

 

(4,334,389)

 

 

(4,384,499)

 

 

(13,058,178)

 

 

(13,620,011)

Gain on extinguishment of debt

 

 

 

7,708,486 

 

 

 

 

7,708,486 

Total other expense

 

(4,323,185)

 

 

3,361,479 

 

 

(13,038,132)

 

 

(5,674,447)

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) before reorganization expense and income taxes

 

(479,778)

 

 

6,151,256 

 

 

(926,150)

 

 

10,411,501 

Reorganization expense

 

43,287 

 

 

125,420 

 

 

121,528 

 

 

374,414 

Net income (loss) before income taxes

 

(523,065)

 

 

6,025,836 

 

 

(1,047,678)

 

 

10,037,087 

Income tax expense (benefit)

 

(48,062)

 

 

(146,082)

 

 

(213,896)

 

 

(91,368)

Net income (loss)

$

(475,003)

 

$

6,171,918 

 

$

(833,782)

 

$

10,128,455 

 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income(loss)

 

 

 

 

 

 

 

 

 

 

 

Unrealized loss on derivative instruments

 

(182,569)

 

 

 

 

(182,569)

 

 

Total comprehensive income(loss)

$

(657,572)

 

$

6,171,918 

 

$

(1,016,351)

 

$

10,128,455 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) per share:

 

 

 

 

 

 

 

 

 

 

 

Basic

$

(0.02) 

 

$

0.25 

 

$

(0.03) 

 

$

0.49 

Diluted

$

(0.02) 

 

$

0.24 

 

$

(0.03) 

 

$

0.48 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average number of common shares outstanding:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

30,808,775 

 

 

24,852,001 

 

 

28,867,424 

 

 

20,467,500 

Diluted

 

30,808,775 

 

 

25,796,280 

 

 

28,867,424 

 

 

21,152,120 


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




4





SARATOGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

For the Nine Months Ended

 

September 30,

 

2012

 

2011

Cash flows from operating activities:

 

 

 

 

 

Net income (loss)

$

(833,782)

 

$

10,128,455 

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

 

 

 

 

 

Depreciation, depletion and amortization

 

14,170,532 

 

 

12,377,089 

Impairment expense

 

44,276 

 

 

Accretion expense

 

1,666,512 

 

 

1,248,478 

Amortization of debt issuance costs

 

675,649 

 

 

313,983 

Amortization of debt discount

 

265,328 

 

 

1,618,929 

Dry hole costs

 

93,353 

 

 

3,787,911 

Stock-based compensation

 

1,040,127 

 

 

793,295 

Loss on plugging and abandonment

 

2,468,969 

 

 

Deferred tax benefit

 

(400,666)

 

 

Unrealized loss on hedges

 

6,490 

 

 

Gain on extinguishment of debt

 

 

 

(7,708,486)

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

4,235,306 

 

 

(404,976)

Prepaids and other

 

(790,767)

 

 

(676,418)

Accounts payable

 

(1,806,687)

 

 

(768,985)

Revenue and severance tax payable

 

(1,542,344)

 

 

(818,723)

Payments to settle asset retirement obligations

 

(586,769)

 

 

(750,840)

Accrued liabilities

 

(4,720,786)

 

 

3,748,868 

Net cash provided by operating activities

 

13,984,741 

 

 

22,888,580 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

Additions to oil and gas property

 

(46,191,709)

 

 

(21,920,216)

Additions to other property and equipment

 

(55,138)

 

 

(83,703)

Proceeds from cash collateral

 

2,021,628 

 

 

Other assets

 

(1,089,153)

 

 

(556,769)

Net cash used by investing activities

 

(45,314,372)

 

 

(22,560,688)

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

Proceeds from issuance of common stock

 

23,153,910 

 

 

14,804,718 

Proceeds from short-term notes payable

 

1,685,226 

 

 

1,649,066 

Repayment of short-term notes payable

 

(1,096,079)

 

 

(1,062,625)

Debt issuance costs of long-term debt

 

 

 

(6,517,796)

Repayment of debt borrowing

 

 

 

(268,224)

Net cash provided by financing activities

 

23,743,057 

 

 

8,605,139 

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

(7,586,574)

 

 

8,933,031 

Cash and cash equivalents - beginning of period

 

15,874,680 

 

 

4,409,984 

Cash and cash equivalents - end of period

$

8,288,106 

 

$

13,343,015 

 

 

 

 

 

 

Supplemental disclosures of cash flow information:

 

 

 

 

 

Cash paid for income taxes

$

186,770 

 

$

97,500 

Cash paid for interest

 

7,987,234 

 

 

8,144,276 

 

 

 

 

 

 

Non-cash investing and financing activities:

 

 

 

 

 

Accounts payable for oil and gas additions

$

6,075,835 

 

$

4,981,325 

Accrued liabilities for oil and gas additions

 

1,708,702 

 

 

556,264 

Accrued interest converted to long-term debt – related party

$

 

$

131,205 

Non-cash refinance of long-term debt:

 

 

 

 

 

Repayment of debt borrowing

$

 

$

145,231,776 

Proceeds from refinance of long-term debt

 

 

 

125,231,776 

Proceeds from issuance of common stock

$

 

$

20,000,000 


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



5





SARATOGA RESOURCES, INC.

Notes to Consolidated Financial Statements

September 30, 2012

(Unaudited)


NOTE 1 – ORGANIZATION AND BASIS OF PRESENTATION


Organization


Saratoga Resources, Inc. (“Saratoga” or, the “Company”) is an independent oil and natural gas company engaged in the acquisition, development, exploitation, exploration and production of natural gas and crude oil properties.


Financial Statements Presented


The accompanying unaudited financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q.  They do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America for a complete financial presentation. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, considered necessary for a fair presentation, have been included in the accompanying unaudited financial statements. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.


The Company utilizes the successful efforts method of accounting for oil and gas producing activities.


These financial statements should be read in conjunction with the financial statements and footnotes which are included as part of the Company’s Form 10-K for the year ended December 31, 2011.


Reclassifications of Prior Period Statements


Certain reclassifications of prior period consolidated financial statement balances have been made to conform to current reporting practices.


Concentration of Credit Risk


Financial instruments that potentially subject the Company to a concentration of credit risk include cash, cash equivalents and any marketable securities. The Company had cash deposits of approximately $8.0 million in excess of FDIC insured limits at the period end. The Company has not experienced any losses on its deposits of cash and cash equivalents.


Other Revenue


Other revenues consist principally of (i) a net profits interest attributable to operating the Breton Sound 31 field, for which we receive a percentage of profits, (ii) production handling fees from our Vermilion 16 field, (iii) during the 2012 period, settlements of lawsuits against the former owners of The Harvest Group LLC and Harvest Oil & Gas, LLC and (iv) during the 2011 period, refunds of severance taxes under a Louisiana incentive program for previously inactive wells.


NOTE 2 – CORRECTION OF A PRIOR PERIOD


During the prior year, the Company discovered and corrected an error related to workover expense.  The error resulted in an overstatement of workover expense for the quarter ended June 30, 2011.  In accordance with the SEC’s staff Accounting Bulletin Nos. 99 and 108 (SAB 99 and SAB 108), the Company evaluated this error and, based on an analysis of quantitative and qualitative factors determined that the error was immaterial to the prior reporting period affected.  Therefore, as permitted by SAB 108, the Company corrected, in the current filing, previously reported results for the nine months ended September 30, 2011.




6




The following table shows the impact of the error to the Consolidated Statement of Operations for the nine months ended September 30, 2011 and the Consolidated Statement of Cash Flows for the nine months ended September 30, 2011:


 

For the Nine Months Ended September 30, 2011

 

As Reported

 

Adjustment

 

As Revised

Consolidated Statement of Operations:

 

 

 

 

 

 

 

 

Workover expense

$

1,222,985 

 

$

(764,699)

 

$

458,286 

Total operating expenses

 

42,506,328 

 

 

(764,699)

 

 

41,741,629 

Operating income

 

15,321,249 

 

 

764,699 

 

 

16,085,948 

Net income (loss) before reorganization expense and income taxes

 

9,646,802 

 

 

764,699 

 

 

10,411,501 

Net income (loss) before income taxes

 

9,272,388 

 

 

764,699 

 

 

10,037,087 

Net income (loss)

$

9,363,756 

 

$

764,699 

 

$

10,128,455 

 

 

 

 

 

 

 

 

 

Net income (loss) per share:

 

 

 

 

 

 

 

 

Basic

$

0.46 

 

$

0.05 

 

$

0.49 

Diluted

$

0.44 

 

$

0.04 

 

$

0.48 

 

 

 

 

 

 

 

 

 

Consolidated Statement of Cash Flows:

 

 

 

 

 

 

 

 

Net income (loss)

$

9,363,756 

 

 

764,699 

 

 

10,128,455 

Net cash provided by operating activities

 

22,123,881 

(1)

 

764,699 

 

 

22,888,580 

Additions to oil and gas property

 

(21,155,517)

(1)

 

(764,699)

 

 

(21,920,216)

Net cash (used in) investing activities

$

(21,795,989)

(1)

 

(764,699)

 

 

(22,560,688)


(1)

These amounts changed from those originally reported due to reclassifications of prior period balances in order to conform to current reporting practices.


NOTE 3 – DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES


The Company utilizes hedge accounting for our cash flow hedges, which consist of fixed price swaps.  For the three months ended September 30, 2012 the Company recognized a derivative liability of $189,060 with the change in fair value reflected in other comprehensive income (loss).


As of September 30, 2012, the Company had the following hedge contracts outstanding:


 

 

Beginning

 

Ending

 

Fixed

 

Total

Instrument

 

Date

 

Date

 

Price

 

Bbls

Swap

 

October 2012

 

December 2012

 

$

110.05 

 

27,600 

Swap

 

October 2012

 

December 2012

 

 

108.05 

 

32,200 

Swap

 

October 2012

 

December 2012

 

$

108.00 

 

32,200 

 

 

 

 

 

 

 

 

 

92,000 


NOTE 4 – FAIR VALUE MEASUREMENTS


The Company has various financial instruments that are measured at fair value in the financial statements, including commodity derivatives.  The Company’s financial assets and liabilities are measured using input from three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.  The three levels are as follows:


Level 1 – Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.


Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the assets or liability and inputs that are derived principally from, or corroborated by, observable market data by correlation or other means (market corroborated inputs).


Level 3 – Unobservable inputs that reflect the Company’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists.  The Company develops these inputs based on the best information available, using internal and external data.




7




The following table presents the Company’s assets and liabilities recognized in the balance sheet and measured at fair value on a recurring basis as of September 30, 2012:


 

 

Beginning

 

Ending

 

Fixed

 

 

Description

 

Level 1

 

Level 2

 

Level 3

 

Total

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

 

$

189,060 

 

 

$

189,060 

 

 

$

 

$

189,060 

 

 

$

189,060 


The Company uses various commodity derivative instruments, including fixed price swaps.  The fair value of commodity derivatives is determined using forward price curves derived from market price quotations, externally developed and commercial models, with internal and external fundamental data inputs.  Market price quotations are obtained from independent energy brokers, direct communication with market participants and actual transactions executed by the Company.


NOTE 5 – OTHER ASSETS


Other assets consist of the following:


 

September 30,

 

December 31,

 

2012

 

2011

Site specific trust accounts – P&A escrow

$

5,338,897 

 

$

4,629,816 

Debt issuance cost, net

 

4,710,625 

 

 

5,386,274 

Restricted cash

 

8,873,572 

 

 

10,485,128 

Bond

 

 

 

30,000 

 

$

18,923,094 

 

$

20,531,218 


Site Specific Trust Accounts – P&A Escrow


The Company maintains escrow agreements that have been established for the purpose of assuring maintenance and administration of performance bonds which secure certain plugging and abandonment obligations assumed in the acquisition of oil and gas properties in certain fields.  Changes in the escrow accounts reflect additional contributions and interest earned during 2012. See Note 9 – “Asset Retirement Obligations”.


Debt Issuance Costs, Net


The Company capitalizes certain debt issuance costs and amortizes those costs as additional interest expense over the lives of the associated debt.  Net debt issuance costs at September 30, 2012 reflect the issuance of the 2016 Notes in July 2011.  See Note 10 – “Debt”.


Restricted Cash


Restricted Cash consists of cash collateral held in escrow to assure maintenance and administration of performance bonds and letters of credit which secure certain plugging and abandonment obligations imposed by state law.  See Note 9 – “Asset Retirement Obligations”.  During 2012, the Company replaced certain letters of credit with performance bonds and, as a result, $2,021,628 was released from the cash collateral.  The cash collateral is reflected as a long term asset to correspond with the expected timing of the related asset retirement obligation liability.


NOTE 6 – STOCK-BASED COMPENSATION EXPENSE


The Company periodically grants restricted stock and stock options to employees, directors and consultants.  The Company is required to make estimates of the fair value of the related instruments and recognize expense over the period benefited, usually the vesting period.


Compensation Plans


In September 2011, the Company’s board of directors adopted, and in June 2012 the Company’s stockholders approved, the Saratoga Resources, Inc. 2011 Omnibus Equity Plan (the “2011 Plan”).  The 2011 Plan reserves a total of 3,000,000 shares for issuance to eligible employees, officers, directors and other service providers pursuant to grants of options, restricted stock, performance stock and other equity based compensation agreements.




8




In conjunction with the adoption of the 2011 Plan, the Company’s board of directors approved the termination of the Saratoga Resources, Inc. 2008 Long-term Incentive Plan (the “2008 Plan”) and the Saratoga Resources, Inc. 2006 Employee and Consultant Stock Plan (the “2006 Plan”).  As of September 30, 2012, no awards were outstanding under the 2008 Plan or the 2006 Plan.


Stock Option Activity


In March 2012, the Company’s board of directors approved a stock option grant to purchase an aggregate of 5,000 shares of common stock to a non-executive employee.  The options are exercisable for a term of seven years at $6.40 per share and vest ½ on the date of grant and ½ on the first anniversary of the grant date.  The grant date value of the options was $31,850.  The options were valued using the Black-Scholes model with the following assumptions: 296% volatility; 3.75 year estimated life; zero dividends; 0.64% discount rate; and, quoted stock price and exercise price of $6.40.


In June 2012, the Company’s board of directors approved stock option grants to purchase an aggregate of 105,000 shares of common stock to non-employee directors.  The options are exercisable for a term of seven years at $6.65 per share and vest ½ on the date of grant and ½ on the first anniversary of the grant date.  The grant date value of the options was $695,100.  The options were valued using the Black-Scholes model with the following assumptions: 292% volatility; 3.75 year estimated life; zero dividends; 0.50% discount rate; and, quoted stock price and exercise price of $6.65.


The following table summarizes information about stock option activity and related information for the nine months ended September 30, 2012:


 

 

Options

 

Weighted-

Average Exercise

Price

 

Aggregate

Intrinsic Value

Outstanding at December 31, 2011

 

982,500 

 

$

3.09 

 

$

4,133,025 

Granted

 

110,000 

 

 

6.64 

 

 

Exercised

 

(195,912)

 

 

2.34 

 

 

Forfeited

 

(34,000)

 

 

5.63 

 

 

Outstanding at September 30, 2012

 

862,588 

 

$

3.62 

 

$

1,737,518 

Exercisable at September 30, 2012

 

574,254 

 

$

3.05 

 

$

1,462,799 


The weighted average remaining contractual term of the outstanding options and exercisable options at September 30, 2012 is 6.9 and 5.6 years, respectively.


Share-Based Compensation Expense


The following table reflects share-based compensation recorded by the Company for the three and nine months ended September 30, 2012 and 2011:


 

Three Months Ended

September 30,

 

Nine Months Ended

September 30,

 

2012

 

2011

 

2012

 

2011

Share-based compensation expense included in reported net income

$

204,833 

 

$

327,497 

 

$

1,040,127 

 

$

793,295 

Basic earnings per share effect of share-based compensation expense

$

(0.01)

 

$

(0.01)

 

$

(0.04)

 

$

(0.04)


As of September 30, 2012, total unrecognized stock-based compensation expense related to non-vested stock options was $0.7 million. The unrecognized expense is expected to be recognized over a weighted average period of 0.7 years.


NOTE 7 – EQUITY


Common Stock Activity


During nine months ended September 30, 2012, the Company issued an aggregate of 171,011shares of common stock upon the exercise of outstanding stock options by non-executive employees and a non-employee director.  Of the shares issued, 125,912 shares were issued for gross proceeds of $292,491, or $2.32 a share, and 45,099 shares were issued pursuant to “cashless” exercise provisions wherein the intrinsic value of the stock options were delivered to the Company in lieu of cash payment of the exercise price of 70,000 stock options, with a weighted average exercise price $2.38 per share.


During the nine months ended September 30, 2012, the Company issued an aggregate of 892,327 shares of common stock upon the exercise of outstanding warrants for which the Company received $4,461,635 of proceeds, or $5.00 per share.  In conjunction with the exercise of 213,996 of those warrants, the Company granted three year warrants to purchase an aggregate of 106,997 shares of common stock at $8.00 per share.



9





On May 24, 2012, the Company sold, in a private placement, an aggregate of 3,089,360 shares of common stock to certain institutional and accredited investors at a price of $6.25 per share, for net proceeds of approximately $18.4 million.


Warrant Activity


The following table summarizes information about stock warrant activity and related information for the nine months ended September 30, 2012:


 

 

Warrants

 

Weighted-

Average Exercise

Price

 

Aggregate

Intrinsic Value

Outstanding at December 31, 2011

 

1,357,958 

 

$

4.82 

 

$

3,365,703 

Granted

 

106,997 

 

 

8.00 

 

 

Exercised

 

(892,327)

 

 

5.00 

 

 

Forfeited

 

 

 

 

 

Outstanding at September 30, 2012

 

572,628 

 

$

5.14 

 

$

465,903 

Exercisable at September 30, 2012

 

572,628 

 

$

5.14 

 

$

465,903 


The weighted average remaining contract life of the warrants is 1.1 years.


NOTE 8 – EARNINGS (LOSS) PER SHARE


A reconciliation of the components of basic and diluted net income per common share is presented in the tables below:  


 

For the Three Months Ended September 30,

 

2012

 

2011

 

Income

(Loss)

 

Weighted

Average

Common

Shares

Outstanding

 

Per Share

 

Income

(Loss)

 

Weighted

Average

Common

Shares

Outstanding

 

Per Share

Basic:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income attributable to common stock

$

(475,003)

 

30,808,775 

 

$

(0.02)

 

$

6,171,918 

 

24,852,001 

 

$

0.25 

Effect of Dilutive Securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock options and other

 

 

 

 

 

 

 

 

 

 

944,279 

 

 

 

Diluted:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) attributable to common

stock, including assumed conversions

$

(475,003)

 

30,808,775 

 

$

(0.02)

 

$

6,171,918 

 

25,796,280 

 

$

0.24 



 

For the Nine Months Ended September 30,

 

2012

 

2011

 

Income

(Loss)

 

Weighted

Average

Common

Shares

Outstanding

 

Per Share

 

Income

(Loss)

 

Weighted

Average

Common

Shares

Outstanding

 

Per Share

Basic:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income attributable to common stock

$

(833,782)

 

28,867,424 

 

$

(0.03)

 

$

9,363,756 

 

20,467,500 

 

$

0.46 

Effect of Dilutive Securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock options and other

 

 

 

 

 

 

 

 

 

 

684,620 

 

 

 

Diluted:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) attributable to common

stock, including assumed conversions

$

(833,782)

 

28,867,424 

 

$

(0.03)

 

$

9,363,756 

 

21,152,120 

 

$

0.44 




10




NOTE 9 – ASSET RETIREMENT OBLIGATIONS


The Company accounts for plugging and abandonment costs in accordance with FASB Accounting Standards Codification 410-20, Accounting for Asset Retirement Obligations.


During the nine months ended September 30, 2012, plugging and abandonment costs related to certain properties exceeded the amount reflected in the asset retirement obligation liability.  Accordingly, the excess amount, which was $2,468,969, was recognized as a loss during the period.


A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations are as follows:


Balance at December 31, 2011

$

11,401,865 

Accretion expense

 

1,666,512 

Additions

 

Revisions

 

Settlements

 

(586,768)

Balance at September 30, 2012

$

12,481,609 


NOTE 10 – DEBT


Long-term debt consists of the following:


 

September 30,

 

December 31,

 

2012

 

2011

12.5% Senior Secured Notes due 2016

$

127,500,000 

 

$

127,500,000 

Less unamortized discount

 

1,849,867 

 

 

2,115,195 

 

$

125,650,133 

 

$

125,384,805 


2016 Notes


In July 2011, the Company and the several wholly-owned subsidiaries of the Company (the “Guarantors”) entered into a Purchase Agreement (the “Purchase Agreement”) with Imperial Capital, LLC (the “Initial Purchaser”), relating to the issuance and sale of $127.5 million in aggregate principal amount of the Company’s 12.5% Senior Secured Notes due 2016 (the “2016 Notes”). The 2016 Notes were sold at 98.221% of par. The 2016 Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The 2016 Notes were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act and to persons outside of the U.S. pursuant to Regulation S.


The 2016 Notes were issued pursuant to an indenture, dated July 12, 2011 (the “Indenture”), among the Company, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (the “Trustee”) and as collateral agent (the “Collateral Agent”). The 2016 Notes are the senior secured obligations of the Company and are fully and unconditionally guaranteed on a senior secured basis by the Guarantors and will rank equally in right of payment with the Company’s and the Guarantors’ existing and future senior indebtedness.


The 2016 Notes mature on July 1, 2016, and interest is payable on the 2016 Notes on January 1 and July 1 of each year, commencing January 1, 2012.


The Indenture includes customary events of default and places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.


The Company has the option to redeem all or a portion of the 2016 Notes at any time on or after January 1, 2014 at the redemption prices specified in the Indenture plus accrued and unpaid interest. The Company may also redeem the 2016 Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, plus accrued and unpaid interest, at any time prior to January 1, 2014. Within each twelve-month period commencing on July 12, 2012 and ending January 1, 2014, the Company may also redeem up to 10% of the aggregate principal amount of the 2016 Notes at a price equal to 106.25% of the principal amount thereof, plus accrued and unpaid interest.  In addition, the Company may redeem up to 35% of the 2016 Notes prior to January 1, 2014 under certain circumstances with the net cash proceeds from certain equity offerings and at a price equal to 112.5% of the principal amount thereof, plus accrued and unpaid interest.




11




NOTE 11 – COMMITMENTS AND CONTINGENCIES


From time to time the Company may become involved in litigation in the ordinary course of business. At September 30, 2012, the Company’s management was not aware, and as of the date of this report is not aware, of any such litigation that could have a material adverse effect on its results of operations, cash flows or financial condition.


Hurricane Isaac resulted in a disruption of production and the shut-in of 100% of our wells for a period of 17 days beginning August 26th and ending September 11, 2012.  The delay in returning field to productive status was primarily attributable to delays in third party pipeline transportation.  We experienced minimal damage to our asset base and estimate total gross repair cost at $1 million,  of which $0.75 million is expected to be covered by insurance.


The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of September 30, 2012, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company’s properties.


NOTE 12 – SUBSEQUENT EVENTS


During October 2012, the Company received gross proceeds of $83,364 for 37,588 stock options exercised at a weighted average of $2.22 per share. The stock options were granted in March 2010 and April 2010.


During October 2012, the Company entered into a fixed price swap at a rate of $110.85 per barrel covering 9,000 barrels of oil in November 2012 and 9,300 barrels in December 2012.



12





ITEM 2

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Forward-Looking Information


This Form 10-Q quarterly report of Saratoga Resources, Inc. (the “Company”) for the nine months ended September 30, 2012, contains certain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended to be covered by the safe harbors created thereby.  To the extent that there are statements that are not recitations of historical fact, such statements constitute forward-looking statements that, by definition, involve risks and uncertainties.  In any forward-looking statement, where we express an expectation or belief as to future results or events, such expectation or belief is expressed in good faith and believed to have a reasonable basis, but there can be no assurance that the statement of expectation or belief will be achieved or accomplished.


The actual results or events may differ materially from those anticipated and as reflected in forward-looking statements included herein. Factors that may cause actual results or events to differ from those anticipated in the forward-looking statements included herein include the Risk Factors described in Item 1A of our Form 10-K for the year ended December 31, 2011.


Readers are cautioned not to place undue reliance on the forward-looking statements contained herein, which speak only as of the date hereof. We believe the information contained in this Form 10-Q to be accurate as of the date hereof. Changes may occur after that date, and we will not update that information except as required by law in the normal course of our public disclosure practices.


Additionally, the following discussion regarding our financial condition and results of operations should be read in conjunction with the financial statements and related notes contained in Item 1 of Part 1 of this Form 10-Q, as well as the Risk Factors in Item 1A and the financial statements in Item 7 of Part II of our Form 10-K for the fiscal year ended December 31, 2011.


Overview


We are an independent oil and natural gas company engaged in the acquisition, development, exploitation, exploration and production of crude oil and natural gas properties.  Our principal properties were acquired in July 2008 and are located in the transitional coastline and protected in-bay environment on parish and state leases of south Louisiana.


At September 30, 2012, we operated or had interests in 101 producing wells and our principal properties covered approximately 32,119 gross/net acres, substantially all of which were held by production without near-term lease expirations, across 12 fields in the transitional coastline and protected in-bay environment on parish and state leases in south Louisiana. We own approximately 100% working interest in all our properties, with the only exceptions being a handful of wells where we have either a net profits interest or an overriding royalty interest. Our net revenue interests in our properties range from 62% to 88%, with our average net revenue interest on a net acreage leasehold basis being approximately 75%. We operate over 97% of the wells that comprise our PV-10, enabling us to effectively exercise management control of our operating costs, capital expenditures and the timing and method of development of our properties.


2012 Developments


Drilling and Development Activities


Drilling and development and infrastructure project operations to date in 2012 are summarized as follows:


Development Drilling.  During the nine months ended September 30, 2012, we drilled and completed three wells, two of which were dual completions, namely the Jupiter SL 195QQ #202 well in Grand Bay field, the Mesa Verde SL 3763 #14 well in Vermilion 16 field and the North Tiger SL 20433 #1well in Breton Sound Block 18 field.  Drilling related capital expenditures on those wells totaled $35.9 million through September 30, 2012.


We spud the SL 195QQ #202 “Jupiter” well in Grand Bay Field in July 2012 and drilled to 9,688 feet measured depth (“MD”)/true vertical depth (“TVD”). The well encountered 104 feet of net pay in 15 sands between 5,516 and 9,042 feet and was completed in the 15 sand in early August 2012. The well tested on August 14, 2012 at a gross rate of 245 barrels of oil per day (“BOPD”) and 650 thousand cubic feet of gas per day (“MCFPD”), or net 254 barrels of oil equivalent per day (“BOEPD”), on a 15/64” choke with flowing tubing pressure (“FTP”) of 860 psi.




13




We spud the SL 20433 #1 “North Tiger” well in Breton Sound Block 19 in July 2012 and drilled it as a directional well to 9,532 feet MD/9,300 feet TVD.  The well encountered 59 feet of net pay in 6 sands and was completed as a dual producer in October 2012.  The well tested on October 15, 2015 at a gross rate of 517 BOPD and 1,457 MCFPD on a 14/64” choke with FTP of 1,900 psi from the 7,100’ sand in the short string and 258 BOPD and 351 MCFPD on a 17/64” choke with FTP of 580 psi from the Cib Carst sand in the long string, or combined net 840 BOEPD.


We spud the SL 3763 #14 “Mesa Verde” well in Vermilion Block 16 Field in May 2012 and drilled to 16,258 feet MD/TVD.  The well encountered up to 15 potentially productive intervals, including the Marg A, LF, Rob 54 and Amph B sands between 11,333 and 15,890 feet and was completed in the LF-H sand in October 2012. The well tested on October 12, 2012 at a gross rate of 190 BOPD, 4,066 MCFPD, or net 685 BOEPD, on a 14/64” choke with FTP of 4,300 psi.  The Marg A sequence was encountered structurally higher than expected with much thinner MA-2, MA-3 and MA-4 sands compared to downdip well control to the northeast and we intend to evaluate a possible future sidetrack of the Mesa Verde well targeting thicker sand development to the north of the existing well bore once production from shallower potentially productive intervals has ceased.


Together, the Jupiter and North Tiger wells encountered 15 new, previously unbooked, pool discoveries.


Exploratory Drilling.  We did not drill any exploratory wells during the nine months ended September 30, 2012.


Recompletion and Workover Program.  During the nine months ended September 30, 2012, we invested $15.3 million in 12 recompletions, 8 of which were successful and 4 of which were unsuccessful, and an additional $3.8 million on 15 workovers, 11 of which were successful, and 4 of which were unsuccessful.


Infrastructure Program.  During the nine months ended September 30, 2012, we invested $2.8 million in infrastructure improvements and additions to support existing production and anticipated increases in production.


Drilling and Development Plans.  We have an extensive inventory of drilling opportunities, including numerous proved behind pipe and proved undeveloped opportunities as well as a number of exploratory opportunities.  Our near term development plans are focused on proved undeveloped opportunities and conversion of PDNP opportunities.


For the nine months ended September 30, 2012, we had approximately 101 gross (100 net) wells in production.


Effects of Hurricane Isaac


Hurricane Isaac resulted in a disruption of production and the shut-in of 100% of our wells for a period of 17days beginning August 26th and ending September 11, 2012.  The delay in returning field to productive status was primarily attributable to delays in third party pipeline transportation.  We experienced minimal damage to our asset base and estimate total gross repair cost at $1 million,  of which $0.75 million is expected to be covered by insurance.  As of November 1, 2012, we are continuing to make repairs and have returned all but two wells to productive status.  Work is in progress to bring the remaining wells back on line.  The hurricane also caused delays in the installation of the flowlines and facility infrastructure required for the North Tiger ( SL 20433 #1/1D ) well, which delayed our initial production startup by approximately 30 days.


Compensation


In March 2012, our board of directors approved a stock option grant to purchase an aggregate of 5,000 shares of common stock to a non-executive employee.  The options are exercisable for a term of seven years at $6.40 per share and vested ½ on grant and ½ on the first anniversary of the grant date.


In June 2012, our board of directors approved stock option grants to purchase an aggregate of 105,000 shares of common stock to non-employee directors.  The options are exercisable for a term of seven years at $6.65 per share and vest ½ on the date of grant and ½ on the first anniversary of the grant date.


As a result of the stock option grants during 2012, we recorded $471,316 of compensation charges that are reflected in general and administrative expense for the nine months ended September 30, 2012.


As of September 30, 2012, total compensation cost related to unvested stock option awards not yet recognized in earnings was approximately $0.7 million, which is expected to be recognized over a weighted average period of approximately 0.7 years.




14




In March 2012, our board of directors approved the adoption of the 2012 Annual Incentive Program which is intended to establish potential bonus payouts tied to satisfaction of performance criteria and established broad company performance criteria. Full payout under the program would result in bonuses of approximately $1.9 million.  $475,000 of compensation expense was reported during the nine months ended September 30, 2012 based on accrual of estimated bonus payments under the program.


Share Issuances for Cash


During the nine months ended September 30, 2012, we sold 125,912 shares of common stock for $292,491 pursuant to the exercise of outstanding stock options.


During the nine months ended September 30, 2012, we sold 892,327 shares of common stock for $4,461,635 pursuant to the exercise of outstanding stock warrants.


On May 24, 2012, we sold, in a private placement, an aggregate of 3,089,360 shares of common stock to certain institutional and accredited investors at a price of $6.25 per share, for net proceeds of approximately $18.4 million.


Hedging Activities


During the quarter ended September 30, 2012, we resumed our hedging program under which, in the normal course of business, we periodically enter into commodity derivative transactions, including fixed price and ratio swaps to mitigate exposure to commodity price movements, but not for trading or speculative purposes.  


As of September 30, 2012, we had in place a combination of forward physical contracts and swaps covering crude oil production over the balance of 2012. Included in such positions were forward physical contracts covering 300 barrels of oil per day, or an aggregate of 36,600 barrels of oil over the period beginning September 1 and ending December 31, 2012, at a fixed price of $107.55 per barrel and fixed price swaps covering an aggregate of 1,000 barrels of oil per day, or an aggregate of 92,000 barrels of oil over the period beginning September 1 and ending December 31, 2012, at prices ranging from $108.00 to $110.05 per barrel. Subsequent to September 30, 2012, we entered into an additional swap covering 300 barrels of oil per day, or an aggregate of 18,300 barrels of oil over the period beginning November 1 and ending December 31, 2012, at a price of $110.85 per barrel.


Results of Operations


Oil and Gas Revenue


Oil and gas revenue for the quarter ended September 30, 2012 decreased by 13% to $16.5 million from $18.9 million in the 2011 quarter.   For the nine month period ended September 30, 2012, oil and gas revenue increased 11% to $59.6 million from $53.5 million in the 2011 period.


For the quarter ended September 30, 2012, the decrease in revenue was attributable to a 6% decrease in production volumes combined with a 7% decrease in average hydrocarbon prices realized as compared to the 2011 quarter.  For the nine months ended September 30, 2012, the increase in revenue was attributable to an 18% increase in production volumes partially offset by a 6% decrease in average hydrocarbon prices realized as compared to the 2011 period.




15




The following table discloses the oil and gas sales revenues, net oil and natural gas production volumes and average sales prices for the three and nine months ended September 30, 2012 and 2011:



 

Three Months Ended

September 30,

 

 

Nine Months Ended

September 30,

 

 

2012

 

 

2011

 

 

2012

 

 

2011

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

$

14,206,497

 

 

$

16,687,429

 

 

$

52,790,300

 

 

$

47,537,599

Gas

 

 

2,247,628

 

 

 

2,198,521

 

 

 

6,798,143

 

 

 

5,921,542

Total oil and gas revenues

 

$

16,454,125

 

 

$

18,885,950

 

 

$

59,588,443

 

 

$

53,459,141

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

 

137,913

 

 

 

162,919

 

 

 

483,808

 

 

 

462,160

Gas (Mcf)

 

 

555,062

 

 

 

500,802

 

 

 

1,937,399

 

 

 

1,326,552

Total production (Boe)

 

 

230,423

 

 

 

246,386

 

 

 

806,708

 

 

 

683,252

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average sales price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

103.01

 

 

$

102.43

 

 

$

109.12

 

 

$

102.86

Gas (per Mcf)

 

 

4.05

 

 

 

4.39

 

 

 

3.51

 

 

 

4.46

Total average sales price (per Boe)

 

$

71.41

 

 

$

76.65

 

 

$

73.87

 

 

$

78.24


The decrease in production during the 2012 quarter was primarily due to lost production days as a result of hurricane Isaac. This decrease was partially offset by daily production increases attributable to our recompletion and workover program and efforts during the 2011 and 2012 periods to address deferred maintenance, third party facilities capacity limitations and infrastructure upgrades that resulted in the resumption of production, or increases in production.


The decrease in realized hydrocarbon prices reflects continued weakening of natural gas prices which were partially offset by a continued trend of increasing global crude oil prices.  During the 2012 period, we continued to realize a premium to prevailing WTI prices as a result of the quality of our oil produced.


Other Revenues


Other revenues consist principally of (i) a net profits interest attributable to operating the Breton Sound 31 field, for which we receive a percentage of profits, (ii) production handling fees from our Vermilion 16 field, (iii) during the 2012 period, settlements of lawsuits against the former owners of The Harvest Group LLC and Harvest Oil & Gas, LLC and (iv) during the 2011 quarter, refunds of severance taxes under a Louisiana incentive program relating to previously inactive wells.


Other revenue for the quarter ended September 30, 2012 decreased to $269,810 from $938,385 in the 2011 quarter.  For the nine months ended September 30, 2012, other revenue decreased to $1,467,403 from $4,368,436 for the 2011 period.  The decrease in other revenue was principally as a result of the one-time nature of the severance tax refunds totaling $1.9 million in the 2011 quarter.


Operating Expenses


Operating expenses decreased by 24% to $12.9 million for the quarter ended September 30, 2012 from $17.0 million in the 2011 quarter.  Operating expenses increased by 17% to $48.9 million for the nine months ended September 30, 2012 from $41.7 million in the 2011 period.




16




The following table sets forth the components of operating expenses for the 2012 and 2011 quarters:


 

Three Months Ended

 

Three Months Ended

 

September 30, 2012

 

September 30, 2011

 

Total

 

Per Boe

 

Total

 

Per Boe

Lease operating expense

$

4,622,010

 

$

20.06

 

$

4,590,675

 

$

18.64

Workover expense

 

306,745

 

 

1.33

 

 

32,549

 

 

0.13

Exploration expense

 

213,733

 

 

0.93

 

 

166,688

 

 

0.68

Loss on plugging and abandonment

 

-

 

 

-

 

 

-

 

 

-

Dry hole costs

 

-

 

 

-

 

 

3,787,911

 

 

15.37

Depreciation, depletion and amortization

 

3,658,002

 

 

15.87

 

 

4,009,462

 

 

16.27

Impairment expense

 

44,276

 

 

0.19

 

 

-

 

 

-

Accretion expense

 

555,504

 

 

2.41

 

 

399,634

 

 

1.62

General and administrative expenses

 

1,971,634

 

 

8.56

 

 

2,616,072

 

 

10.62

Production and severance taxes

 

1,502,134

 

 

6.52

 

 

1,431,567

 

 

5.81

 

$

12,874,038

 

$

55.87

 

$

17,034,558

 

$

69.14


The following table sets forth the components of operating expenses for the 2012 and 2011 periods:


 

Nine Months Ended

 

Nine Months Ended

 

September 30, 2012

 

September 30, 2011

 

Total

 

Per Boe

 

Total

 

Per Boe

Lease operating expense

$

13,860,709

 

$

17.18

 

$

12,683,787

 

$

18.57

Workover expense

 

3,846,046

 

 

4.77

 

 

458,286

 

 

0.67

Exploration expense

 

369,419

 

 

0.46

 

 

573,077

 

 

0.84

Loss on plugging and abandonment

 

2,468,969

 

 

3.06

 

 

-

 

 

-

Dry hole costs

 

93,353

 

 

0.11

 

 

3,787,911

 

 

5.54

Impairment expense

 

44,276

 

 

0.05

 

 

-

 

 

-

Depreciation, depletion and amortization

 

14,170,532

 

 

17.57

 

 

12,377,089

 

 

18.11

Accretion expense

 

1,666,512

 

 

2.07

 

 

1,248,478

 

 

1.83

General and administrative expenses

 

7,042,299

 

 

8.73

 

 

6,516,360

 

 

9.54

Production and severance taxes

 

5,375,259

 

 

6.66

 

 

4,096,641

 

 

5.99

 

$

48,937,374

 

$

60.66

 

$

41,741,629

 

$

61.09


The changes in operating expenses were primarily attributable to the factors discussed below.


Lease Operating Expenses


Lease operating expenses for the quarter ended September 30, 2012 increased 0.1% to $4,622,010 from $4,590,675 in the 2011 quarter, but on a per BOE basis increased 7.6% to $20.06 per BOE from $18.64 per BOE, in the 2011 quarter.  Lease operating expenses for the nine months ended September 30, 2012 increased 9.3% to $13,860,709 from $12,683,787 in the 2011 period, but decreased 7.5% to $17.18 per BOE from $18.57 per BOE, in the 2011 period.


Operating costs in our fields have historically been relatively high due to water handling, the need for gas lift to maintain oil production and due to the need for marine transportation in the shallow water, bay environment. The increases in operating expenses during the 2012 nine month period were primarily attributable to an increase in production volumes and an increase in operating expenses on third party operated properties and increases in transportation expenses.  The decrease in lease operating expenses on a per BOE basis for the nine month period was primarily attributable to the fixed nature of certain lease operating expenses.  The increase in total lease operating expenses for the quarter and in lease operating expenses on a per BOE basis for the quarter was primarily due to production losses from Hurricane Isaac.


Workover Expense


Workover expense for the quarter ended September 30, 2012 increased to $306,745 from $32,549 in the 2011 quarter and increased to $3,846,046 from $458,286 for the nine months ended September 30, 2012 from the 2011 period.  The change in workover expense was attributable to an increase in the number of workovers completed during the nine months ended September 30, 2012.




17




Exploration Expense


Exploration expense for the quarter ended September 30, 2012 increased to $213,733 from $166,688 in the 2011 quarter.  Exploration expense for the nine months ended September 30, 2012 decreased to $369,419 from $573,077 in the 2011 period.  Exploration expenses during 2012 principally relate to delay rentals.  The change in exploration expense was primarily attributable to the completion of our full field study program during early 2011 and delay rentals paid during the 2011 period.


Loss on plugging and abandonment


Loss on plugging and abandonment for the nine months ended September 30, 2012 totaled $2,468,969 due to costs of plugging and abandoning wells in Little Bay, South Atchafalaya Bay and Crooked Bayou fields that exceeded those estimated in our calculation of asset retirement obligation liabilities.  Four of the wells plugged were the deepest and highest pressure wells in our entire inventory of wells to be plugged.  These wells were orphaned wells on expired leases which we inherited from the previous owners and which have never produced since we have owned the assets.  In addition, several of the wells had unanticipated severe casing damage.  Accordingly, the actual costs incurred in plugging and abandoning these wells was substantially higher than we estimated and would expect to incur in future plugging operations.


Dry hole costs


Dry hole costs decreased for the quarter and nine month period ended September 30, 2012 due primarily to the cost of the Rio Grande well which was drilled as a dry hole during the third quarter of 2011.


Depreciation, Depletion and Amortization (DD&A)


Depreciation, depletion and amortization for the quarter ended September 30, 2012 decreased 8.9% to $3,658,002 from $4,009,462 in the 2011 quarter and decreased to $15.87 per BOE from $16.27 per BOE in the 2011 quarter.  Depreciation, depletion and amortization for the nine months ended September 30, 2012 increased 14.5% to $14,170,532 from $12,377,089 in the 2011 period, but decreased to $17.57 per BOE from $18.11 per BOE in the 2011 period.


We utilize the successful efforts method of accounting for oil and gas producing activities.  Under this method, DD&A is computed on the units-of-production method separately on each individual property and includes the accrual of future plugging and abandonment costs.  The decrease in DD&A expense for the quarter reflects lost production volumes due to hurricane Isaac, while the increase for the nine month period reflects increased production volumes.


Impairment expense


Impairment expense relating to our Breton Sound 51 Field of $44,276 was recorded during the 2012 quarter.  The impairment expense was a result of one of the three producing wells in the field becoming fully depleted during the quarter.


Accretion expense


Accretion expense relating to our asset retirement obligations increased to $555,504 from $399,634 for the quarter ended September 30, 2012 as compared to the 2011 quarter.  Accretion expense increased to $1,666,512 from $1,248,478 for the nine months ended September 30, 2012 as compared to the 2011 period.


The increase in accretion expense was attributable to changes in the anticipated plugging dates and discount rates used in calculating the asset retirement obligation for certain fields.


General and Administrative Expenses and Other


General and administrative (“G&A”) expense for the quarter ended September 30, 2012 decreased 24.6% to $1,971,634 from $2,616,072 in the 2011 quarter, and was 19.4% lower on a per BOE basis. For the nine months ended September 30, 2012, general and administrative expense increased by 8.0% to $7,042,299 from $6,516,360 in the 2011 period, and decreased 8.5% on a per BOE basis. The decrease in G&A expense for the quarter was primarily attributable to decreases in head count and stock based compensation.  The increase in G&A expense for the nine month period was primarily attributable to the accrual of estimated bonuses under the 2012 Annual Incentive Program.




18




Severance Taxes


Severance taxes for the quarter ended September 30, 2012 increased to $1,502,134 from $1,431,567 in the 2011 quarter, primarily due to severance tax refunds received during 2011.  For the nine months ended September 30, 2012, severance taxes increased to $5,375,259 from $4,096,641 for the 2011 period.  The change in severance taxes for the nine month period was attributable to increased production partially offset by decreased severance tax rates for our inactive wells.


Other Income (Expense), Net


Net other Income (expense) decreased to $4.3 million in expense for the quarter ended September 30, 2012 from $3.4 million in net income for the 2011 quarter.  For the nine months ended September 30, 2012, net other expense decreased to $13.0 million as compared to $5.7 million in the 2011 period.


The following table sets forth the components of net other income (expenses) for the 2012 and 2011 quarter and nine month periods:


 

Three Months Ended

September 30,

 

Nine Months Ended

September 30,

 

2012

 

2011

 

2012

 

2011

Interest income

 

11,204 

 

 

37,492 

 

 

20,046 

 

 

237,078 

Interest expense

 

(4,334,389)

 

 

(4,384,499)

 

 

(13,058,178)

 

 

(13,620,011)

Gain on extinguishment of debt

 

 

 

7,708,486 

 

 

 

 

7,708,486 

 

$

(4,323,185)

 

$

3,361,479 

 

$

(13,038,132)

 

$

(5,674,447)


The change in other income (expense), net, was principally attributable to a gain on the extinguishment of debt recorded during the third quarter of 2011.


Reorganization Expenses


Reorganization expenses reflect payments to professionals and other fees incurred in connection with our prior Chapter 11 case. Reorganization expenses decreased to $43,287 during the quarter ended September 30, 2012 from $125,420 in the 2011 quarter.  Reorganization expense decreased to $121,528 during the nine months ended September 30, 2012 from $374,414 in the 2011 period.  The decrease in reorganization expenses was attributable to our exit from bankruptcy in May 2010.


Income Tax Expense (Benefit)


For the quarter ended September 30, 2012 we recorded an income tax benefit of $48,062 compared to $146,082 in the 2011 quarter.  For the nine months ended September 30, 2012 we recorded an income tax benefit of $213,896 compared to $91,368 for the 2011 period.


Our effective tax rates were different than our federal statutory tax rate due to Louisiana state income taxes associated with income from various locations in which we have operations.  Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices, the timing, amount, and location of future production and future operating expenses and capital costs.


Financial Condition


Liquidity and Capital Resources


Our principal requirements for capital are to fund our day-to-day operations and exploration, development and acquisition activities and to satisfy our contractual obligations, primarily for the repayment of debt.


Since early 2009, we have not had access to capital under a revolving credit facility and have funded operations out of operating cash flow and cash on hand, which funds have been supplemented by capital raises.  At September 30, 2012, and continuing as of this writing, we had not yet established a revolving credit facility and continue to evaluate multiple potential options regarding the establishment of such a facility.




19




We have developed a layered, multi-faceted development and maintenance program designed to achieve short-, mid- and long-term objectives. Short-term, our focus is on restoration of shut-in and curtailed production through investments in infrastructure and deferred maintenance and recompletions, workovers and thru-tubing plugbacks each designed to increase or restore production volumes from wells producing below capacity and an inventory of proved developed nonproducing opportunities. Mid-term, following or in conjunction with execution of short-term opportunities, our focus is on the development of an inventory of proved undeveloped opportunities within our inventory of proved undeveloped wells targeting normally pressured oil and gas.  Long-term, following or in conjunction with the execution of our short- and mid-term opportunities, our focus is on continuing development of our reserves and exploratory drilling of deep shelf opportunities.


We believe that our cash flows from operations and cash on hand, including funds received from our 2012 equity and 2011 equity and note offerings are sufficient to support our liquidity needs for the next twelve months, including funding all of our current short-term objectives, including investments in planned infrastructure and deferred maintenance, recompletions, workovers and through-tubing plugbacks.  We believe that our cash flows from operations and cash on hand will also be sufficient to pursue our current mid-term objectives relating to development of proved undeveloped opportunities.  Our development of proved undeveloped opportunities is scalable.  Depending upon the results of our short-term development initiatives, initial development efforts relating to our proved undeveloped opportunities and any further capital efforts, we may accelerate our planned development of proved undeveloped opportunities or otherwise adjust the nature or rate of our development program.  As a result of the loss of production and associated revenues relating to the shut-in of production in the wake of Hurricane Isaac, our cash and liquidity position weakened during the quarter ended September 30, 2012 and we have deferred various projects originally planned during the fourth quarter of 2012 until later periods.


We continue discussions with McMoRan and other parties regarding the formation of joint ventures to explore our deep and ultra-deep shelf prospects at Vermilion 16 and Grand Bay.


Unexpected declines in commodity prices or production levels, or failures in achieving production increases through short- and mid-term development plans, could result in our inability to support our operations and drilling and development plans.


Further, as noted above, in order to further supplement our liquidity and increase our operating flexibility, we intend to enter into a new revolving credit facility and may seek other forms of debt and/or equity financings. We continue to pursue efforts to enter into a definitive agreement to provide a revolving credit facility but, as of this writing, have not yet established such a facility and there can be no assurance that we will be successful in establishing a revolving credit facility on terms that we consider to be favorable or at all.


Cash, Cash Flows and Working Capital


We had a cash balance of $8.3 million and a working capital deficit of $6.5 million at September 30, 2012 as compared to a cash balance of $15.9 million and working capital of $8.5 million at December 31, 2011. The decrease in cash on hand and working capital is primarily attributable to production losses from Hurricane Isaac.


Operations provided cash flow of $14.0 million for the nine months ended September 30, 2012 as compared to $22.9 million for the nine months ended September 30, 2011. The change in operating cash flows during 2012 was principally attributable to decreased revenues during the quarter ended September 30, 2012 together with an increase in payables and accrued expenses reflecting increased developmental drilling activity.


Investing activities used cash totaling $45.3 million during the nine months ended September 30, 2012 as compared to cash used in investing of $22.6 million during the nine months ended September 30, 2011.  The increase in cash used in investing activities during 2012 was attributable to increased development activity on our oil and gas properties and infrastructure upgrades.  Including the cash invested, balances in accounts payable and accrued liabilities, we incurred $54.0 million and $23.7 million for oil and gas development activities for the nine months ended September 30, 2012 and 2011, respectively.


Financing activities provided cash flows of $23.7 million during the nine months ended September 30, 2012 as compared to cash provided by financing activities of $8.6 million during nine months ended September 30, 2011.  Cash flows provided by financing activities during the 2012 period related to our equity offering and funds received for the exercise of common stock options and warrants.


Debt and Non-Current Liabilities


At September 30, 2012, we had $125.7 million of indebtedness outstanding (reflecting a $1.8 million debt discount) compared to $125.4 million of indebtedness outstanding at December 31, 2011 (reflecting a $2.1 million debt discount), consisting of $127.5 million under our 2016 Notes.



20




The principal terms of our debt and non-current liabilities at September 30, 2012 were as follows:


2016 Notes.  In July 2011, we issued $127.5 million in face amount of our 12.5% Senior Secured Notes due 2016.  The 2016 Notes are our senior secured obligations and are fully and unconditionally guaranteed on a senior secured basis by the Guarantors and will rank equally in right of payment with our and the Guarantors’ existing and future senior indebtedness. The 2016 Notes mature on July 1, 2016, and interest is payable on the 2016 Notes on January 1 and July 1 of each year, commencing January 1, 2012.


We have the option to redeem all or a portion of the 2016 Notes at any time on or after January 1, 2014 at the redemption prices specified in the Indenture pursuant to which the 2016 Notes were issued plus accrued and unpaid interest. We may also redeem the 2016 Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, plus accrued and unpaid interest, at any time prior to January 1, 2014. Within each twelve-month period commencing on July 12, 2012 and ending January 1, 2014, we may also redeem up to 10% of the aggregate principal amount of the 2016 Notes at a price equal to 106.25% of the principal amount thereof, plus accrued and unpaid interest.  In addition, we may redeem up to 35% of the 2016 Notes prior to January 1, 2014 under certain circumstances with the net cash proceeds from certain equity offerings and at a price equal to 112.5% of the principal amount thereof, plus accrued and unpaid interest.


Capital Expenditures and Commitments


Our capital spending for the nine months ended September 30, 2012 was $53.9 million relating primarily to development of our oil and gas properties, including completion of 10 recompletions and investments in multiple infrastructure projects.


As of October 1, 2012, we anticipate that our capital budget for the last quarter of 2012 will be approximately$4 million, excluding potential acquisitions and capital requirements associated with any joint ventures to develop our deep prospects.  As noted, we have the operational flexibility to react quickly with our capital expenditures to changes in our cash flows from operations.  Actual levels of capital expenditures in any year may vary significantly due to many factors, including the extent to which properties are acquired, drilling results, oil and gas prices, industry conditions and the prices and availability of goods and services.


Off-Balance Sheet Arrangements


We had no off-balance sheet arrangements or guarantees of third party obligations at September 30, 2012.


Inflation


We believe that inflation has not had a significant impact on our operations since inception.


ITEM 3

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


Commodity Price Risk


Our major market-risk exposure is the commodity pricing applicable to our oil and natural gas production.  Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas.  Prices have fluctuated significantly during the last five years and such volatility is expected to continue, and the range of such price movement is not predictable with any degree of certainty. During the quarter ended September 30, 2012, we resumed our hedging program under which, in the normal course of business we periodically enter into commodity derivative transactions, including fixed price and ratio swaps to mitigate exposure to commodity price movements, but not for trading or speculative purposes.


As of September 30, 2012, we had in place a combination of forward physical contracts and swaps covering crude oil production over the balance of 2012.  Included in such positions were forward physical contracts covering 300 barrels of oil per day, or an aggregate of 36,600 barrels of oil over the period beginning September 1 and ending December 31, 2012, at a fixed price of $107.55 per barrel.  Additionally, at September 30, 2012, we had the following crude oil hedge contracts outstanding:


 

 

Beginning

 

Ending

 

Fixed

 

Total

 

Net Unrealized

Instrument

 

Date

 

Date

 

Price

 

Bbls

 

Gain (Loss)

Swap

 

October 2012

 

December 2012

 

$

110.05 

 

27,600 

 

$

(6,463)

Swap

 

October 2012

 

December 2012

 

 

108.05 

 

32,200 

 

 

(91,298)

Swap

 

October 2012

 

December 2012

 

$

108.00 

 

32,200 

 

 

(91,298)

 

 

 

 

 

 

 

 

 

92,000 

 

$

(189,059)


Subsequent to September 30, 2012, we entered into an additional crude oil swap contract for the period November 2012 to December 2012 covering 300 barrels of oil per day at $110.85.




21




We are exposed to market risk on derivative instruments to the extent of changes in market prices of crude oil.  However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity.  Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts.  The change in the fair value of our commodity derivative contracts that are effective are recorded to Accumulated Other Comprehensive Income (Loss) in Stockholders’ Equity in the Consolidated Balance Sheet.  The ineffective portion of the change in fair market value of derivatives is recorded currently in earnings as a component of Oil and Gas Hedging in the Consolidated Statements of Operations.  We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities.  For the three months ended September 30, 2012, we recorded an unrealized loss on commodity derivatives of $6,490 in current earnings and an unrealized loss on commodity derivatives of $182,569 in accumulated other comprehensive income (loss).


Shell Trading (US) Company is the counterparty to each of our present forward physical contracts and fixed price swap contracts. We are exposed to credit losses in the event of nonperformance by the counterparty on our commodity derivatives positions.  However, we do not anticipate nonperformance by the counterparty over the term of the commodity derivatives positions.


Interest Rate Risk


All of our debt has a fixed interest rate and we are not presently exposed to interest rate risk.  In the event that we establish a new revolving credit facility we expect that such facility will provide for interest at a floating rate and that borrowing under such facility will expose us to risk of changing interest rates.


ITEM 4

CONTROLS AND PROCEDURES


Evaluation of Disclosure Controls and Procedures


Under the supervision and the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation as of September 30, 2012 of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2012.


Changes in Internal Control over Financial Reporting


No change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) occurred during the quarter ended September 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.





22




PART II


ITEM 6

EXHIBITS


Exhibit No.

 

Description

 

 

 

31.1

 

Certification of CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 

 

 

31.2

 

Certification of CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 

 

 

32.1

 

Certification of CEO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

 

 

32.2

 

Certification of CFO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

 

 

101.INS

 

XBRL Instance Document

101.SCH

 

XBRL Schema Document

101.CAL

 

XBRL Calculation Linkbase Document

101.DEF

 

XBRL Definition Linkbase Document

101.LAB

 

XBRL Labels Linkbase Document

101.PRE

 

XBRL Presentation Linkbase Document




SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on behalf by the undersigned thereunto duly authorized.


  

SARATOGA RESOURCES, INC.

Date:  November 13, 2012 

  

  

  

By:

/s/ Thomas Cooke

  

  

Thomas Cooke

  

  

Chief Executive Officer

  

  

  

  

By:

/s/ Michael Aldridge

  

  

Michael Aldridge

  

  

Executive Vice President and Chief

Financial Officer





23