Edgar Filing: SARATOGA RESOURCES INC /TX

SARATOGA RESOURCES, INC.

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 March 31, 2013


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 x	Non-accelerated filer ¨	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 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 May 3, 2013, we had 30,911,601 shares of $0.001 par value Common Stock outstanding.

SARATOGA RESOURCES, INC.

FORM 10-Q

INDEX


		Page No.
PART I FINANCIAL INFORMATION		3

ITEM 1. Financial Statements (Unaudited)		3
	Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012	3
	Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2013 and 2012	4
	Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012	5
	Notes to Consolidated Financial Statements	6
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		11
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		19
ITEM 4. Controls and Procedures		20

PART II OTHER INFORMATION		21

ITEM 6. Exhibits		21

PART I - FINANCIAL INFORMATION

ITEM 1

Financial Statements


SARATOGA RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)

	March 31,		December 31,
	2013		2012
ASSETS

Current assets:
Cash and cash equivalents	$	21,997,531	$	32,302,313
Accounts receivable		10,166,005		12,430,158
Prepaid expenses and other		659,106		1,268,971
Derivative asset		157,183		-
Other current asset		150,000		150,000
Total current assets		33,129,825		46,151,442

Property and equipment:
Oil and gas properties - proved (successful efforts method)		268,047,053		260,916,084
Other		802,732		795,138
		268,849,785		261,711,222
Less: Accumulated depreciation, depletion and amortization		(86,848,766)		(81,640,272)
Total property and equipment, net		182,001,019		180,070,950

Deferred tax asset, net		8,986,822		8,499,575
Other assets, net		20,040,370		19,929,394
Total assets	$	244,158,036	$	254,651,361

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	3,457,324	$	7,259,244
Revenue and severance tax payable		5,315,337		6,129,867
Accrued liabilities		5,735,078		10,787,044
Derivative liabilities – short term		-		171,086
Short-term notes payable		-		373,360
Asset retirement obligation – current		-		256,200
Total current liabilities		14,507,739		24,976,801

Long-term liabilities:
Asset retirement obligation		17,400,201		16,815,736
Long-term debt, net of unamortized discount of $1,986,188 and $2,104,106, respectively		150,513,812		150,395,894
Total long-term liabilities		167,914,013		167,211,630

Commitment and contingencies (see notes)

Stockholders' equity:
Common stock, $0.001 par value; 100,000,000 shares authorized 30,911,601 and 30,905,101 shares issued and outstanding at March 31, 2013 and December 31, 2012, respectively		30,912		30,905
Additional paid-in capital		77,313,431		77,140,451
Accumulated other comprehensive loss		(9,326)		(171,086)
Retained deficit		(15,598,733)		(14,537,340)

Total stockholders' equity		61,736,284		62,462,930

Total liabilities and stockholders' equity	$	244,158,036	$	254,651,361

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

SARATOGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	For the Three Months Ended
	March 31,
	2013		2012
Revenues:
Oil and gas revenues	$	19,261,901	$	19,343,680
Oil and gas hedging		(648,380)		-
Other revenues		119,675		874,248

Total revenues		18,733,196		20,217,928

Operating Expense:
Lease operating expense		4,558,833		4,570,699
Workover expense		261,262		1,471,468
Exploration expense		168,284		57,396
Loss on plugging and abandonment		-		1,612,290
Dry hole costs		-		89,874
Depreciation, depletion and amortization		5,208,494		4,937,152
Accretion expense		638,097		555,504
General and administrative		2,103,534		2,746,483
Severance taxes		2,091,054		1,680,879

Total operating expenses		15,029,558		17,721,745

Operating income		3,703,638		2,496,183

Other income (expense):
Interest income		6,080		3,316
Interest expense		(5,222,942)		(4,411,111)

Total other expense		(5,216,862)		(4,407,795)

Net loss before reorganization expenses and income taxes		(1,513,224)		(1,911,612)

Reorganization expenses		2,319		43,205

Net loss before income taxes		(1,515,543)		(1,954,817)

Income tax benefit		(454,150)		(735,743)

Net income loss	$	(1,061,393)	$	(1,219,074)

Other Comprehensive income (loss)
Unrealized gain on derivative instruments		161,760		-
Total comprehensive income (loss)	$	(899,633)	$	(1,219,074)

Net loss per share:
Basic	$	(0.03)	$	(0.04)
Diluted	$	(0.03)	$	(0.04)

Weighted average number of common shares outstanding:
Basic		30,911,023		27,114,972
Diluted		30,911,023		27,114,972

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


SARATOGA RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	For the Three Months Ended
	March 31,
	2013		2012
Cash flows from operating activities:
Net loss	$	(1,061,393)	$	(1,219,074)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		5,208,494		4,937,152
Accretion expense		638,097		555,504
Amortization of debt issuance costs		320,870		216,469
Amortization of debt discount		117,918		85,007
Dry hole costs		-		89,874
Stock-based compensation		163,042		261,783
Loss on plugging and abandonment		-		1,612,290
Deferred tax benefit		(487,247)		(768,243)
Unrealized gain on hedges		(166,509)		-
Changes in operating assets and liabilities:
Accounts receivable		2,264,153		(850,178)
Prepaids and other		609,865		322,907
Accounts payable		(4,380,931)		(556,757)
Revenue and severance tax payable		(814,530)		7,118
Payments to settle asset retirement obligations		(309,832)		(705,462)
Accrued liabilities		(5,126,160)		(3,105,187)
Net cash (used in) provided by operating activities		(3,024,163)		883,203

Cash flows from investing activities:
Additions to oil and gas property		(6,477,765)		(4,029,778)
Additions to other property and equipment		(7,594)		(10,446)
Other assets		(431,845)		(196,368)
Net cash used in investing activities		(6,917,204)		(4,236,592)

Cash flows from financing activities:
Proceeds from issuance of common stock		9,945		2,576,950
Repayment of short-term notes payable		(373,360)		(344,256)
Net cash (used in) provided by financing activities		(363,415)		2,232,694

Net increase (decrease) in cash and cash equivalents		(10,304,782)		(1,120,695)
Cash and cash equivalents - beginning of period		32,302,313		15,874,680
Cash and cash equivalents - end of period	$	21,997,531	$	14,753,985

Supplemental disclosures of cash flow information:
Cash paid for income taxes	$	33,097	$	-
Cash paid for interest		9,541,508		7,485,332

Non-cash investing and financing activities:
Unrealized gain on derivative instruments	$	161,760	$	-
Accounts payable for oil and gas additions		579,019		2,565,795
Accrued liabilities for oil and gas additions		74,185		355,243

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

SARATOGA RESOURCES, INC.

Notes to Consolidated Financial Statements

March 31, 2013

(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 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, 2012.

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 $21.7 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.

NOTE 2 – DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objective and Strategies for Using Commodity Derivative Instruments

The Company periodically enters into commodity derivative instruments, primarily fixed price swaps, to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company. The fixed price swap contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price. The amount payable by us, if the floating price is above the fixed price, is the product of the notional quantity per calculation period and the excess of the floating price over the fixed price with respect to each calculation period. The amount payable by the counterparty, if the floating price is below the fixed price, is the product of the notional quantity per calculation period and the excess of the fixed price over the floating price with respect to each calculation period.

While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits from future increases in commodity prices.

See Note 3 – “Fair Value Measurements” for a discussion of the methods and assumptions used to estimate the fair values of our commodity derivative instruments.

The Company utilizes hedge accounting for our commodity derivative instruments, which are designated as cash flow hedges.

Counterparty Credit Risk

Commodity derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are with two and one counterparties at March 31, 2013 and December 31, 2012, respectively. We monitor and manage our level of financial exposure with respect to the counterparties we use. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election.

We monitor the creditworthiness of our commodity derivatives counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk.

As of March 31, 2013, the Company had the following hedge contracts outstanding:


	Beginning	Ending	Fixed		Total
Instrument	Date	Date	Price		Bbls
Fixed Price Swap	April 2013	December 2013	$	106.82	137,500
Fixed Price Swap	April 2013	March 2014	$	109.20	159,500
					297,000

The following table presents the fair value of the Company’s commodity derivative instruments at March 31, 2013 and December 31, 2012:


	March 31,		December 31,
Description	2013		2012
Current Assets:
Commodity derivatives	$	157,183	$	-
	$	157,183	$	-
Current liabilities:
Commodity derivatives	$	-	$	171,086
	$	-	$	171,086

NOTE 3 – 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.

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 March 31, 2013 and December 31, 2012:


	Level 1		Level 2		Level 3		Total
March 31, 2013
Assets:
Commodity derivatives	$	-	$	157,183	$	-	$	157,183
	$	-	$	157,183	$	-	$	157,183

December 31, 2012
Liabilities:
Commodity derivatives	$	-	$	171,086		-	$	171,086
	$	-	$	171,086		-	$	171,086

The Company uses various commodity derivative instruments, including fixed price swaps. We consider the fair value of our commodity derivative instruments to be level 2 on the fair value hierarchy. The fair value of commodity derivatives is determined using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data.

NOTE 4 – OTHER ASSETS

Other assets consist of the following:


	March 31,		December 31,
	2013		2012
Site specific trust accounts - P&A escrow	$	5,485,049	$	5,279,084
Debt issuance cost, net		5,452,066		5,728,755
Restricted cash – P&A bond		8,873,497		8,873,497
Other		229,758		48,058
	$	20,040,370	$	19,929,394

Site Specific Trust Accounts – P&A Escrow

The Company maintains an escrow agreement that has been established for the purpose of assuring maintenance and administration of a performance bond which secures 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 2013. See Note 8 – “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 March 31, 2013 and December 31, 2012 reflect the issuance of the 2016 Notes in December 2012 and July 2011. See Note 9 – “Debt”.

Restricted Cash – P&A Bond

Restricted Cash – P&A Bond consists of cash collateral held in escrow to assure maintenance and administration of performance bonds which secures certain plugging and abandonment obligations imposed by state law. The cash collateral is reflected as a long term asset to correspond with the expected timing of the related asset retirement obligation liability. See Note 8 – “Asset Retirement Obligations”.

NOTE 5 – 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 Plan

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.

Stock Option Activity

The following table summarizes information about stock option activity and related information for the three months ended March 31, 2013:


	Number of Shares Underlying Options		Weighted Average Exercise Price per Share		Weighted Average Grant Date Fair Value per Share		Weighted Average Remaining Contractual Life (in Years)	Aggregate Intrinsic Value ⁽¹⁾
Outstanding at December 31, 2012		784,000	$	3.66	$	3.65	6.5	$	474,240
Granted		-		-		-	-		-
Exercised		(6,500)		1.53		1.53	-		-
Forfeited		-		-		-	-		-
Outstanding at March 31, 2013		777,500	$	3.68	$	3.67	6.3	$	175,275
Exercisable at March 31, 2013		551,666	$	3.23	$	3.22	6.4	$	160,208

(1)

The intrinsic value of an option is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the option. On March 28, 2013, the last reported sales price of our common stock on the NYSE MKT was $2.66 per share.

Share-Based Compensation Expense

The following table reflects share-based compensation recorded by the Company for the three months ended March 31, 2013 and 2012:


	Three Months Ended March 31,
	2013		2012
Share-based compensation expense included in reported net income	$	163,042	$	261,783
Basic earnings per share effect of share-based compensation expense	$	(0.01)	$	(0.01)

As of March 31, 2013, total unrecognized stock-based compensation expense related to non-vested stock options was $0.4 million. The unrecognized expense is expected to be recognized over a weighted average period of 0.5 years.

NOTE 6 – EQUITY

Common Stock Activity

In January 2013, the Company received gross proceeds of $9,945 for 6,500 stock options exercised at $1.53 a share.

Warrant Activity

The following table summarizes information about stock warrant activity and related information for the three months ended March 31, 2013:


	Number of Shares Underlying Warrants		Weighted Average Exercise Price per Share		Weighted Average Grant Date Fair Value per Share		Weighted Average Remaining Contractual Life (in Years)	Aggregate Intrinsic Value ⁽¹⁾
Outstanding at December 31, 2012		572,628	$	5.14	$	3.22	0.8	$	132,900
Granted		-		-		-	-		-
Exercised		-		-		-	-		-
Forfeited		-		-		-	-		-
Outstanding at March 31, 2013		572,628	$	5.14	$	3.22	0.6	$	80,500
Exercisable at March 31, 2013		572,628	$	5.14	$	3.22	0.6	$	80,500

(1)

The intrinsic value of a warrant is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the warrant. On March 28, 2013, the last reported sales price of our common stock on the NYSE MKT was $2.66 per share.

NOTE 7 – EARNINGS (LOSS) PER SHARE

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


	For the Three Months Ended March 31,
	2013					2012
	Income (Loss)		Weighted Average Common Shares Outstanding	Per Share		Income (Loss)		Weighted Average Common Shares Outstanding	Per Share
Basic:
Loss attributable to common stock	$	(1,061,393)	30,911,023	$	(0.03)	$	(1,219,074)	27,114,972	$	(0.04)
Effect of Dilutive Securities:
Stock options and other			-					-
Diluted:
Loss attributable to common stock, including assumed conversions	$	(1,061,393)	30,911,023	$	(0.03)	$	(1,219,074)	27,114,972	$	(0.04)

NOTE 8 – 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.

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


Balance at December 31, 2012	$	17,071,936
Accretion expense		638,097
Additions		-
Revisions		-
Settlements		(309,832)
Balance at March 31, 2013	$	17,400,201

NOTE 9 – DEBT

Long-term debt consists of the following:


	March 31,		December 31,
	2013		2012
12.5% Senior Secured Notes due 2016	$	152,500,000	$	152,500,000
Less unamortized discount		1,986,188		2,104,106
	$	150,513,812	$	150,395,894

2016 Notes

In July 2011, the Company and the several wholly-owned subsidiaries of the Company (the “Guarantors”) entered into a 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. 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.

In December 2012, the Company and the Guarantors entered into another Purchase Agreement with the Initial Purchaser, relating to the issuance and sale of an additional $25 million in aggregate principal amount of the Company’s 2016 Notes. The 2016 Notes were sold at 98.58% of par. The 2016 Notes were offered and sold in a transaction exempt from the registration requirements of 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 “Base 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”) and, with respect to the 2016 Notes issued in 2012, a First Supplemental Indenture, dated December 4, 2012 (the “Supplemental Indenture” and, together with the Base Indenture, the “Indenture”). 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.

NOTE 10 – COMMITMENTS AND CONTINGENCIES

In March 2013, we bid on, and were the apparent high bidder relative to, four leases, with seismic maps included, totaling 19,814 acres in the Central Gulf of Mexico Lease Sale 227. The acreage is in the shallow Gulf of Mexico shelf in water depths of 13 to 77 feet. Two of the leases are in the Vermilion area and two of the leases are in the Ship Shoal area. Final award of the leases is subject to BOEMRE review. Lease bonuses on the prospects total $880,000 and first year annual rentals total $138,698. Additionally, assuming final award of the leases, we will pay a prospect fee of $450,000 to a third party consultant.

From time to time the Company may become involved in litigation in the ordinary course of business. At March 31, 2013, 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.

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 March 31, 2013, 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.

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 three months ended March 31, 2013, 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, 2012.

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 8 of Part II of our Form 10-K for the fiscal year ended December 31, 2012.

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 March 31, 2013, we operated or had interests in 105 producing wells and our principal properties covered approximately 32,027 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.

2013 Developments

Drilling and Development Activities

Drilling and development and infrastructure project operations to date in 2013 are summarized as follows:

Development Drilling. During the three months ended March 31, 2013, we completed the SL 195QQ-209 “Buddy” well in Grand Bay Field and drilled and completed the MP 47 SL 195QQ-25 “Roux Toux” well in Main Pass 47 Field.

Exploratory Drilling. We did not drill any exploratory wells during the three months ended March 31, 2013.

Recompletion and Workover Program. During the three months ended March 31, 2013, we invested $0.3 million in 3 recompletions, all of which were successful, and an additional $0.3 million on 2 workovers, 1 of which was still in progress at the end of the quarter.

Infrastructure Program. During the three months ended March 31, 2013, we invested $0.8 million in infrastructure improvements and additions to support existing production and anticipated increases in production, primarily in Grand Bay Field.

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 three months ended March 31, 2013, we had approximately 105 gross (104 net) wells in production.

Effects of Hurricane Isaac

As of March 31, 2013, we had completed all ongoing projects relating to restoration of production and repairs arising from the effects of Hurricane Isaac.

Compensation

As of March 31, 2013, total compensation cost related to unvested stock option awards not yet recognized in earnings was approximately $0.4 million, which is expected to be recognized over a weighted average period of approximately 0.5 years.

Share Issuances for Cash

During the three months ended March 31, 2013, we sold 6,500 shares of common stock for $9,945 pursuant to the exercise of outstanding stock options.

Hedging Activities

As of March 31, 2013, we had in place fixed price swaps covering an aggregate of 297,000 barrels of oil over the period beginning April 1, 2013 and ending March 31, 2014, at prices ranging from $106.82 to $109.20 per barrel.

Gulf of Mexico Shelf Acreage

Results of Operations

Oil and Gas Revenue

Oil and gas revenue for the quarter ended March 31, 2013 stayed flat at $19.3 million.

The following table discloses the oil and gas sales revenues, net oil and natural gas production volumes and average sales prices for the three months ended March 31, 2013 and 2012:


	Three Months Ended March 31,
	2013		2012
Revenues
Oil	$	17,388,900	$	17,130,340
Gas		1,873,001		2,213,340
Total oil and gas revenues	$	19,261,901	$	19,343,680

Production
Oil (Bbls)		156,770		150,744
Gas (Mcf)		443,346		620,717
Total production (Boe)		230,661		254,197

Average sales price
Oil (per Bbl)	$	110.92	$	113.64
Gas (per Mcf)		4.22		3.57
Total average sales price (per Boe)	$	83.51	$	76.10

The decrease in production during the quarter was primarily due a curtailment of production due to third party handling issues and a temporary lack of available gas lift gas in Main Pass 25 Field, where production was down 21.5 MBOE compared to the 2012 quarter. In addition, the QQ24 well in Grand Bay Field was shut-in for five weeks during the drilling of the QQ25 well resulting in a decrease in production of 4.5 MBOE compared to the 2012 quarter. Also contributing to the production decrease were shut ins due to work associated with infrastructure improvements. Residual curtailments caused by the lingering effects of Hurricane Isaac also effected production during the 2013 quarter. The decreases in production were partially offset by new wells that came on production over the last 3 quarters of 2012 and the first quarter of 2013. At quarter end, all curtailments related to gas lift and third party handling issues in Main Pass 25 field, as well as the residual curtailments associated with Hurricane Isaac had been resolved.

The increase in realized hydrocarbon prices reflects a general strengthening of natural gas prices, partially offset by slight moderation in crude oil prices. We continued to realize a premium to WTI pricing on both our crude oil and natural gas production.

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, and (iii) during the 2012 period, settlements of lawsuits against the former owners of The Harvest Group LLC and Harvest Oil & Gas, LLC.

Other revenue for the quarter ended March 31, 2013 decreased to $119,675 from $874,248 in the 2012 quarter. The decrease in other revenue was principally as a result of the one-time nature of lawsuit settlements, totaling $604,591, in the 2012 quarter.

Operating Expenses

Operating expenses decreased by 15.2% to $15.0 million for the quarter ended March 31, 2013 from $17.7 million in the 2012 quarter. The following table sets forth the components of operating expenses for the 2013 and 2012 quarters:


	Three Months Ended				Three Months Ended
	March 31, 2013				March 31, 2012
	Total		Per Boe		Total		Per Boe
Lease operating expense	$	4,558,833	$	19.76	$	4,570,699	$	17.98
Workover expense		261,262		1.13		1,471,468		5.79
Exploration expense		168,284		0.73		57,396		0.23
Loss on plugging and abandonment		-		-		1,612,290		6.34
Dry hole costs		-		-		89,874		0.35
Depreciation, depletion and amortization		5,208,494		22.58		4,937,152		19.42
Accretion expense		638,097		2.77		555,504		2.18
General and administrative		2,103,534		9.12		2,746,483		10.80
Severance taxes		2,091,054		9.07		1,680,879		6.61
	$	15,029,558	$	65.16	$	17,721,745	$	69.72

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

Lease Operating Expense

Lease operating expenses for the quarter ended March 31, 2013 were essentially flat at $4.6 million as compared to the 2012 quarter, but on a per BOE basis increased 9.9% to $19.76 per BOE from $17.98 per BOE, in the 2012 quarter.

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 increase in lease operating expenses on a per BOE basis for the three month period was primarily attributable to the 9.3% decrease in production volumes and the fixed nature of certain lease operating expenses.

Workover Expense

Workover expense for the quarter ended March 31, 2013 decreased to $261,262 from $1,471,468 in the 2012 quarter. The change in workover expense was attributable to a decrease in the number of workovers completed during 2013 quarter.

Exploration Expense

Exploration expense for the quarter ended March 31, 2013 increased to $168,284 from $57,396 in the 2012 quarter. Exploration expenses principally relate to delay rentals and field studies related to Grand Bay Field.

Loss on plugging and abandonment

Loss on plugging and abandonment for the three months ended March 31, 2012 totaled $1,612,290 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.

Depreciation, Depletion and Amortization (DD&A)

Depreciation, depletion and amortization for the quarter ended March 31, 2013 increased 5.5% to $5,208,494 from $4,937,152 in the 2012 quarter and increased to $22.58 per BOE from $19.42 per BOE in the 2012 quarter.

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 increase in DD&A expense and DD&A expense per BOE, during the 2013 quarter was attributable to additional capital expenditures incurred in our development program.

Accretion expense

Accretion expense relating to our asset retirement obligations increased to $638,097 from $555,504 for the quarter ended March 31, 2013 as compared to the 2012 quarter.

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

General and administrative (“G&A”) expense for the quarter ended March 31, 2013 decreased 23.4% to $2,103,534 from $2,746,483 in the 2012 quarter, and was 15.6% lower on a per BOE basis. The decrease in G&A expense for the quarter was primarily attributable to decreases in head count (reducing salary, wages and benefits approximately $280,000) and stock based compensation (down $98,741).

Severance Taxes

Severance taxes for the quarter ended March 31, 2013 increased to $2,091,054 from $1,680,879 in the 2012 quarter. The increase was primarily attributable to a reduced number of inactive wells eligible for certain Louisiana severance tax exemptions.

Other Income (Expense), Net

Net other income (expense) increased to $5.2 million in expense for the quarter ended March 31, 2013 from $4.4 million for the 2012 quarter.

The following table sets forth the components of net other income (expenses) for the 2013 and 2012 quarters:


	Three Months Ended March 31,
	2013		2012
Interest income		6,080		3,316
Interest expense		(5,222,942)		(4,411,111)
	$	(5,216,862)	$	(4,407,795)

Interest expense reflects interest incurred on debt under our senior secured notes and our prior term credit agreement and revolving credit agreement. The increase in interest expense was attributable to our placement of an additional $25.0 million in principal amount of senior secured notes in December 2012.

Reorganization Expenses

Reorganization expenses reflect payments to professionals and other fees incurred in connection with our prior Chapter 11 case. Reorganization expenses decreased to $2,319 during the quarter ended March 31, 2013 from $43,205 in the 2012 quarter. The decrease in reorganization expenses was attributable to our exit from bankruptcy in May 2010.

Income Tax Benefit

For the quarter ended March 31, 2013 we recorded an income tax benefit of $454,150 compared to $735,743 in the 2012 quarter.

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 payment of interest and repayment of debt.

Since 2009, we have operated without access to a revolving credit facility and have funded operations out of operating cash flow and cash on hand, which funds have been supplemented by our receipt of funds from our April and July 2011 and May 2012 equity capital raises and our December 2012 issuance of senior secured notes described herein. At March 31, 2013, 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.

We developed, and beginning in 2011 commenced, a layered, multi-faceted development and maintenance program designed to achieve short-, mid- and long-term objectives. Short-term objectives are focused 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. During 2011, we achieved our principal short-term objectives through substantial investments in infrastructure upgrades. During 2012 and continuing in the first quarter of 2013, while continuing to advance short-term objectives associated with continual investment in our infrastructure, recompletions and workovers, we focused on our mid-term objectives as reflected in continued investment in our developmental drilling program.

As noted, we have supplemented our cash and liquidity position through a series of equity capital raises during 2011 and 2012, consisting of (1) the receipt of $7.4 million from the sale of common stock and warrants in April 2011, (2) the receipt of $27.3 million from the sale of common stock in July 2011, and (3) the receipt of $18.4 million from the sale of common stock in May 2012. We have utilized the proceeds from the offerings of such stock and warrants to support accelerated investments in our development and maintenance program.

Further, during July 2011, we received $120.9 million of net proceeds from the sale of our 2016 Notes and, during December 2012, we received $23.4 million of net proceeds from the sale of additional 2016 Notes. Funds received from the July 2011 common stock offering and offering of 2016 Notes were used to repay indebtedness under our prior credit facilities.

We believe that our cash flows from operations and cash on hand, including funds received from our 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, ongoing development efforts relating to our proved undeveloped opportunities and any further capital commitments, we may accelerate our planned development of proved undeveloped opportunities or otherwise adjust the nature or rate of our development program. Pursuit of our long-term plans for exploratory drilling of deep shelf prospects is expected to require funding in excess of our current resources and projected operating cash flow and to be dependent upon results attained by other operators that are currently pioneering ultra-deep drilling in the trend within which our ultra-deep prospects are located. At March 31, 2013, we were continuing to monitor developments within the ultra-deep trend and to be engaged in discussions with various potential partners relative to the potential exploration of our ultra-deep prospects. We presently lack the financial resources to carry our proportionate share of the anticipated exploration and development costs associated with such joint venture and will be required to secure additional financing to support our share of such costs and maintain our interest in such ultra-deep prospects. To that end, we expect to seek partners to enter into arrangements that will provide the necessary funding to pay some, or all, of our share of the joint venture costs with the effect of reducing our interest in the joint venture. We presently have no commitments to provide funding to cover our share of such costs.

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. To that end, we continue to pursue efforts to secure 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 $22.0 million and working capital of $18.6 million at March 31, 2013 as compared to a cash balance of $32.3 million and working capital of $21.2 million at December 31, 2012. The decrease in cash on hand was primarily attributable to the interest payment on our 2016 notes made in January and investments in our development program. The decrease in our working capital was primarily attributable to utilization of cash to fund our development program.

Operations used cash flow of $3.0 million for the three months ended March 31, 2013 as compared to providing $0.9 million for the three months ended March 31, 2012. The change in operating cash flows during 2013 was principally attributable changes in our operating assets and liabilities, in particular reductions in accrued liabilities reflecting payment of accrued interest on our 2016 Notes in January 2013.

Investing activities used cash totaling $6.9 million during the three months ended March 31, 2013 as compared to cash used in investing of $4.2 million during the three months ended March 31, 2012. We incurred $7.1 million and $7.0 million for oil and gas development activities for the three months ended March 31, 2013 and 2012, respectively. The increase in cash used in investing activities during 2013 was attributable primarily to the fact that a large percentage of development costs were included in accounts payable and accrued liabilities at the end of the 2012 quarter.

Financing activities used cash flows of $0.4 million during the three months ended March 31, 2013 as compared to cash provided by financing activities of $2.2 million during the three months ended March 31, 2012. Cash flows used by financing activities during the 2013 period related to repayment of our short term debt.

Debt and Non-Current Liabilities

At March 31, 2013, we had $150.5 million of indebtedness outstanding (reflecting a $2.0 million debt discount) compared to $150.4 million of indebtedness outstanding at December 31, 2012 (reflecting a $2.1 million debt discount), consisting of $152.5 million under our 2016 Notes.

The principal terms of our debt and non-current liabilities at March 31, 2013 were as follows:

2016 Notes. In July 2011, we issued $127.5 million of our 2016 Notes and retired all obligations owing under our prior credit facilities and all outstanding letter of credit obligations. In December 2012, we issued an additional $25.0 million of our 2016 Notes.

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 three months ended March 31, 2013 was $7.1 million relating primarily to development of our oil and gas properties, including completion of 3 recompletions and investments in multiple infrastructure projects.

As of April 1, 2013, we anticipate that our capital budget for the remaining three quarters of 2013 will be approximately$37.1 million, excluding potential acquisitions and capital requirements associated with any joint ventures to develop our deep prospects. If we are ultimately awarded, and consummate, the Gulf of Mexico leases on which we were the apparent high bidder, we will be required to pay lease bonuses and other costs of approximately $1.3 million at the time the leases are finalized. 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 March 31, 2013.

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 March 31, 2013, we had the following hedge contracts outstanding:


	Beginning	Ending	Fixed		Total
Instrument	Date	Date	Price		Bbls
Fixed Price Swap	April 2013	December 2013	$	106.82	137,500
Fixed Price Swap	April 2013	March 2014	$	109.20	159,500
					297,000

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 Loss in Stockholders’ Equity in the Consolidated Balance Sheets. 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 and Comprehensive Income. 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 March 31, 2013, we recorded an unrealized gain on commodity derivatives of $166,509 in current earnings and an unrealized gain on commodity derivatives of $161,760 in accumulated other comprehensive income (loss).

At March 31, 2013, we had two counterparties to our fixed price swap contracts. We are exposed to credit losses in the event of nonperformance by any counterparty on our commodity derivatives positions. However, we do not anticipate nonperformance by any 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 March 31, 2013 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 not effective as of March 31, 2013.

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 March 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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: May 10, 2013
	By:	/s/ Thomas Cooke
		Thomas Cooke
		Chief Executive Officer

	By:	/s/ Michael Aldridge
		Michael Aldridge
		Executive Vice President and Chief Financial Officer