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 June 30, 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 August 5, 2013, we had 30,941,601 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 June 30, 2013 and December 31, 2012	3
	Consolidated Statements of Operations and Other Comprehensive Income (Loss) for the three and six months ended June 30, 2013 and 2012	4
	Consolidated Statements of Cash Flows for the six months ended June 30, 2013 and 2012	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

PART I - FINANCIAL INFORMATION

ITEM 1

Financial Statements


SARATOGA RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,		December 31,
	2013		2012
ASSETS

Current assets:
Cash and cash equivalents	$	30,168,859	$	32,302,313
Accounts receivable		8,062,373		12,430,158
Prepaid expenses and other		2,395,058		1,268,971
Derivative asset		1,570,374		-
Other current asset		150,000		150,000
Total current assets		42,346,664		46,151,442

Property and equipment:
Oil and gas properties - proved (successful efforts method)		273,141,969		260,916,084
Other		868,671		795,138
		274,010,640		261,711,222
Less: Accumulated depreciation, depletion and amortization		(92,511,308)		(81,640,272)
Total property and equipment, net		181,499,332		180,070,950

Deferred tax asset, net		10,078,704		8,499,575
Other assets, net		19,544,488		19,929,394
Total assets	$	253,469,188	$	254,651,361

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	6,450,634	$	7,259,244
Revenue and severance tax payable		4,919,493		6,129,867
Accrued liabilities		11,573,160		10,787,044
Derivative liabilities – short term		-		171,086
Short-term notes payable		1,354,049		373,360
Asset retirement obligation – current		-		256,200
Total current liabilities		24,297,336		24,976,801

Long-term liabilities:
Asset retirement obligation		18,038,298		16,815,736
Long-term debt, net of unamortized discount of $1,864,032 and $2,104,106, respectively		150,635,968		150,395,894
Total long-term liabilities		168,674,266		167,211,630

Commitment and contingencies (see notes)

Stockholders' equity:
Common stock, $0.001 par value; 100,000,000 shares authorized 30,941,601 and 30,905,101 shares issued and outstanding at June 30, 2013 and December 31, 2012, respectively		30,942		30,905
Additional paid-in capital		77,691,753		77,140,451
Accumulated other comprehensive income (loss)		687,643		(171,086)
Retained deficit		(17,912,752)		(14,537,340)

Total stockholders' equity		60,497,586		62,462,930

Total liabilities and stockholders' equity	$	253,469,188	$	254,651,361

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


SARATOGA RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE INCOME (LOSS)
(Unaudited)


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2013		2012		2013		2012
Revenues:
Oil and gas revenues	$	17,727,757	$	23,790,638	$	36,989,658	$	43,134,318
Oil and gas hedging		1,139,217		-		490,837		-
Other revenues		82,466		364,467		246,349		1,290,096
Total revenues		18,949,440		24,155,105		37,726,844		44,424,414

Operating Expense:
Lease operating expense		5,200,113		4,709,122		9,803,154		9,331,202
Workover expense		1,167,870		2,067,833		1,429,132		3,539,301
Exploration expense		115,687		98,290		283,971		155,686
Loss on plugging and abandonment		-		856,679		-		2,468,969
Dry hole costs		-		3,479		-		93,353
Depreciation, depletion and amortization		5,662,542		5,575,388		10,871,036		10,512,540
Accretion expense		638,097		555,504		1,276,194		1,111,008
General and administrative		2,335,208		2,324,182		4,438,742		5,070,665
Severance taxes		1,901,558		2,192,246		3,992,612		3,873,125
Total operating expenses		17,021,075		18,382,723		32,094,841		36,155,849

Operating income		1,928,365		5,772,382		5,632,003		8,268,565

Other income (expense):
Interest income		10,345		4,169		18,460		13,666
Interest expense		(5,312,111)		(4,311,321)		(10,537,088)		(8,728,613)
Total other expense		(5,301,766)		(4,307,152)		(10,518,628)		(8,714,947)

Net income (loss) before reorganization expense and income taxes		(3,373,401)		1,465,230		(4,886,625)		(446,382)

Reorganization expense		-		35,036		2,319		78,241

Net income (loss) before income taxes		(3,373,401)		1,430,194		(4,888,944)		(524,623)

Income tax expense (benefit)		(1,059,382)		569,909		(1,513,532)		(165,834)

Net income (loss)	$	(2,314,019)	$	860,285	$	(3,375,412)	$	(358,789)

Other comprehensive income(loss)
Unrealized gain (loss) on derivative instruments		696,969		-		858,729		-
Total comprehensive income(loss)	$	(1,617,050)	$	860,285	$	(2,516,683)	$	(358,789)

Net income (loss) per share:
Basic	$	(0.07)	$	0.03	$	(0.11)	$	(0.01)
Diluted	$	(0.07)	$	0.03	$	(0.11)	$	(0.01)

Weighted average number of common shares outstanding:
Basic		30,926,766		28,657,191		30,918,938		27,886,081
Diluted		30,926,766		29,285,509		30,918,938		27,886,081

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


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

	For the Six Months Ended
	June 30,
	2013		2012
Cash flows from operating activities:
Net loss	$	(3,375,412)	$	(358,789)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		10,871,036		10,512,540
Accretion expense		1,276,194		1,111,008
Amortization of debt issuance costs		658,970		441,986
Amortization of debt discount		240,074		173,568
Dry hole costs		-		93,353
Stock-based compensation		536,294		835,194
Loss on plugging and abandonment		-		2,468,969
Deferred tax benefit		(1,579,129)		(230,834)
Unrealized gain on hedges		(882,731)		-
Changes in operating assets and liabilities:
Accounts receivable		4,367,785		1,133,620
Prepaids and other		397,218		197,429
Accounts payable		(3,453,228)		6,210,509
Revenue and severance tax payable		(1,210,374)		49,691
Payments to settle asset retirement obligations		(309,832)		(709,228)
Accrued liabilities		334,269		(939,214)
Net cash (used in) provided by operating activities		7,871,134		20,989,802

Cash flows from investing activities:
Additions to oil and gas property		(9,129,420)		(24,298,595)
Additions to other property and equipment		(73,533)		(14,387)
Other assets		(274,064)		(816,581)
Net cash used in investing activities		(9,477,017)		(25,129,563)

Cash flows from financing activities:
Proceeds from issuance of common stock		15,045		22,473,270
Repayment of short-term notes payable		(542,616)		(531,484)
Net cash (used in) provided by financing activities		(527,571)		21,941,786

Net increase (decrease) in cash and cash equivalents		(2,133,454)		17,802,025
Cash and cash equivalents - beginning of period		32,302,313		15,874,680
Cash and cash equivalents - end of period	$	30,168,859	$	33,676,705

Supplemental disclosures of cash flow information:
Cash paid for income taxes	$	65,597	$	65,000
Cash paid for interest		9,551,144		7,495,018

Non-cash investing and financing activities:
Unrealized gain on derivative instruments	$	858,729	$	-
Accounts payable for oil and gas additions		2,644,617		2,838,068
Accrued liabilities for oil and gas additions		451,848		930,335
Prepaid insurance financed with debt		1,523,305		1,685,206

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

SARATOGA RESOURCES, INC.

Notes to Consolidated Financial Statements

June 30, 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 $29.9 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 June 30, 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 June 30, 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	92,000
Fixed Price Swap	April 2013	March 2014	$	109.20	114,000
					206,000

The following table presents the fair value of the Company’s commodity derivative instruments at June 30, 2013 and December 31, 2012:


	June 30,		December 31,
Description	2013		2012
Current Assets:
Commodity derivatives	$	1,570,374	$	-
	$	1,570,374	$	-
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 June 30, 2013 and December 31, 2012:


	Level 1		Level 2		Level 3		Total
June 30, 2013
Assets:
Commodity derivatives	$	-	$	1,570,374	$	-	$	1,570,374
	$	-	$	1,570,374	$	-	$	1,570,374

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:


	June 30,		December 31,
	2013		2012
Site specific trust accounts - P&A escrow	$	5,502,569	$	5,279,084
Debt issuance cost, net		5,114,664		5,728,755
Restricted cash – P&A bond		8,873,497		8,873,497
Other		53,758		48,058
	$	19,544,488	$	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 June 30, 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

In April 2013, the Company’s board of directors approved a stock option grant to purchase an aggregate of 75,000 shares of common stock to two non-executive employees. The options are exercisable for a term of five years at prices ranging from $2.34 to $2.42 per share and vest 1/3 on each of the first three grant date anniversaries. The grant date value of the options was $178,200. The options were valued using the Black-Scholes model with the following assumptions: 240% volatility; 4.5 year estimated life; zero dividends; 0.60% to 0.62% discount rate; and, quoted stock price and exercise price of $2.34 to $2.42.

In June 2013, the Company’s board of directors approved a stock option grant to purchase an aggregate of 500,000 shares of common stock to two executive officers. The options are exercisable for a term of five years at $3.00 per share and vest 1/8 per quarter. The grant date value of the options was $505,000. The options were valued using the Black-Scholes model with the following assumptions: 83% volatility; 3.06 year estimated life; zero dividends; 0.57% discount rate; and, quoted stock price of $2.18.

In June 2013, the Company’s board of directors approved a stock option grant 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 $2.18 per share and vest 1/2 on the date of grant and ½ on the first anniversary of the grant date. The grant date value of the options was $174,300. The options were valued using the Black-Scholes model with the following assumptions: 121% volatility; 3.75 year estimated life; zero dividends; 0.77% discount rate; and, quoted stock price and exercise price of $2.18.

The following table summarizes information about stock option activity and related information for the six months ended June 30, 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		680,000		2.81		1.26	5.5		-
Exercised		(6,500)		1.53		1.53	-		-
Forfeited		-		-		-	-		-
Outstanding at June 30, 2013		1,457,500	$	3.27	$	2.54	3.3	$	59,900
Exercisable at June 30, 2013		666,666	$	3.41	$	3.35	6.2	$	59,900

(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 June 28, 2013, the last reported sales price of our common stock on the NYSE MKT was $1.53 per share.

Share-Based Compensation Expense

The following table reflects share-based compensation recorded by the Company for the three and six months ended June 30, 2013 and 2012:


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Share-based compensation expense included in reported net income	$	373,252	$	573,411	$	536,294	$	835,194
Basic earnings per share effect of share-based compensation expense	$	(0.01)	$	(0.02)	$	(0.02)	$	(0.03)

As of June 30, 2013, total unrecognized stock-based compensation expense related to non-vested stock options was $0.8 million. The unrecognized expense is expected to be recognized over a weighted average period of 0.7 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.

In May 2013, the Company received gross proceeds of $5,100 for 30,000 stock warrants exercised at $0.17 a share.

Warrant Activity

The following table summarizes information about stock warrant activity and related information for the six months ended June 30, 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		(30,000)		0.17		0.17	-		-
Forfeited		(390,630)		5.00		2.69	-		-
Outstanding at June 30, 2013		151,998	$	6.47	$	5.21	1.8	$	150
Exercisable at June 30, 2013		151,998	$	6.47	$	5.21	1.8	$	150

(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 June 28, 2013, the last reported sales price of our common stock on the NYSE MKT was $1.53 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 June 30,
	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	$	(2,314,019)	30,926,766	$	(0.07)	$	860,285	28,657,191	$	0.03
Effect of Dilutive Securities:
Stock options and other			-					628,318
Diluted:
Loss attributable to common stock, including assumed conversions	$	(2,314,019)	30,926,766	$	(0.07)	$	860,285	29,285,509	$	0.03


	For the Six Months Ended June 30,
	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	$	(3,375,412)	30,918,938	$	(0.11)	$	(358,789)	27,886,081	$	(0.01)
Effect of Dilutive Securities:
Stock options and other			-					-
Diluted:
Loss attributable to common stock, including assumed conversions	$	(3,375,412)	30,918,938	$	(0.11)	$	(358,789)	27,886,081	$	(0.01)

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		1,276,194
Additions		-
Revisions		-
Settlements		(309,832)
Balance at June 30, 2013	$	18,038,298

NOTE 9 – DEBT

Long-term debt consists of the following:


	June 30,		December 31,
	2013		2012
12.5% Senior Secured Notes due 2016	$	152,500,000	$	152,500,000
Less unamortized discount		1,864,032		2,104,106
	$	150,635,968	$	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

Contingencies

From time to time the Company may become involved in litigation in the ordinary course of business. At June 30, 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 June 30, 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.

Contractual Commitments – Employment Agreements

On June 10, 2013, the Company entered into new employment agreements with its Chairman and Chief Executive Officer, Thomas Cooke, and its President, Andrew Clifford. The employment agreements supersede and replace the 2007 employment agreements of Messrs. Cooke and Clifford. Each of the employment agreements has a three-year term and automatically renews for additional one-year terms thereafter unless either parties provides notice of non-renewal at least thirty days in advance of the end of the then current term.

The new employment agreements reflect the following changes in the principal terms of employment of Messrs. Cooke and Clifford: (i) the annual base salary of Messrs. Cooke and Clifford is increased from its current level of $305,000 by 4%, to $317,200, on July 1, 2013 and increases by 4% on July 1 of each succeeding year; (ii) the automobile allowance of Messrs. Cooke and Clifford is modified to either provide a Company vehicle or pay a monthly automobile allowance, which allowance remains $700 per month for Mr. Clifford and was increased to $950 per month for Mr. Cooke; additionally, beyond repair and maintenance costs previously paid by the Company, the automobile allowance has been revised to cover all costs of operating a vehicle; (iii) the expense reimbursement provisions have been modified to clarify that the Company will pay all incremental costs associated with maintenance of home offices by Messrs. Cooke and Clifford, including costs of internet service, telephone and facsimile service and, with respect to Mr. Clifford, a home workstation; (iv) travel pay in the amount of $200 per day has been added by Messrs. Cooke and Clifford for each overnight stay or out-of-town travel of twenty-four hours exclusively for business purposes; (v) Messrs. Cooke and Clifford each received options to purchase 250,000 shares of common stock exercisable at $3.00 per share for a term of five years and vesting on a quarterly basis over eight quarters; (vi) in the event of termination of employment due to death or disability, the Company will continue to pay base salary to the executive or his estate for a period of twelve months; and (vii) in the event of termination of employment by the Company without cause or by the executive for “good reason”, the Company shall pay a lump sum to the executive in an amount equal to two times the base salary and bonus paid during the twelve months immediately preceding termination and shall continue to provide health insurance for a period of twenty-four months.

NOTE 11 – SUBSEQUENT EVENTS

In July 2013, final leases were awarded, 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. The leases have a primary term of five years and can be extended for an additional three years. Lease bonuses on the prospects totaled $880,000 and first year annual rentals total $138,698. Additionally, the Company will pay a prospect fee of $500,000 to a third party consultant. The cost of the leases, in the amount of $1,380,000, has been recorded in oil and gas properties at June 30, 2013 and first year lease rentals of $138,698 is recorded as other assets at June 30, 2013. Lease bonuses, totaling $880,000, and first year lease rentals, totaling $138,698, were paid during the quarter ended June 30, 2013 and the prospect fee of $500,000 was recorded in accounts payable at June 30, 2013.

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 six months ended June 30, 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 producing properties were acquired in July 2008 and cover 32,219 acres in the transitional coastline and protected in-bay environment on parish and state leases of south Louisiana. In July 2013, we acquired an additional 19,814 acres of leases in the shallow Gulf of Mexico shelf, increasing our total lease holdings to 52,033 acres.

At June 30, 2013, we operated or had interests in 105 producing wells and our principal properties covered approximately 32,219 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 six months ended June 30, 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. In July 2013, we spud and completed the SL 1224 #25 “Rocky” well and are presently awaiting hook up and testing of the well. Following completion of the Rocky well, in August 2013 we immediately spud the SL 1227 #26 “Zeke” well. The Rocky well represents our first horizontal development well in our Breton Sound 32 field.

Exploratory Drilling. We did not drill any exploratory wells during the six months ended June 30, 2013.

Recompletion and Workover Program. During the six months ended June 30, 2013, we invested $1.9 million in12 recompletions, 7 of which were successfully completed and 5 of which were still in progress at the end of the quarter, and an additional $1.4 million on 6 workovers, all of which were successfully completed during the quarter. Included in the recompletions and workovers were investments of $1.6 million in our tubing replacement program which accounted for 8 of the recompletions and 1 of the workovers undertaken during the quarter, including 4 recompletions in progress at quarter end.

Infrastructure Program. During the six months ended June 30, 2013, we invested $2.7 million in infrastructure improvements and additions to support existing production and anticipated increases in production, primarily in Grand Bay Field and Main Pass 25 Field. The Main Pass 25 facility upgrade has now been completed and is expected to address the production curtailments in that field that were experienced during the first six months of 2013.

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. We began to drill the SL 1224 #26 “Zeke” well immediately following completion of the Rocky well. In addition, we are starting efforts to find joint venture partners for our Gulf of Mexico prospects, as well as some of the Grand Bay deep prospects.

For the six months ended June 30, 2013, we had approximately 105 gross (104 net) wells in production.

Gulf of Mexico Shelf Acreage

In July 2013, final leases were awarded pursuant to our high bid on 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. The leases have a primary term of five years and can be extended for an additional three years. Lease bonuses on the prospects totaled $880,000 and first year annual rentals total $138,698. Additionally, the Company will pay a prospect fee of $500,000 to a third party consultant. The cost of the leases, in the amount of $1,380,000, has been recorded in oil and gas properties at June 30, 2013 and first year lease rentals of $138,698 is recorded as other assets at June 30, 2013. Lease bonuses, totaling $880,000, and first year lease rentals, totaling $138,698, were paid during the quarter ended June 30, 2013 and the prospect fee of $500,000 was recorded in accounts payable at June 30, 2013.

Compensation

In April 2013, our board of directors approved a stock option grant to purchase an aggregate of 75,000 shares of common stock to two non-executive employees. The options are exercisable for a term of seven years at prices ranging from $2.34 to $2.42 per share and vest 1/3 on each of the first three grant date anniversaries.

In June 2013, our board of directors approved new employment agreements for our two principal officers, Thomas Cooke and Andy Clifford. Pursuant to the new employment agreements, (i) the annual base salary of Messrs. Cooke and Clifford was increased from its then current level of $305,000 by 4%, to $317,200, on July 1, 2013 and increases by 4% on July 1 of each succeeding year; (ii) the automobile allowance of Messrs. Cooke and Clifford was modified to either provide a company vehicle or pay a monthly automobile allowance, which allowance remains $700 per month for Mr. Clifford and was increased to $950 per month for Mr. Cooke; additionally, beyond repair and maintenance costs previously paid by the company, the automobile allowance has been revised to cover all costs of operating a vehicle; (iii) the expense reimbursement provisions were modified to clarify that the company will pay all incremental costs associated with maintenance of home offices by Messrs. Cooke and Clifford, including costs of internet service, telephone and facsimile service and, with respect to Mr. Clifford, a home workstation; (iv) travel pay in the amount of $200 per day was added for each overnight stay or out-of-town travel of twenty-four hours exclusively for business purposes; (v) Messrs. Cooke and Clifford each received options to purchase 250,000 shares of common stock exercisable at $3.00 per share for a term of five years and vesting on a quarterly basis over eight quarters; (vi) in the event of termination of employment due to death or disability, we will continue to pay base salary to the executive or his estate for a period of twelve months; and (vii) in the event of termination of employment by the company without cause or by the executive for “good reason”, we will pay a lump sum to the executive in an amount equal to two times the base salary and bonus paid during the twelve months immediately preceding termination and shall continue to provide health insurance for a period of twenty-four months.

In June 2013, our board of directors approved a stock option grant 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 $2.18 per share and vest 1/2 on the date of grant and ½ on the first anniversary of the grant date.

As a result of the stock option grants during 2013, we recorded $225,592 of compensation charges that are reflected in general and administrative expense for the six months ended June 30, 2013.

As of June 30, 2013, total compensation cost related to unvested stock option awards not yet recognized in earnings was approximately $0.8 million, which is expected to be recognized over a weighted average period of approximately 0.7 years.

Share Issuances for Cash

During the six months ended June 30, 2013, we sold 6,500 shares of common stock for $9,945 pursuant to the exercise of outstanding stock options and 30,000 shares for $5,100 pursuant to the exercise of outstanding stock warrants.

Hedging Activities

As of June 30, 2013, we had in place fixed price swaps covering an aggregate of 206,000 barrels of oil over the period beginning July 1, 2013 and ending March 31, 2014, at prices ranging from $106.82 to $109.20 per barrel.

Results of Operations

Oil and Gas Revenue

Oil and gas revenue for the quarter ended June 30, 2013 decreased by 25% to $17.7 million from $23.8 million in the 2012 quarter. For the six month period ended June 30, 2013 oil and gas revenue decreased by 14% to $37.0 million from $43.1 million in the 2012 period.

For the quarter ended June 30, 2013, the decrease in revenue was attributable to a 26.2% decline in oil revenues on a 21.2% decrease in oil production volumes and a 6.3% decrease in average oil prices realized and an 18.9% decline in gas revenues on a 43.5% decrease in gas production volumes partially offset by a 43.6% increase in average prices realized, each as compared to the 2012 quarter. For the six months ended June 30, 2013, the decrease in revenue was attributable to a 13.9% decline in oil revenues on a 10.2% decrease in oil production volumes and a 4.1% decrease in average oil prices realized and a 17.2% decline in gas revenues on a 36.8% decrease in gas production volumes partially offset by a 31.0% increase in average gas prices realized, each as compared to the 2012 period.

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 six months ended June 30, 2013 and 2012:


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Revenues
Oil	$	15,831,909	$	21,453,463	$	33,220,809	$	38,583,803
Gas		1,895,848		2,337,175		3,768,849		4,550,515
Total oil and gas revenues	$	17,727,757	$	23,790,638	$	36,989,658	$	43,134,318

Production
Oil (Bbls)		153,753		195,151		310,523		345,895
Gas (Mcf)		430,381		761,620		873,727		1,382,337
Total production (Boe)		225,483		322,088		456,144		576,285

Average sales price
Oil (per Bbl)	$	102.97	$	109.93	$	106.98	$	111.55
Gas (per Mcf)		4.41		3.07		4.31		3.29
Total average sales price (per Boe)	$	78.62	$	73.86	$	81.09	$	74.85

The decrease in production during the quarter and six months, outside of natural reserve declines, was primarily due to reductions in production in Main Pass 25, Main Pass 46 and Grand Bay fields. In Main Pass 25 Field, production was curtailed due to third party handling issues and a temporary lack of available gas lift gas accounting for a decrease in production of 10.1 MBbl for oil and 18.0 MMcf (or, 3.0 MBOE) for gas compared to the 2012 quarter and 24.3 MBbl for oil and 61.0 MMcf (or, 10.2 MBOE) for gas compared to the 2012 six month period. In Main Pass 46 Field, the Catina well suffered gradually worsening flow line restrictions resulting in a 12.5 MBbl decrease in production of oil compared to the 2012 quarter and a 25.9 MBbl decrease in production of oil compared to the 2012 six month period. As a result of these flow line restrictions, the Catina well has recently been shut-in for repair. In Grand Bay Field shut-ins due to drilling of our QQ25 well and work associated with infrastructure improvements, mechanical issues and gas lift interruptions were principal drivers of a decline in oil production of 40.1 MBbl and gas production of 114.1 MMcf (or, 19.0 MBOE) compared to the 2012 quarter and a decline in oil production of 41.2 MBbl and gas production of 16.1 MMcf (or, 2.7 MBOE) compared to the 2012 six month period. Drilling of the QQ25 well resulted in the shut-in of the QQ24 well for five weeks during the first quarter resulting in a decrease in production of 27.0 MMcf (or, 4.5 MBOE) for gas compared to the 2012 six month period. Additional shut-ins or curtailments in production in Grand Bay Field were due to work associated with infrastructure improvements, including flow line testing and repairs and down time on compressors causing gas lift interruptions. Residual curtailments caused by the lingering effects of Hurricane Isaac also effected production during the first quarter of 2013. The decreases in production were partially offset by new wells that came on production over the last 3 quarters of 2012 and the first half of 2013. At quarter end the residual curtailments associated with Hurricane Isaac had been resolved. However, the curtailments related to gas lift and third party handling issues in Main Pass 25 field persisted at June 30, 2013 and have only recently 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 revenue for the quarter ended June 30, 2013 decreased to $82,466 from $364,467 in the 2012 quarter. For the six months ended June 30, 2013, other revenue decreased to $346,349 from $1,290,096 for the 2012 period. The decrease in other revenue was principally as a result of the one-time nature of lawsuit settlements, totaling $604,591, in the 2012 period and decreases in production handling fees and a net profits interest during the 2013 period.

Operating Expenses

Operating expenses decreased by 7.4% to $17.0 million for the quarter ended June 30, 2013 from $18.4 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
	June 30, 2013				June 30, 2012
	Total		Per Boe		Total		Per Boe
Lease operating expense	$	5,200,113	$	23.06	$	4,709,122	$	14.62
Workover expense		1,167,870		5.18		2,067,833		6.42
Exploration expense		115,687		0.51		98,290		0.30
Loss on plugging and abandonment		-		-		856,679		2.66
Dry hole costs		-		-		3,479		0.01
Depreciation, depletion and amortization		5,662,542		25.11		5,575,388		17.31
Accretion expense		638,097		2.83		555,504		1.72
General and administrative		2,335,208		10.36		2,324,182		7.22
Severance taxes		1,901,558		8.43		2,192,246		6.81
	$	17,021,075	$	75.48	$	18,382,723	$	57.07

Operating expenses decreased by 11.2% to $32.1 million for the six months ended June 30, 2013 from $36.2 million in the 2012 period. The following table sets forth the components of operating expenses for the 2013 and 2012 periods:


	Six Months Ended				Six Months Ended
	June 30, 2013				June 30, 2012
	Total		Per Boe		Total		Per Boe
Lease operating expense	$	9,803,154	$	21.49	$	9,331,202	$	16.19
Workover expense		1,429,132		3.14		3,539,301		6.14
Exploration expense		283,971		0.62		155,686		0.27
Loss on plugging and abandonment		-		-		2,468,969		4.29
Dry hole costs		-		-		93,353		0.16
Depreciation, depletion and amortization		10,871,036		23.83		10,512,540		18.24
Accretion expense		1,276,194		2.80		1,111,008		1.93
General and administrative		4,438,742		9.73		5,070,665		8.80
Severance taxes		3,992,612		8.75		3,873,125		6.72
	$	32,094,841	$	70.36	$	36,155,849	$	62.74

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

Lease Operating Expense

Lease operating expenses for the quarter ended June 30, 2013 increased 10.4% to $5.2 million from $4.7 million in the 2012 quarter and, on a per BOE basis, increased 57.7% to $23.06 per BOE from $14.62 per BOE, in the 2012 quarter. Lease operating expenses for the six months ended June 30, 2013 increased 5.1% to $9.8 million from $9.3 million in the 2012 period and on a per BOE basis, increased 32.7% to $21.49 per BOE from $16.19 per BOE in the 2012 period. The increase in lease operating expense for the three and six month periods was primarily due the nonrecurring cost of a barge removal in the Little Bay Field totaling $0.4 million.

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 quarter and six month period was primarily attributable to the decreases in production volumes and the fixed nature of certain lease operating expenses.

Workover Expense

Workover expense for the quarter ended June 30, 2013 decreased to $1,167,870 from $2,067,833 in the 2012 quarter and decreased to $1,429,132 from $3,539,301 for the six months ended June 30, 2013 from the 2012 period. The change in workover expense was attributable to a decrease in the number of workovers completed during 2013 quarter and period as compared to 2012.

Exploration Expense

Exploration expense for the quarter ended June 30, 2013 increased to $115,687 from $98,290 in the 2012 quarter. Exploration expense for the six months ended June 30, 2013 increased to $283,971 from $155,686 in the 2012 period. 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 quarter and six months ended June 30, 2012 totaled $856,679 and $2,468,969, respectively, 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 June 30, 2013 increased 1.6% to $5,662,542 from $5,575,388 in the 2012 quarter and increased to $25.11 per BOE from $17.31 per BOE in the 2012 quarter. Depreciation, depletion and amortization for the six months ended June 30, 2013 increased 3.4% to $10,871,036 from $10,512,540 in the 2012 period and increased to $23.83 per BOE from $18.24 per BOE in the 2012 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 increase in DD&A expense and DD&A expense per BOE, during the 2013 periods 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 June 30, 2013 as compared to the 2012 quarter. Accretion expense relating to our asset retirement obligations increased to $1,276,194 from $1,111,008 for the six months ended June 30, 2013 as compared to the 2012 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

General and administrative (“G&A”) expense for the quarter ended June 30, 2013 remained essentially flat at $2,335,208 as compared to $2,324,182 in the 2012 quarter, but was 43.5% higher on a per BOE basis. For the six months ended June 30, 2013, general and administrative expense decreased by 12.5% to $4,438,742 from $5,070,665 in the 2012 period. The decrease in G&A expense for the six month period was primarily attributable to decreases in head count (reducing salary, wages and benefits approximately $204,000) and a decrease in stock based compensation for the quarter (down approximately $299,000). During and, subsequent to, the second quarter of 2013 we added personnel and do not expect the decrease in G&A expense due to reduced head count to be permanent.

Severance Taxes

Severance taxes for the quarter ended June 30, 2013 decreased to $1,901,558 from $2,192,246 in the 2012 quarter. For the six months ended June 30, 2013, severance taxes increased to $3,992,612 from $3,873,125 for the 2012 period. The increase was primarily attributable a reduced number of inactive wells eligible for certain Louisiana severance tax exemptions, partially offset by reduced revenues.

Other Income (Expense), Net

Net other expense increased to $5.3 million in for the quarter ended June 30, 2013 from $4.3 million for the 2012 quarter. For the six months ended June 30, 2013, other expense increased to $10.5 million from $8.7 million in the 2012 period.

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. The decrease in reorganization expenses was attributable to our exit from bankruptcy in May 2010.

Income Tax Benefit

For the quarter ended June 30, 2013 we recorded an income tax benefit of $1,059,382 compared to $569,909 in expense during the 2012 quarter. For the six months ended June 30, 2013 we recorded an income tax benefit of $1,513,532 compared to $165,834 in the 2012 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 payment of interest and repayment of debt.

Since 2009, we have funded operations, including all development and related activities, 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.

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 through the second 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 June 30, 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 from potential joint venture partners or 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, in order to further supplement our liquidity and increase our operating flexibility, we continue to pursue efforts to secure 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 $30.2 million and working capital of $18.0 million at June 30, 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, including lease bonus and first year rentals on our new Gulf of Mexico leases. The decrease in our working capital was primarily attributable to utilization of cash to fund our development program and Gulf of Mexico lease acquisition.

Operations provided cash flow of $7.9 million for the six months ended June 30, 2013 as compared to providing $21.0 million for the six months ended June 30, 2012. The change in operating cash flows during 2013 was principally attributable to reduced profitability resulting from lower production volumes and changes in our operating assets and liabilities.

Investing activities used cash totaling $9.5 million during the six months ended June 30, 2013, including $1.1 million of cash used to pay lease bonuses and first year rentals on our new Gulf of Mexico leases, as compared to cash used in investing of $25.1 million during the six months ended June 30, 2012. We incurred $12.2 million and $28.9 million for oil and gas development activities for the six months ended June 30, 2013 and 2012, respectively.

Financing activities used cash flows of $0.5 million during the six months ended June 30, 2013 as compared to $21.9 million provided during the six months ended June 30, 2012. Cash flows provided by financing activities during the 2012 period primarily related to an equity offering and funds received for the exercise of common stock options and warrants.

Debt and Non-Current Liabilities

At June 30, 2013, we had $150.6 million of indebtedness outstanding (reflecting a $1.9 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 June 30, 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 six months ended June 30, 2013 was $12.2 million relating primarily to development of our oil and gas properties ($6.2 million), acquisition of Gulf of Mexico Shelf acreage ($1.4 million), 12 recompletions ($1.9 million) and investments in multiple infrastructure projects ($2.7 million). Included in the recompletions is $1.2 million relating to our tubing replacement program.

As of July 1, 2013, we anticipate that our capital budget for the balance of 2013, including drilling our Rocky and Zeke prospects, will be approximately $12.8 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 June 30, 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 June 30, 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	92,000
Fixed Price Swap	April 2013	March 2014	$	109.20	114,000
					206,000

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 Income (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 June 30, 2013, we recorded an unrealized gain on commodity derivatives of $716,222 in current earnings and an unrealized gain on commodity derivatives of $696,969 in accumulated other comprehensive income (loss). For the six months ended June 30, 2013, we recorded an unrealized gain on commodity derivatives of $882,731 in current earnings and an unrealized gain on commodity derivatives of $858,729 in accumulated other comprehensive income (loss).

At June 30, 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 June 30, 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 June 30, 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 June 30, 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: August 9, 2013
	By:	/s/ Thomas Cooke
		Thomas Cooke
		Chief Executive Officer

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