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 September 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.)

3 Riverway, Suite 1810, Houston, Texas 77056

(Address of principal executive offices)(Zip Code)

(713) 458-1560

(Registrant's telephone number, including area code)

7500 San Felipe, Suite 675, Houston, Texas 77063

(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 November 8, 2013, we had 30,946,601 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 September 30, 2013 and December 31, 2012	3
	Consolidated Statements of Operations and Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2013 and 2012	4
	Consolidated Statements of Cash Flows for the nine months ended September 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		14
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		23
ITEM 4. Controls and Procedures		23

PART II OTHER INFORMATION		24

ITEM 6. Exhibits		24

PART I - FINANCIAL INFORMATION

ITEM 1

Financial Statements


SARATOGA RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)

	September 30,		December 31,
	2013		2012
ASSETS

Current assets:
Cash and cash equivalents	$	9,587,978	$	32,302,313
Accounts receivable		8,225,689		12,430,158
Prepaid expenses and other		1,667,999		1,268,971
Derivative asset		311,697		-
Other current asset		150,000		150,000
Total current assets		19,943,363		46,151,442

Property and equipment:
Oil and gas properties - proved (successful efforts method)		289,501,591		260,916,084
Other		889,388		795,138
		290,390,979		261,711,222
Less: Accumulated depreciation, depletion and amortization		(99,609,801)		(81,640,272)
Total property and equipment, net		190,781,178		180,070,950

Deferred tax asset, net		12,794,728		8,499,575
Other assets, net		20,074,947		19,929,394
Total assets	$	243,594,216	$	254,651,361

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	7,884,141	$	7,259,244
Revenue and severance tax payable		4,646,023		6,129,867
Accrued liabilities		6,641,646		10,787,044
Derivative liabilities – short term		-		171,086
Short-term notes payable		846,280		373,360
Asset retirement obligation – current		-		256,200
Total current liabilities		20,018,090		24,976,801

Long-term liabilities:
Asset retirement obligation		18,466,028		16,815,736
Long-term debt, net of unamortized discount of $1,737,397 and $2,104,106, respectively		150,762,603		150,395,894
Total long-term liabilities		169,228,631		167,211,630

Commitment and contingencies (see notes)

Stockholders' equity:
Common stock, $0.001 par value; 100,000,000 shares authorized 30,946,601 and 30,905,101 shares issued and outstanding at September 30, 2013 and December 31, 2012, respectively		30,947		30,905
Additional paid-in capital		77,933,631		77,140,451
Accumulated other comprehensive income (loss)		21,029		(171,086)
Retained deficit		(23,638,112)		(14,537,340)

Total stockholders' equity		54,347,495		62,462,930

Total liabilities and stockholders' equity	$	243,594,216	$	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 September 30,				For the Nine Months Ended September 30,
	2013		2012		2013		2012
Revenues:
Oil and gas revenues	$	17,195,776	$	16,454,125	$	54,185,434	$	59,588,443
Oil and gas hedging		(717,378)		(6,490)		(226,541)		(6,490)
Other revenues		3,466		269,810		249,815		1,467,403
Total revenues		16,481,864		16,717,445		54,208,708		61,049,356

Operating Expense:
Lease operating expense		5,490,268		4,622,010		15,293,422		13,860,709
Workover expense		848,094		306,745		2,277,226		3,846,046
Exploration expense		462,994		213,733		746,965		369,419
Loss on plugging and abandonment		727,039		-		727,039		2,468,969
Dry hole costs		-		-		-		93,353
Depreciation, depletion and amortization		4,919,418		3,658,002		15,790,454		14,170,532
Impairment expense		2,179,075		44,276		2,179,075		44,276
Accretion expense		638,097		555,504		1,914,291		1,666,512
General and administrative		2,365,501		1,971,634		6,804,243		7,042,299
Severance taxes		1,900,292		1,502,134		5,892,904		5,375,259
Total operating expenses		19,530,778		12,874,038		51,625,619		48,937,374

Operating income (loss)		(3,048,914)		3,843,407		2,583,089		12,111,982

Other income (expense):
Interest income		8,548		11,204		27,008		20,046
Interest expense		(5,368,376)		(4,334,389)		(15,905,464)		(13,058,178)
Total other expense		(5,359,828)		(4,323,185)		(15,878,456)		(13,038,132)

Net loss before reorganization expense and income taxes		(8,408,742)		(479,778)		(13,295,367)		(926,150)

Reorganization expense		-		43,287		2,319		121,528

Net loss before income taxes		(8,408,742)		(523,065)		(13,297,686)		(1,047,678)

Income tax expense (benefit)		(2,683,382)		(48,062)		(4,196,914)		(213,896)

Net loss	$	(5,725,360)	$	(475,003)	$	(9,100,772)	$	(833,782)

Other comprehensive income (loss)
Unrealized gain (loss) on derivative instruments		(666,614)		(182,569)		192,115		(182,569)
Total comprehensive income (loss)	$	(6,391,974)	$	(657,572)	$	(8,908,657)	$	(1,016,351)

Net loss per share:
Basic	$	(0.19)	$	(0.02)	$	(0.29)	$	(0.03)
Diluted	$	(0.19)	$	(0.02)	$	(0.29)	$	(0.03)

Weighted average number of common shares outstanding:
Basic		30,945,242		30,808,775		30,927,802		28,867,424
Diluted		30,945,242		30,808,775		30,927,802		28,867,424

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


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

	For the Nine Months Ended
	September 30,
	2013		2012
Cash flows from operating activities:
Net loss	$	(9,100,772)	$	(833,782)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		15,790,454		14,170,532
Impairment expense		2,179,075		44,276
Accretion expense		1,914,291		1,666,512
Amortization of debt issuance costs		1,006,240		675,649
Amortization of debt discount		366,709		265,328
Dry hole costs		-		93,353
Stock-based compensation		769,427		1,040,127
Loss on plugging and abandonment		727,039		2,468,969
Deferred tax benefit		(4,295,153)		(400,666)
Unrealized gain on hedges		(290,668)		6,490
Changes in operating assets and liabilities:
Accounts receivable		4,204,469		4,235,306
Prepaids and other		1,124,277		894,459
Accounts payable		(3,619,119)		(1,806,687)
Revenue and severance tax payable		(1,483,844)		(1,542,344)
Payments to settle asset retirement obligations		(1,247,239)		(586,769)
Accrued liabilities		(4,581,395)		(4,720,786)
Net cash provided by operating activities		3,463,791		15,669,967

Cash flows from investing activities:
Additions to oil and gas property		(23,905,494)		(46,191,709)
Additions to other property and equipment		(94,250)		(55,138)
Proceeds from cash collateral		-		2,021,628
Other assets		(1,151,793)		(1,089,153)
Net cash used in investing activities		(25,151,537)		(45,314,372)

Cash flows from financing activities:
Proceeds from issuance of common stock		23,795		23,153,910
Repayment of short-term notes payable		(1,050,384)		(1,096,079)
Net cash (used in) provided by financing activities		(1,026,589)		22,057,831

Net increase (decrease) in cash and cash equivalents		(22,714,335)		(7,586,574)
Cash and cash equivalents - beginning of period		32,302,313		15,874,680
Cash and cash equivalents - end of period	$	9,587,978	$	8,288,106

Supplemental disclosures of cash flow information:
Cash paid for income taxes	$	98,239	$	186,770
Cash paid for interest		19,082,534		7,987,234

Non-cash investing and financing activities:
Unrealized gain on derivative instruments	$	192,115	$	-
Accounts payable for oil and gas additions		4,244,015		6,075,835
Accrued liabilities for oil and gas additions		435,998		1,708,702
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

September 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 $9.3 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 – OIL AND GAS PROPERTIES

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

During three months ended September 30, 2013, we recognized $2,179,075 in impairment expense. The impairment related to the loss of a lease in Louisiana. During the three months ended September 30, 2012 we recognized $44,276 in impairment expense. The impairment was a result of one of three producing wells in a field becoming fully depleted during the quarter.

NOTE 3 – 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 4 – “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 September 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 September 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	46,000
Fixed Price Swap	April 2013	March 2014	$	109.20	83,250
Fixed Price Swap	October 2013	December 2013	$	107.43	23,000
Fixed Price Swap	January 2014	March 2014	$	105.18	45,000
					197,250

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


	September 30,		December 31,
Description	2013		2012
Current Assets:
Commodity derivatives	$	311,697	$	-
	$	311,697	$	-
Current liabilities:
Commodity derivatives	$	-	$	171,086
	$	-	$	171,086

NOTE 4 – FAIR VALUE MEASUREMENTS

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

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

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

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

The following table presents the Company’s assets and liabilities recognized in the balance sheet and measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012:


	Level 1		Level 2		Level 3		Total
September 30, 2013
Assets:
Commodity derivatives	$	-	$	311,697	$	-	$	311,697
	$	-	$	311,697	$	-	$	311,697

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 5 – OTHER ASSETS

Other assets consist of the following:


	September 30,		December 31,
	2013		2012
Site specific trust accounts - P&A escrow	$	5,515,428	$	5,279,084
Debt issuance cost, net		4,767,394		5,728,755
Restricted cash – P&A bond		9,738,367		8,873,497
Other		53,758		48,058
	$	20,074,947	$	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 9 – “Asset Retirement Obligations”.

Debt Issuance Costs, Net

The Company capitalizes certain debt issuance costs and amortizes those costs as additional interest expense over the lives of the associated debt. Net debt issuance costs at September 30, 2013 and December 31, 2012 reflect the issuance of the 2016 Notes in December 2012 and July 2011. See Note 10 – “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 6 – STOCK-BASED COMPENSATION EXPENSE

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

Compensation 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 management 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. 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 ½ 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.

In July 2013, the Company’s management approved a stock option grant to purchase an aggregate of 60,000 shares of common stock to a non-executive employee. The options are exercisable for a term of seven years at price of $1.53 per share and vest 1/3 on each of the first three grant date anniversaries. The grant date value of the options was $90,600. The options were valued using the Black-Scholes model with the following assumptions: 231% volatility; 4.5 year estimated life; zero dividends; 1.18% discount rate; and, quoted stock price and exercise price of $1.53.

In August 2013, the Company’s management approved a stock option grant to purchase an aggregate of 90,000 shares of common stock to a non-executive employee. The options are exercisable for a term of seven years at price of $1.72 per share and vest 1/3 on each of the first three grant date anniversaries. The grant date value of the options was $150,300. The options were valued using the Black-Scholes model with the following assumptions: 204% volatility; 4.5 year estimated life; zero dividends; 1.18% discount rate; and, quoted stock price and exercise price of $1.72.

The following table summarizes information about stock option activity and related information for the nine months ended September 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		830,000		2.60		1.32	5.5		132,000
Exercised		(6,500)		1.53		1.53	-		-
Forfeited		-		-		-	-		-
Outstanding at September 30, 2013		1,607,500	$	3.13	$	2.46	5.6	$	278,575
Exercisable at September 30, 2013		742,500	$	3.35	$	3.13	5.8	$	157,075

(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 September 30, 2013, the last reported sales price of our common stock on the NYSE MKT was $2.38 per share.

Share-Based Compensation Expense

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Share-based compensation expense included in reported net income	$	233,132	$	204,833	$	769,427	$	1,040,127
Basic earnings per share effect of share-based compensation expense	$	(0.01)	$	(0.01)	$	(0.02)	$	(0.04)

As of September 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 7 – 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.

In July 2013, the Company received gross proceeds of $8,750 for 5,000 stock warrants exercised at $1.75 a share.

Warrant Activity

The following table summarizes information about stock warrant activity and related information for the nine months ended September 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		(35,000)		0.40		0.22	-		-
Forfeited		(390,630)		5.00		2.69	-		-
Outstanding at September 30, 2013		146,998	$	6.64	$	5.33	1.6	$	-
Exercisable at September 30, 2013		146,998	$	6.64	$	5.33	1.6	$	-

(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 September 30, 2013, the last reported sales price of our common stock on the NYSE MKT was $2.38 per share.

NOTE 8 – 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 September 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	$	(5,725,360)	30,945,242	$	(0.19)	$	(475,003)	30,808,775	$	(0.03)
Effect of Dilutive Securities:
Stock options and other			-					-
Diluted:
Loss attributable to common stock, including assumed conversions	$	(5,725,360)	30,945,242	$	(0.19)	$	(475,003)	30,808,775	$	(0.03)


	For the Nine Months Ended September 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	$	(9,100,772)	30,927,802	$	(0.29)	$	(833,782)	28,867,424	$	(0.03)
Effect of Dilutive Securities:
Stock options and other			-					-
Diluted:
Loss attributable to common stock, including assumed conversions	$	(9,100,772)	30,927,802	$	(0.29)	$	(833,782)	28,867,424	$	(0.03)

NOTE 9 – ASSET RETIREMENT OBLIGATIONS

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

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		1,914,291
Additions		-
Revisions		-
Settlements		(520,199)
Balance at September 30, 2013	$	18,466,028

NOTE 10 – DEBT

Long-term debt consists of the following:


	September 30,		December 31,
	2013		2012
12.5% Senior Secured Notes due 2016	$	152,500,000	$	152,500,000
Less unamortized discount		1,737,397		2,104,106
	$	150,762,603	$	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 11 – COMMITMENTS AND CONTINGENCIES

Contingencies

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

The Company has employment agreements with its Chairman and Chief Executive Officer, Thomas Cooke, and its President, Andrew 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 employment agreements reflect the following principal terms of employment of Messrs. Cooke and Clifford: (i) the annual base salary of Messrs. Cooke and Clifford is $317,200, effective July 1, 2013 and increases by 4% on July 1 of each succeeding year; (ii) the automobile allowance of Messrs. Cooke and Clifford either provides a Company vehicle or pays a monthly automobile allowance, which allowance is $950 per month; additionally, beyond repair and maintenance costs the automobile allowance covers all costs of operating a vehicle; (iii) the expense reimbursement provisions provide 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) the agreements provide travel pay in the amount of $200 per day to 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 12 – SUBSEQUENT EVENTS

In October 2013, the Company received $620,500 in proceeds for the sale of crude oil call options. The options provided for a premium of $6.80 per Bbl for a total of 91,250 Bbls. The call options cover 250 Bbls per day beginning on April 1, 2014 and ending on March 31, 2015 at an option strike price of $103.30. The short crude oil call option, when combined with the Company’s long production position, represents a “covered call”, and creates a $103.30 per Bbl ceiling on the price to be received during the covered period for the related production.

ITEM 2

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

Forward-Looking Information

This Form 10-Q quarterly report of Saratoga Resources, Inc. (the “Company”) for the nine months ended September 30, 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 lease holdings totaled 51,890 acres at September 30, 2013, comprised of our principal producing properties covering 32,076 acres in the transitional coastline and protected in-bay environment on parish and state leases of south Louisiana and an additional 19,814 acres of leases in the shallow Gulf of Mexico shelf.

At September 30, 2013, we operated or had interests in 94 producing wells and our principal properties covered approximately 51,890 gross/net acres, 31,031 acres, or 60% of the total, of which were held by production without near-term lease expirations, across 10 fields in the transitional coastline and protected in-bay environment on parish and state leases in south Louisiana as well as in the shallow Gulf of Mexico. We own approximately 100% working interest in all our properties, with the only exception being a single well where we have an overriding royalty interest. Our net revenue interests in our properties range from 69% to 82%, with our average net revenue interest on a net acreage leasehold basis being approximately 75%. We operate over 99% 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 nine months ended September 30, 2013, we completed the “Buddy” well in Grand Bay Field and drilled and completed the “Roux Toux” well in Main Pass 47 Field, and the “Rocky” and “Zeke” wells in Breton Sound 32 field with the Rocky and Zeke wells being drilled and completed during the most recent quarter.

The Rocky well targeted an elongated ridge, offsetting the SL 1227 #21 and #22 wells in the 5,800’ sand, which is the main producing reservoir in the Breton Sound 32 field. A seventy-degree pilot hole was drilled followed by a sidetrack with a 750’ lateral completion. This well was our first horizontal well. The Rocky well had an IP rate of gross 600 BOPD, 120 MCFPD on a 16/64” choke with 650# FTP (net 508 BOEPD).

The Zeke also targeted the same 5,800’ sand but in a separate structure to the south-east and was completed as a high angle (82 degrees) directional. The Zeke well also established a previously unbooked uphole recompletion opportunity in the overlying 5,750’ sand, which also produces within the field. The Zeke well had an IP rate of gross 312 BOPD, 89 MCFPD on a 38/64” choke with 480# FTP (net 268 BOEPD).

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

Recompletion and Workover Program. During the nine months ended September 30, 2013, we invested $4.9 million in 18 recompletions, 14 of which were successfully completed and 1 of which was still in progress at the end of the period, and an additional $2.3 million on 9 workovers, all of which were successfully completed during the period.

Infrastructure Program. During the nine months ended September 30, 2013, we invested $4.9 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 half 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 are continuing efforts to find joint venture partners for our Gulf of Mexico prospects, as well as some of the Grand Bay deep prospects.

For the nine months ended September 30, 2013, we had approximately 94 gross (93 net) wells in production.

Leasing Activity

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 we paid 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 September 30, 2013. Annual rentals on the leases total $138,698 during the primary term.

Louisiana State Leases. In September 2013, we acquired an additional 857.96 acres under two Louisiana state leases in Breton Sound 18, 19 and 32 fields. The leasehold acreage is contiguous with our existing lease holdings in Breton Sound 18 and 32 fields, is close to existing facilities and pipeline infrastructure and in water depths of less than 20 feet. The leases have a primary term of three years and are subject to a 21% royalty burden. Lease bonuses on the acreage totaled $225,620. Annual rentals on the leases total $94,755 during the primary term.

Compensation

During the nine months ended September 30, 2013, we granted an aggregate of 830,000 stock options to various employees, officers and directors at exercise prices ranging from $1.53 to $3.00 per share.

We recorded $233,132 and $769,427 of compensation charges that are reflected in general and administrative expense for the three and nine months ended September 30, 2013 and are attributable to equity grants during 2013 and prior years.

As of September 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.

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.

Share Issuances for Cash

During the nine months ended September 30, 2013, we sold 6,500 shares of common stock for $9,945 pursuant to the exercise of outstanding stock options and 35,000 shares for $13,850 pursuant to the exercise of outstanding stock warrants.

Hedging Activities

As of September 30, 2013, we had in place fixed price swaps covering an aggregate of 197,250 barrels of oil over the period beginning October 1, 2013 and ending March 31, 2014, at prices ranging from $105.18 to $109.20 per barrel.

In October 2013, we received $620,500 in proceeds for the sale of crude oil call options. The options provided for a premium of $6.80 per Bbl for a total of 91,250 Bbls. The call options cover 250 Bbls per day beginning on April 1, 2014 and ending on March 31, 2015 at an option strike price of $103.30. The short crude oil call option, when combined with the Company’s long production position, represents a “covered call”, and creates a $103.30 per Bbl ceiling on the price to be received during the covered period for the related production.

Results of Operations

Oil and Gas Revenue

Oil and gas revenue for the quarter ended September 30, 2013 increased by 4.5% to $17.2 million from $16.5 million in the 2012 quarter. For the nine month period ended September 30, 2013 oil and gas revenue decreased by 9.1% to $54.2 million from $59.6 million in the 2012 period.

For the quarter ended September 30, 2013, the increase in revenue was attributable to a 15.1% increase in oil revenues on a 9.2% increase in oil production volumes and a 5.4% increase in average oil prices realized partially offset by a 62.2% decline in gas revenues on a 66.3% decrease in gas production volumes partially offset by a 12.6% increase in average prices realized, each as compared to the 2012 quarter. For the nine months ended September 30, 2013, the decrease in revenue was attributable to a 6.1% decline in oil revenues on a 4.7% decrease in oil production volumes and a 1.5% decrease in average oil prices realized and a 32.0% decline in gas revenues on a 45.3% decrease in gas production volumes partially offset by a 24.2% 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 nine months ended September 30, 2013 and 2012:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Revenues
Oil	$	16,345,209	$	14,206,497	$	49,566,017	$	52,790,300
Gas		850,567		2,247,628		4,619,417		6,798,143
Total oil and gas revenues	$	17,195,776	$	16,454,125	$	54,185,434	$	59,588,443

Production
Oil (Bbls)		150,543		137,913		461,066		483,808
Gas (Mcf)		186,798		555,062		1,060,525		1,937,399
Total production (Boe)		181,676		230,423		637,820		806,708

Average sales price
Oil (per Bbl)	$	108.58	$	103.01	$	107.51	$	109.12
Gas (per Mcf)		4.56		4.05		4.36		3.51
Total average sales price (per Boe)	$	94.65	$	71.41	$	84.96	$	73.87

The decrease in gas production during the quarter and nine month period, outside of natural reserve declines, was primarily due to reductions in Main Pass 25, Main Pass 46, Main Pass 52, Grand Bay and Breton Sound 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 55.0 MMcf (or, 9.2 MBOE) compared to the 2012 nine month period . These issues were resolved during the third quarter and gas production was back to 2012 levels for the quarter. In Main Pass 46 Field, the Catina well suffered gradually worsening flow line restrictions and was shut-in for most of August 2013 for repair. As a result, gas production from Catina was down 10.2 MMcf and 46.2 MMcf (or, 1.7 MBOE and 7.7 MBOE) for the quarter and nine month period, respectively, as compared to 2012. The SL 20034 #1 well became fully depleted in the 6100’ sand resulting in a decrease of 29.7 MMcf and 184.5 MMcf (or, 5.0 and 30.8 MBOE) for the quarter and nine month period, respectively, as compared to 2012. This well was recently recompleted into a new producing zone. In Main Pass 52 Field, natural declines and depleted production zones resulted in a decrease in gas production of 53.1 MMcf and 153.5 MMcf (or, 8.9 MBOE and 25.6 MBOE) for the quarter and nine month period, respectively, as compared to 2012. In Grand Bay Field, shut-ins due to drilling of our QQ25 well, work associated with infrastructure improvements, mechanical issues, gas lift interruptions, flow line testing and repair and down time on compressors were principal drivers of a decline in gas production of 258.9 MMcf and 320.7 MMcf (or, 43.2 MBOE and 320.7 MBOE) for the quarter and nine month period, respectively, as compared to 2012. In the Breton Sound Fields, gas production is down 98.5 MMcf (or, 16.4 MBOE) for the nine month period, as compared to 2012, due to natural declines in the 2012 principal producing wells, but has increased by 33.0 MMcf (or, 5.5 MBOE) for the quarter, as compared to 2012, due to the completion of the North Tiger well in the fourth quarter of 2012.

Oil production was down 22.7 MBbl for the nine month period as compared to 2012. This decrease was primarily due to the flow line problems experienced in the Main Pass 46 Field which resulted in a decrease of 34.7 MBbl. In addition, shut-ins in the Main Pass 25 Field caused by construction projects resulted in a decrease of 26.3 MBbl for the nine month period as compared to 2012. These decreases were partially offset by the fact the North Tiger well was completed in the fourth quarter of 2012. For the quarter, oil production increased by 12.6 MBbl, as compared to 2012, primarily due to the completion of the Rocky and Zeke wells during the third quarter.

The increase in realized hydrocarbon prices reflects a general strengthening of both crude oil and natural gas prices. We continued to realize a premium pricing on both our crude oil and natural gas production.

Following quarter-end, in early October 2013, we were substantially 100% shut-in for a day as pipeline operators and other third party service providers temporarily ceased operations in the Gulf of Mexico as a precaution prior to the arrival of Tropical Storm Karen. No material damage was sustained as a result of the storm but it took five days to bring our properties back to full production. As a result, we will experience some deferral of production and associated revenues during the fourth quarter.

Other Revenues

Other revenue for the quarter ended September 30, 2013 decreased to $3,466 from $269,810 in the 2012 quarter. For the nine months ended September 30, 2013, other revenue decreased to $249,815 from $1,467,403 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 increased by 51.7% to $19.5 million for the quarter ended September 30, 2013 from $12.9 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
	September 30, 2013				September 30, 2012
	Total		Per Boe		Total		Per Boe
Lease operating expense	$	5,490,268	$	30.22	$	4,622,010	$	20.06
Workover expense		848,094		4.67		306,745		1.33
Exploration expense		462,994		2.55		213,733		0.93
Loss on plugging and abandonment		727,039		4.00		-		-
Depreciation, depletion and amortization		4,919,418		27.08		3,658,002		15.87
Impairment expense		2,179,075		11.99		44,276		0.19
Accretion expense		638,097		3.51		555,504		2.41
General and administrative		2,365,501		13.02		1,971,634		8.56
Severance taxes		1,900,292		10.46		1,502,134		6.52
	$	19,530,778	$	107.50	$	12,874,038	$	55.87

Operating expenses increased by 5.5% to $51.6 million for the nine months ended September 30, 2013 from $48.9 million in the 2012 period. The following table sets forth the components of operating expenses for the 2013 and 2012 periods:


	Nine Months Ended				Nine Months Ended
	September 30, 2013				September 30, 2012
	Total		Per Boe		Total		Per Boe
Lease operating expense	$	15,293,422	$	23.97	$	13,860,709	$	17.18
Workover expense		2,277,226		3.57		3,846,046		4.77
Exploration expense		746,965		1.17		369,419		0.46
Loss on plugging and abandonment		727,039		1.14		2,468,969		3.06
Dry hole costs		-		-		93,353		0.11
Depreciation, depletion and amortization		15,790,454		24.76		14,170,532		17.57
Impairment expense		2,179,075		3.42		44,276		0.05
Accretion expense		1,914,291		3.00		1,666,512		2.07
General and administrative		6,804,243		10.67		7,042,299		8.73
Severance taxes		5,892,904		9.24		5,375,259		6.66
	$	51,625,619	$	80.94	$	48,937,374	$	60.66

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

Lease Operating Expense

Lease operating expenses for the quarter ended September 30, 2013 increased 18.9% to $5.5 million from $4.6 million in the 2012 quarter and, on a per BOE basis, increased 50.6% to $30.22 per BOE from $20.06 per BOE, in the 2012 quarter. Lease operating expenses for the nine months ended September 30, 2013 increased 10.4% to $15.3 million from $13.9 million in the 2012 period and on a per BOE basis, increased 39.6% to $23.97 per BOE from $17.18 per BOE in the 2012 period. The increase in lease operating expense for the three and nine month periods was primarily due to the nonrecurring cost of a barge removal in the Little Bay Field totaling $0.4 million and the cost of chemically treating and cleaning our sales lines and flow lines totaling $0.6 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 nine 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 September 30, 2013 increased to $848,094 from $306,745 in the 2012 quarter and decreased to $2,277,226 from $3,846,046 for the nine months ended September 30, 2013 from the 2012 period. The change in workover expense was attributable to variances in the number of workovers undertaken during the respective periods.

Exploration Expense

Exploration expense for the quarter ended September 30, 2013 increased to $462,994 from $213,733 in the 2012 quarter. Exploration expense for the nine months ended September 30, 2013 increased to $746,965 from $369,419 in the 2012 period. The increase in exploration expenses principally relate to increased delay rentals and filed studies, including $138,698 relating to our Gulf of Mexico shelf acreage incurred during the 2013 quarter, and increased investment in field studies related to Grand Bay Field, in particular seismic attribute and AVO analysis relating to the Grand Bay deep prospects.

Loss on plugging and abandonment

Loss on plugging and abandonment for the quarter and nine months ended September 30, 2013 totaled $727,039 due to cost of plugging and abandoning a well in Vermilion Bay 16 field that exceeded those estimated in our calculation of asset retirement obligation liabilities. This well was a high pressure well which we discovered had been completed with a kill string resulting in the need for additional plugs and tubing cuts. Accordingly, the actual costs incurred in plugging and abandoning this well was substantially higher than we estimated and would expect to incur in future plugging operations.

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

Depreciation, Depletion and Amortization (DD&A)

Depreciation, depletion and amortization for the quarter ended September 30, 2013 increased 34.5% to $4,919,418 from $3,658,002 in the 2012 quarter and increased to $27.08 per BOE from $15.87 per BOE in the 2012 quarter. Depreciation, depletion and amortization for the nine months ended September 30, 2013 increased 11.4% to $15,790,454 from $14,170,532 in the 2012 period and increased to $24.76 per BOE from $17.57 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 during the current year and relating to work in progress at the end of 2012 that was placed in service during the current year.

Impairment Expense

Impairment expense of $2,179,075 was recorded during the 2013 quarter due to the loss of the lease at our Little Bay Field when production levels fell below commercial levels.

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

Accretion expense

Accretion expense relating to our asset retirement obligations increased to $638,097 from $555,504 for the quarter ended September 30, 2013 as compared to the 2012 quarter. Accretion expense relating to our asset retirement obligations increased to $1,914,291 from $1,666,512 for the nine months ended September 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 September 30, 2013 increased 20.0% to $2,365,501 as compared to $1,971,634 in the 2012 quarter, and increased 52.1% to $13.02 from $8.56 on a per BOE basis. For the nine months ended September 30, 2013, G&A expense decreased by 3.4% to $6,804,243 from $7,042,299 in the 2012 period. The increase in G&A expense for the quarter was primarily due to consulting fees relating to reservoir engineering and an increase in the employee headcount resulting in higher salaries and benefits. The decrease in G&A expense for the nine month period was primarily attributable to a temporary decrease in head count during the first and portions of the second quarter of 2013 and reductions in employee stock compensation and the year-end bonus accrual which were partially offset by the increase in reservoir consulting costs.

Severance Taxes

Severance taxes for the quarter ended September 30, 2013 increased to $1,900,292 from $1,502,134 in the 2012 quarter. For the nine months ended September 30, 2013, severance taxes increased to $5,892,904 from $5,375,259 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 $5.4 million in for the quarter ended September 30, 2013 from $4.3 million for the 2012 quarter. For the nine months ended September 30, 2013, other expense increased to $15.9 million from $13.0 million in the 2012 period.

Interest expense reflects interest incurred on debt under our senior secured notes. 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.

Income Tax Benefit

For the quarter ended September 30, 2013 we recorded an income tax benefit of $2,683,382 compared to $48,062 during the 2012 quarter. For the nine months ended September 30, 2013 we recorded an income tax benefit of $4,196,914 compared to $213,896 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 third 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 on hand at September 30, 2013, together with anticipated operating cash flow, will support current operations over the next twelve months, but will not support development operations at 2013 levels. Accordingly, contingent upon operating results, we may need to secure additional financing to support development activities at those levels or to curtail development activities to levels supported by operating cash flow. 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 September 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.

We plan to seek joint venture partners for our shallow Gulf of Mexico properties, which have a primary lease term of five years and are exploratory in nature.

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 senior 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 senior 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 $9.6 million and a working capital deficit of $0.1 million at September 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 reductions in operating cash flow 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 $3.5 million for the nine months ended September 30, 2013 as compared to providing $15.7 million for the nine months ended September 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 $25.2 million during the nine months ended September 30, 2013, including $1.5 million of cash used to pay lease bonuses, first year rentals and a prospect fee relating to our new Gulf of Mexico leases, as compared to cash used in investing of $45.3 million during the nine months ended September 30, 2012. We incurred $28.6 million and $54.0 million for oil and gas development activities for the nine months ended September 30, 2013 and 2012, respectively.

Financing activities used cash flows of $1.0 million during the nine months ended September 30, 2013 as compared to $22.1 million provided during the nine months ended September 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 September 30, 2013, we had $150.8 million of indebtedness outstanding (reflecting a $1.7 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 September 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 nine months ended September 30, 2013 was $28.6 million relating primarily to development of our oil and gas properties ($17.4 million), acquisition of Gulf of Mexico Shelf acreage ($1.4 million), 18 recompletions ($4.9 million) and investments in multiple infrastructure projects ($4.9 million).

As of October 1, 2013, we anticipate that our capital budget for the balance of 2013 will be approximately $1.7 million, excluding potential acquisitions and capital requirements associated with any joint ventures to develop our deep prospects and Gulf of Mexico shelf acreage. As noted, we have the operational flexibility to react quickly with our capital expenditures to changes in our cash flows from operations. Actual levels of capital expenditures in any year may vary significantly due to many factors, including the extent to which properties are acquired, drilling results, oil and gas prices, industry conditions and the prices and availability of goods and services.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements or guarantees of third party obligations at September 30, 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 September 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	46,000
Fixed Price Swap	April 2013	March 2014	$	109.20	83,250
Fixed Price Swap	October 2013	December 2013	$	107.43	23,000
Fixed Price Swap	January 2014	March 2014	$	105.18	45,000
					197,250

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 September 30, 2013, we recorded an unrealized loss on commodity derivatives of $592,063 in current earnings and an unrealized loss on commodity derivatives of $666,614 in accumulated other comprehensive income (loss). For the nine months ended September 30, 2013, we recorded an unrealized gain on commodity derivatives of $290,668 in current earnings and an unrealized gain on commodity derivatives of $192,115 in accumulated other comprehensive income (loss).

At September 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 September 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 September 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 September 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: November 12, 2013
	By:	/s/ Thomas Cooke
		Thomas Cooke
		Chief Executive Officer

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