Edgar Filing: SARATOGA RESOURCES INC /TX

SARATOGA RESOURCES, INC.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)


x	QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2014


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)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company x

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

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

As of May 12, 2014, 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 March 31, 2014 and December 31,2013	3
	Consolidated Statements of Operations and Other Comprehensive Loss for the three months ended March 31, 2014 and 2013	4
	Consolidated Statements of Cash Flows for the three months ended March 31, 2014 and 2013	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		21
ITEM 4. Controls and Procedures		22

PART II OTHER INFORMATION		22

ITEM 6. Exhibits		22

PART I - FINANCIAL INFORMATION

ITEM 1

Financial Statements

SARATOGA RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31,		December 31,
	2014		2013
ASSETS

Current assets:
Cash and cash equivalents	$	20,371,954	$	32,547,380
Accounts receivable		7,197,809		6,758,572
Prepaid expenses and other		704,184		1,056,350
Other current asset		150,000		150,000
Total current assets		28,423,947		40,512,302

Property and equipment:
Oil and gas properties - proved (successful efforts method)		287,746,605		286,441,663
Other		900,421		892,694
		288,647,026		287,334,357
Less: Accumulated depreciation, depletion and amortization		(103,830,755)		(101,088,696)
Total property and equipment, net		184,816,271		186,245,661

Other assets, net		21,090,083		21,665,830
Total assets	$	234,330,301	$	248,423,793

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	4,600,267	$	5,391,648
Revenue and severance tax payable		3,741,463		3,754,812
Accrued liabilities		5,021,709		9,807,935
Derivative liabilities – short term		447,119		837,758
Short-term notes payable		-		338,512
Total current liabilities		13,810,558		20,130,665

Long-term liabilities:
Asset retirement obligation		13,097,924		12,649,458
Long-term debt, net of unamortized discount of $1,459,889 and $1,603,016, respectively		178,340,111		178,196,984
Derivative liabilities		-		182,174
Total long-term liabilities		191,438,035		191,028,616

Commitment and contingencies (see notes)

Stockholders' equity:
Common stock, $0.001 par value; 100,000,000 shares authorized 30,946,601 shares issued and outstanding at March 31, 2014 and December 31, 2013		30,947		30,947
Additional paid-in capital		78,171,394		78,165,364
Accumulated other comprehensive income (loss)		100,353		-
Retained deficit		(49,220,986)		(40,931,799)

Total stockholders' equity		29,081,708		37,264,512

Total liabilities and stockholders' equity	$	234,330,301	$	248,423,793

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

SARATOGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

(Unaudited)


	For the Three Months Ended
	March 31,
	2014		2013
Revenues:
Oil and gas revenues	$	10,602,991	$	19,261,901
Oil and gas hedging		1,061,123		(648,380)
Other revenues		76,175		119,675

Total revenues		11,740,289		18,733,196

Operating Expense:
Lease operating expense		5,492,815		4,558,833
Workover expense		2,192,186		261,262
Exploration expense		221,352		168,284
Depreciation, depletion and amortization		2,742,059		5,208,494
Accretion expense		448,466		638,097
General and administrative		2,352,570		2,103,534
Severance taxes		500,750		2,091,054

Total operating expenses		13,950,198		15,029,558

Operating income		(2,209,909)		3,703,638

Other income (expense):
Interest income		16,321		6,080
Interest expense		(6,013,533)		(5,222,942)

Total other expense		(5,997,212)		(5,216,862)

Net loss before reorganization expenses and income taxes		(8,207,121)		(1,513,224)

Reorganization expenses		-		2,319

Net loss before income taxes		(8,207,121)		(1,515,543)

Income tax expense (benefit)		82,066		(454,150)

Net loss	$	(8,289,187)	$	(1,061,393)

Other Comprehensive income (loss)
Unrealized gain on derivative instruments		100,353		161,760
Total comprehensive loss	$	(8,188,834)	$	(899,633)

Net loss per share:
Basic	$	(0.27)	$	(0.03)
Diluted	$	(0.27)	$	(0.03)

Weighted average number of common shares outstanding:
Basic		30,946,601		30,911,023
Diluted		30,946,601		30,911,023

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

SARATOGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the Three Months Ended
	March 31,
	2014		2013
Cash flows from operating activities:
Net loss	$	(8,289,187)	$	(1,061,393)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		2,742,059		5,208,494
Accretion expense		448,466		638,097
Amortization of debt issuance costs		589,306		320,870
Amortization of debt discount		143,127		117,918
Stock-based compensation		6,029		163,042
Deferred tax benefit		-		(487,247)
Unrealized gain on hedges		(1,092,960)		(166,509)
Changes in operating assets and liabilities:
Accounts receivable		(439,237)		2,264,153
Prepaids and other		352,166		609,865
Accounts payable		150,078		(1,901,152)
Revenue and severance tax payable		(13,349)		(814,530)
Payments to settle asset retirement obligations		-		(309,832)
Accrued liabilities		(4,118,957)		(4,793,261)
Net cash used in operating activities		(9,522,459)		(211,485)

Cash flows from investing activities:
Additions to oil and gas property		(2,293,169)		(9,290,443)
Additions to other property and equipment		(7,727)		(7,594)
Other assets		(13,559)		(431,845)
Net cash used in investing activities		(2,314,455)		(9,729,882)

Cash flows from financing activities:
Proceeds from issuance of common stock		-		9,945
Repayment of short-term notes payable		(338,512)		(373,360)
Net cash used in financing activities		(338,512)		(363,415)

Net decrease in cash and cash equivalents		(12,175,426)		(10,304,782)
Cash and cash equivalents - beginning of period		32,547,380		32,302,313
Cash and cash equivalents - end of period	$	20,371,954	$	21,997,531

Supplemental disclosures of cash flow information:
Cash paid for income taxes	$	49,566	$	33,097
Cash paid for interest		9,190,000		9,541,508

Non-cash investing and financing activities:
Unrealized gain on derivative instruments	$	100,353	$	161,760
Accounts payable for oil and gas additions		(941,459)		(1,900,768)
Accrued liabilities for oil and gas additions		(46,768)		(258,706)

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

SARATOGA RESOURCES, INC.

Notes to Consolidated Financial Statements

March 31, 2014

(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, 2013.

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 $20.1 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 March 31, 2014 and 2013, we did not recognize any impairment expense.

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 one and two counterparties at March 31, 2014 and December 31, 2013, respectively. We monitor and manage our level of financial exposure with respect to the counterparties we use. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election.

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

As of March 31, 2014, the Company had the following hedge contracts outstanding:


	Beginning	Ending	Fixed		Strike				Total
Instrument	Date	Date	Price		Price		Premium		Bbls
Fixed Price Swap	April 1, 2014	June 30, 2014	$	104.10	$	-	$	-	22,750
Fixed Price Swap	April 1, 2014	June 30, 2014		107.25		-		-	22,750
Covered Call	September 1, 2014	March 31, 2015	$	-	$	103.30	$	6.80	91,250
									136,750

The following table presents the fair value of the Company’s commodity derivative instruments at March 31, 2014 and December 31, 2013:


	March 31,		December 31,
Description	2014		2013
Current liabilities:
Commodity derivatives	$	447,119	$	837,758
	$	447,119	$	837,758
Long-term liabilities:
Commodity derivatives	$	-	$	182,174
	$	-	$	182,174

The following tables present the effect of commodity derivative instruments on our consolidated statements of operations and comprehensive income (loss) for the three months ended March 31, 2014 and 2013:


	For the Three months Ended March 31,
Description	2014		2013
Unrealized mark-to-market gain	$	1,092,960	$	166,508
Realized loss on settlements		(31,837)		(814,888)
Total loss on commodity derivative instruments	$	1,061,123	$	(648,380)


	For the Three months Ended March 31,
Description	2014		2013
Unrealized mark-to-market gain (loss) in other comprehensive income	$	100,353	$	161,760
Total other comprehensive income	$	100,353	$	161,760

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 March 31, 2014 and December 31, 2013:


	Level 1		Level 2		Level 3		Total
March 31, 2014
Liabilities:
Commodity derivatives	$	-	$	447,119	$	-	$	447,119
	$	-	$	447,119	$	-	$	447,119

December 31, 2013
Liabilities:
Commodity derivatives	$	-	$	1,019,932	$	-	$	1,019,932
	$	-	$	1,019,932	$	-	$	1,019,932

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:


	March 31,		December 31,
	2014		2013
Site specific trust accounts - P&A escrow	$	5,531,824	$	5,521,913
Debt issuance cost, net		5,762,500		6,351,806
Restricted cash – P&A bond		9,738,353		9,738,353
Other		57,406		53,758
	$	21,090,083	$	21,665,830

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 2014. 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 March 31, 2014 and December 31, 2013 reflect the issuance of the 12½% Second Lien Notes in December 2012 and July 2011 and the issuance of the 10% First Lien Notes in November 2013. 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 9 – “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 February 2014, 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 $1.32 per share and vest 1/3 on each of the first three grant date anniversaries. The grant date value of the options was $96,300. The options were valued using the Black-Scholes model with the following assumptions: 121% volatility; 4.5 year estimated life; zero dividends; 1.36% discount rate; and, quoted stock price and exercise price of $1.32.

The following table summarizes information about stock option activity and related information for the three months ended March 31, 2014:


	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, 2013		1,607,500	$	3.13	$	2.46	5.4	$	39,000
Granted		90,000		1.32		1.07	6.9		2,700
Exercised		-		-		-	-		-
Forfeited		(225,000)		4.06		4.05	-		-
Outstanding at March 31, 2014		1,472,500	$	2.87	$	2.13	5.2	$	52,200
Exercisable at March 31, 2014		762,500	$	3.29	$	2.75	5.1	$	49,500

(1)

The intrinsic value of an option is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the option. On March 31, 2014, the last reported sales price of our common stock on the NYSE MKT was $1.35 per share.

Share-Based Compensation Expense

The following table reflects share-based compensation recorded by the Company for the three months ended March 31, 2014 and 2013:


	Three Months Ended March 31,
	2014		2013
Share-based compensation expense included in reported net income	$	6,029	$	163,042
Basic earnings per share effect of share-based compensation expense	$	-	$	(0.01)

As of March 31, 2014, total unrecognized stock-based compensation expense related to non-vested stock options was $0.5 million. The unrecognized expense is expected to be recognized over a weighted average period of 0.6 years.

NOTE 7 – EQUITY

Common Stock Activity

There was no common stock activity during the three months ended March 31, 2014.

Warrant Activity

The following table summarizes information about stock warrant activity and related information for the three months ended March 31, 2014:


	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, 2013		146,998	$	6.64	$	5.33	1.4	$	-
Granted		-		-		-	-		-
Exercised		-		-		-	-		-
Forfeited		-		-		-	-		-
Outstanding at March 31, 2014		146,998	$	6.64	$	5.33	1.1	$	-
Exercisable at March 31, 2014		146,998	$	6.64	$	5.33	1.1	$	-

(1)

The intrinsic value of a warrant is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the warrant. On March 31, 2014, the last reported sales price of our common stock on the NYSE MKT was $1.35 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 March 31,
	2014					2013
	Income (Loss)		Weighted Average Common Shares Outstanding	Per Share		Income (Loss)		Weighted Average Common Shares Outstanding	Per Share
Basic:
Loss attributable to common stock	$	(8,289,187)	30,946,601	$	(0.27)	$	(1,061,393)	30,911,023	$	(0.03)
Effect of Dilutive Securities:
Stock options and other			-					-
Diluted:
Loss attributable to common stock, including assumed conversions	$	(8,289,187)	30,946,601	$	(0.27)	$	(1,061,393)	30,911,023	$	(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, 2013	$	12,649,458
Accretion expense		448,466
Additions		-
Revisions		-
Settlements		-
Balance at March 31, 2014	$	13,097,924

NOTE 10 – DEBT

Long-term debt consists of the following:


	March 31,		December 31
	2014		2013
10% First Lien Notes due 2015	$	54,600,000	$	54,600,000
12 ½% Second Lien Notes due 2016		125,200,000		125,200,000
Less unamortized discount		(1,459,889)		(1,603,016)
	$	178,340,111	$	178,196,984

10.0% First Lien Notes

In November 2013, the Company, and its wholly-owned subsidiaries (the “Guarantors”), issued $54.6 million in aggregate principal amount of 10.0% Senior Secured Notes due 2015 (the “First Lien Notes”) to two institutional accredited investors (the “Purchasers”).

The First Lien Notes were issued pursuant to Purchase Agreements (the “Purchase Agreement”), and under an Indenture (the “First Lien Indenture”), by and among the Company, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (the “First Lien Trustee”). The First Lien Notes are our senior secured obligations and are fully and unconditionally guaranteed (the “Guarantees”) 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 and senior in right of payment to Second Lien Notes (as defined below).

The purchase price for the First Lien Notes and Guarantees was 100% of their principal amount. We received net proceeds from the issuance and sale of the First Lien Notes of approximately $25.4 million, after commissions and estimated offering expenses, and the surrender for retirement by the Purchasers of $27.3 million in face amount of 12½% Senior Secured Notes (the “Second Lien Notes”).

The First Lien Notes mature on December 31, 2015, and interest, accruing at 10% per annum, is payable on the First Lien Notes on March 31, June 30, September 30 and December 31 of each year, commencing December 31, 2013.

The First Lien 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 First Lien Notes at any time at 100% of the principal amount to be redeemed plus accrued and unpaid interest. Upon the occurrence of a change of control, we are required to offer to purchase the First Lien Notes at a price equal to 101% of the aggregate principal amount of First Lien Notes repurchased plus accrued and unpaid interest. Further, upon the occurrence of certain asset sales, we are required to provide notice of the same and are required to offer to purchase a defined portion of the First Lien Notes at a price equal to 100% of the principal amount of First Lien Notes repurchased plus accrued and unpaid interest.

In connection with the issuance and sale of the First Lien Notes, the Company, the First Lien Trustee and The Bank of New York Mellon Trust Company, N.A., in its capacity as trustee and collateral under the Second Lien Documents (as defined below)(the “Second Lien Trustee”) entered into an Intercreditor Agreement (the “Intercreditor Agreement”). Pursuant to the Intercreditor Agreement, parties agreed that the lien with respect to collateral securing the First Lien Indenture and related First Lien Notes and Guarantees (the “First Lien Obligations”) shall be senior in right, priority, operation, effect and all other respects to any lien with respect to collateral securing the obligations under that certain Indenture dated as of June 12, 2011, as supplemented or amended from time to time thereafter (the “Second Lien Indenture”), by and among our company, the Guarantors named therein and the Second Lien Trustee, and the related Second Lien Notes in the aggregate amount of $125.2 million (the “Second Lien Obligations”).

12½% Second Lien Notes

In July 2011, the Company and 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 12½% Senior Secured Notes due 2016. The Second Lien Notes were sold at 98.221% of par in a transaction exempt from the registration requirements of the Securities Act and 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 Second Lien Notes. The Second Lien Notes were sold at 98.58% of par in a transaction exempt from the registration requirements of the Securities Act and 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 Second Lien Notes were issued pursuant to the Second Lien Indenture among the Company, the Guarantors named therein and Second Lien Trustee, as trustee and collateral agent and, with respect to the Second Lien Notes issued in 2012, a First Supplemental Indenture, dated December 4, 2012. The Second Lien 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, subject, however, to the Intercreditor Agreement pursuant to which the First Lien Notes are senior in right, priority, operation and effect to the lien securing the Second Lien Notes.

The Second Lien Notes mature on July 1, 2016, and interest is payable on January 1 and July 1 of each year.

The Second Lien 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 Second Lien Notes at any time on or after January 1, 2014 at the redemption prices specified in the Indenture 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 March 31, 2014, the Company’s management was not aware, and as of the date of this report is not aware, of any such litigation that could have a material adverse effect on its results of operations, cash flows or financial condition.

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of March 31, 2014, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company’s properties.

NOTE 12 – SUBSEQUENT EVENTS

In April 2014, 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 $1.22 per share and vest 1/3 on each of the first three grant date anniversaries. The grant date value of the options was $57,000. The options were valued using the Black-Scholes model with the following assumptions: 113% volatility; 4.5 year estimated life; zero dividends; 1.47% discount rate; and, quoted stock price and exercise price of $1.22.

In April 2014, 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 $1.18 per share and vest 1/3 on the six month grant date anniversary and 1/3 on each of the first two grant date anniversaries. The grant date value of the options was $70,200. The options were valued using the Black-Scholes model with the following assumptions: 92% volatility; 4.1 year estimated life; zero dividends; 1.25% discount rate; and, quoted stock price and exercise price of $1.18.

ITEM 2

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

Forward-Looking Information

This Form 10-Q quarterly report of Saratoga Resources, Inc. (the “Company”) for the three months ended March 31, 2014, 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, 2013.

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, 2013.

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 52,103 acres at March 31, 2014, comprised of our principal producing properties covering 32,289 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 March 31, 2014, we operated or had interests in 90 producing wells and our principal properties covered approximately 52,103 gross/net acres, more than half of which were held by production without near-term lease expirations, across 13 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 70% to 82%, with our average net revenue interest on a net acreage leasehold basis being approximately 75%. We operate over 95% 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.

2014 Developments

Drilling and Development Activities

Drilling and development and infrastructure project operations to date in 2014 are summarized as follows:

Development Drilling. We did not drill any developmental wells during the three months ended March 31, 2014. Following quarter end, we commenced drilling operations on our Rocky 3 well, our second horizontal well and, we believe, an analog to our Rocky well.

Exploratory Drilling. We did not drill any exploratory wells during the three months ended March 31, 2014.

Recompletion and Workover Program. During the three months ended March 31, 2014, we invested $1.0 million in 2 recompletions, one of which was successfully completed during the period and one of which was still in progress at quarter end, and an additional $2.2 million on 7 workovers, all of which were successfully completed during the period.

Infrastructure Program. During the three months ended March 31, 2014, we invested $0.2 million in infrastructure improvements and additions to support existing production and anticipated increases in production, primarily in Breton Sound 51 Field.

Drilling and Development Plans. We have an extensive inventory of drilling opportunities, including numerous proved behind pipe and proved undeveloped opportunities as well as a number of exploratory opportunities. Our near term development plans are focused on proved undeveloped opportunities and conversion of PDNP opportunities. 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 three months ended March 31, 2014, we had approximately 90 gross/net wells in production.

Production Optimization Initiatives

During the three months ended March 31, 2014, we undertook an exhaustive review of field operations in order to address ongoing run time issues that have adversely impacted production rates across our fields. Senior management, together with consultants retained by Saratoga, spent substantial time in the field evaluating personnel, facilities, gas lift availability and other potential causes of unexpected down time in numerous fields. As a result of such evaluation, we made extensive changes in our field operating personnel and in our Covington office personnel. We also undertook extensive repairs and maintenance projects to improve certain facilities in the field and invested in gas lift projects and salt water disposal wells. The majority of the personnel changes, facilities upgrades and other projects were completed in early March 2014. Additional changes and upgrades continued through the end of the quarter and beyond and we continue to monitor the results of such changes and upgrades and potential future changes and upgrades.

Prior to implementing the changes and upgrades in early March, run times had fallen to an estimated 54% on average during January and February 2014 from 75% during fiscal 2013. Following the changes and upgrades, run times for March 2014 averaged an estimated 76%. As a result of the run time issues experienced during the first two months of the quarter, average daily production for the full quarter fell to 1,330 boepd, down from 1,800 boepd during the fourth quarter of 2013. Following the changes and upgrades, and investments in workovers and salt water disposal wells, our production rate over the last seven days of the quarter had risen to an average of 1,875 boepd.

While the production initiatives undertaken during the quarter resulted in marked growth in production during the final month of the quarter, our lease operating expenses for the quarter rose on a year-over-year basis due, largely, to increased contract labor costs and facilities maintenance and repair costs incurred as part of the production optimization initiative.

Severance Tax

During the three months ended March 31, 2014, we experienced a sharp drop in severance taxes. While the drop in severance taxes reflected lower production levels, the bulk of the decrease in severance tax was associated with severance tax refunds attributable to exemptions for our Rocky, Zeke and Mesa Verde wells drilled in prior years.

Compensation

During the three months ended March 31, 2014, we granted 90,000 stock options to an employee at an exercise price of $1.32 per share.

We recorded $6,029 of compensation charges that is reflected in general and administrative expense for the three months ended March 31, 2014 and is attributable to equity grants during 2014 and prior years.

As of March 31, 2014, total compensation cost related to unvested stock option awards not yet recognized in earnings was approximately $0.5 million, which is expected to be recognized over a weighted average period of approximately 0.6 years.

During the three months ended March 31, 2014 and early in the second quarter of 2014, we hired four additional members of our professional staff. As a result of such hiring, we experienced a rise in compensation expense for the quarter and will experience a further rise in compensation expense in the second quarter of 2014.

Hedging Activities

As of March 31, 2014, we had in place fixed price swaps covering an aggregate of 45,500 barrels of oil over the period beginning April 1, 2014 and ending June 30, 2014, at prices ranging from $104.10 to $107.25 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 March 31, 2014 decreased by 45.0% to $10.6 million from $19.3 million in the 2013 quarter.

The decrease in revenue was attributable to a 44.2% decrease in oil revenues on a 39.9% decrease in oil production volumes and a 7.2% decrease in average oil prices realized and a 51.8% decline in gas revenues on a 65.5% decrease in gas production volumes partially offset by a 39.8% increase in average prices realized, each as compared to the 2013 quarter.

The following table discloses the oil and gas sales revenues, net oil and natural gas production volumes and average sales prices for the three ended March 31, 2014 and 2013:


	Three Months Ended March 31,
	2014		2013
Revenues
Oil	$	9,700,842	$	17,388,900
Gas		902,149		1,873,001
Total oil and gas revenues	$	10,602,991	$	19,261,901

Production
Oil (Bbls)		94,247		156,770
Gas (Mcf)		152,861		443,346
Total production (Boe)		119,724		230,661

Average sales price
Oil (per Bbl)	$	102.93	$	110.92
Gas (per Mcf)		5.90		4.22
Total average sales price (per Boe)	$	88.56	$	83.51

Oil production was down 62.5 MBbl, or 39.9%, for the three months ended March 31, 2014 as compared to the same period in 2013. The decrease in oil production was largely attributable to the decrease in average run times during the first two months of the quarter and, at the field level, reflected: (i) a 31.1 MBbl decline in oil production from the Breton Sound 18 Field primarily attributable to low gas volumes available for gas lift during the first half of the quarter and, to a lesser extent, natural decline; (ii) a 11.7 MBbl decline in oil production from Breton Sound 32 Field attributable to a combination of a lack of salt water disposal facilities and natural decline from some older wells, which was partially offset by production from the Rocky and Zeke wells brought into production during the third quarter of 2013; (iii) a 14.7 MBbl decline in oil production from Grand Bay Field primarily attributable to a combination of lack of gas lift, depletion of the producing sand in one well and an unexpected decline in production from a second well, all partially offset by increased production from a number of wells that underwent recompletion or workover projects during the second half of 2013 and the first quarter of 2014; and (iv) a 7.2 MBbl decline in oil production from Main Pass 46 Field primarily attributable to the Catina well due to natural declines and a brief shut-in period for maintenance. The declines in oil production from Breton Sound 18, Breton Sound 32, Grand Bay and Main Pass 46 Fields were partially offset by a 3.1MBbl increase in oil production from Main Pass 25 Field following the resolution during the current quarter of third party handling, gas lift and platform construction issues. The gas lift and salt water disposal facilities issues affecting oil production during the quarter are believed to have been substantially resolved by the quarter end.

Natural gas production was down 290.5 MMcf, or 51.8%, for the three months ended March 31, 2014 as compared to the same period in 2013. The decrease in gas production reflected: (i) a 228.9 MMcf decline in gas production in Grand Bay Field resulting from depletion of the producing sand in three wells, which was partially offset by increased gas production following a successful recompletion of one well in late 2013; and (ii) a 50.9 MMcf decline in gas production in Main Pass 52 Field resulting from the depletion of the producing sand in one well. The declines in gas production in Grand Bay and Main Pass 52 Fields were partially offset by (i) a 29.8 MMcf increase in gas production from Main Pass 46 Field as a result of the resolution of flow line restriction and facility repair issues; and (ii) a 3.5 MMcf increase in gas production as a result of the Rocky well coming on line in the third quarter of 2013 and a successful recompletion of a well during the first quarter of 2014 in the Breton Sound 32 Field.

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

Other Revenues

Other revenue consists principally of production handling fees and contract operator fees received.

Operating Expenses

Operating expenses increased by 51.7% to $19.5 million for the quarter ended March 31, 2014 from $12.9 million in the 2013 quarter. The following table sets forth the components of operating expenses for the 2014 and 2013 quarters:


	Three Months Ended				Three Months Ended
	March 31, 2014				March 31, 2013
	Total		Per Boe		Total		Per Boe
Lease operating expense	$	5,492,815	$	45.88	$	4,558,833	$	19.76
Workover expense		2,192,186		18.31		261,262		1.13
Exploration expense		221,352		1.85		168,284		0.73
Depreciation, depletion and amortization		2,742,059		22.90		5,208,494		22.58
Accretion expense		448,466		3.75		638,097		2.77
General and administrative		2,352,570		19.65		2,103,534		9.12
Severance taxes		500,750		4.18		2,091,054		9.07
	$	13,950,198	$	116.52	$	15,029,558	$	65.16

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

Lease Operating Expense

Lease operating expenses for the quarter ended March 31, 2014 increased 20.5% to $5.5 million from $4.6 million in the 2013 quarter and, on a per BOE basis, increased 132.2% to $45.88 per BOE from $19.76 per BOE, in the 2013 quarter. The increase in lease operating expense for the quarter was primarily due to (i) higher building repair and maintenance expenses in the Grand Bay Field and flowline/platform repair and maintenance expenses in Breton Sound 18 and Main Pass 25/46 Fields; (ii) increased contract construction labor expenses primarily in Grand Bay, Main Pass 25/46 Fields and the Breton Sound Fields; and (iii) a Breton Sound 32 flowline well maintenance charge in March of 2014. An estimated $0.5 million of the increase in lease operating expense related to contract labor and repairs and maintenance charges associated with our production enhancement initiative. We expect those expenses will decrease and as such result in future lease operating expenses leveling off. The increases in repair and maintenance and contract labor were partially offset by a decrease in slickline and payroll expenses.

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 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 March 31, 2014 increased to $2,192,186 from $261,262 in the 2013 quarter. 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 March 31, 2014 increased to $221,352 from $168,284 in the 2013 quarter. The increase in exploration expenses was principally due to investment in field studies related to our Gulf of Mexico shelf acreage.

Depreciation, Depletion and Amortization (DD&A)

Depreciation, depletion and amortization for the quarter ended March 31, 2014 decreased 47.4% to $2,742,059 from $5,208,494 in the 2013 quarter and increased to $22.90 per BOE from $22.58 per BOE in the 2013 quarter.

We utilize the successful efforts method of accounting for oil and gas producing activities. Under this method, DD&A is computed on the units-of-production method separately on each individual property and includes the accrual of future plugging and abandonment costs.

The decrease in DD&A expense during the 2014 quarter was primarily attributable to production declines during the quarter.

Accretion expense

Accretion expense relating to our asset retirement obligations decreased to $448,466 from $638,097 for the quarter ended March 31, 2014 as compared to the 2013 quarter.

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

General and Administrative

General and administrative (“G&A”) expense for the quarter ended March 31, 2014 increased 11.8% to $2,352,570 as compared to $2,103,534 in the 2013 quarter, and increased 115.5% to $19.65 from $9.12 on a per BOE basis. The increase in G&A expense for the quarter was primarily due to legal and professional fees and an increase in the employee headcount resulting in higher salaries and benefits, partially offset by a decrease in non-cash stock compensation expense.

Severance Taxes

Severance taxes for the quarter ended March 31, 2014 decreased to $500,750 from $2,091,054 in the 2013 quarter. The decrease was primarily attributable to production declines and the horizontal well severance tax exemptions obtained for our Rocky and Zeke wells and the deep well severance tax exemption obtained for our Mesa Verde well. These exemptions resulted in refunds of severance taxes paid in prior periods of $0.5 million.

Other Income (Expense), Net

Net other expense increased to $6.0 million in for the quarter ended March 31, 2014 from $5.2 million for the 2013 quarter.

Interest expense reflects interest incurred on debt under our 10% First Lien Notes and 12.5% Second Lien Notes. The increase in interest expense was attributable to our placement of $54.6 million in principal of the First Lien Notes in November 2013, partially offset by a simultaneous reduction of $27.3 million in principal of the Second Lien Notes.

Income Tax Expense (Benefit)

For the quarter ended March 31, 2014 we recorded an income tax expense of $82,066 compared to a benefit of $454,150 during the 2013 quarter.

The increase in income tax expense is primarily due to the fact that we recorded a valuation allowance for the entire balance of our net deferred tax asset at December 31, 2013 and accordingly, did not recognize any deferred tax benefit as a result of the current quarter loss.

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

Financial Condition

Liquidity and Capital Resources

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

During 2013 and 2014 we funded operations out of operating cash flow and cash on hand, which funds have been supplemented by the issuance of $27.3 million of First Lien Notes for cash in November 2013. During 2013 and 2014, we did not have access to available capital under a revolving credit agreement and do not at this time have a revolving credit facility. With our receipt of proceeds from our November 2013 First Lien Note offering, we do not anticipate that we will need to establish a revolving credit facility in the foreseeable future.

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 2013 and 2014, while continuing to advance short-term objectives associated with continual investment in recompletions, workovers and infrastructure, we focused on our mid-term objectives through drilling proved undeveloped opportunities in 2013 and in preparation to drill proved undeveloped opportunities in 2014.

We believe that our cash flows from operations and cash on hand 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 operating results, including 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 or curtail our planned development of proved undeveloped opportunities or otherwise adjust the nature or rate of our development program to reflect available funding.

Pursuit of our long-term plans for exploratory drilling of deep shelf prospects in Grand Bay Field, Vermilion 16 Field and our newly acquired Gulf of Mexico shelf prospects is expected to require funding in excess of our current resources and projected operating cash flow and, with respect to ultra-deep prospects in Vermilion 16 Field, to be dependent upon results attained by other operators that are currently pioneering ultra-deep drilling in the trend within which our ultra-deep prospects are located. At March 31, 2014, we were continuing to monitor developments within the ultra-deep trend and to be engaged in efforts to attract potential partners relative to the potential exploration of our ultra-deep prospects and deep shelf prospects. Even if we are able to attract partners to bear the majority of the costs of exploration of these prospects, we may lack the financial resources to carry our proportionate share of the anticipated exploration and development costs associated with such joint venture and may be required to secure additional financing to support our share of such costs and maintain our interest in such ultra-deep and deep shelf prospects. To that end, we expect to seek partners to enter into arrangements that will provide the necessary funding to pay some, or all, of our share of the joint venture costs with the effect of reducing our interest in the joint venture. We presently have no commitments to provide funding to cover our share of such costs.

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

Cash, Cash Flows and Working Capital

We had a cash balance of $20.4 million and working capital of $14.6 million at March 31, 2014 as compared to a cash balance of $32.5 million and working capital of $20.4 million at December 31, 2013. The decrease in cash on hand was primarily attributable the interest payment on our 12.5% Second Line Notes in January 2014 and on our 10% First Lien Notes in March 2014 and to reductions in operating cash flow and investments in our development program. The decrease in our working capital was primarily attributable to the reduction in our cash balance, partially offset by reductions in accounts payable and accrued liabilities.

Operations used cash flow of $9.5 million for the three months ended March 31, 2014 as compared to using $0.2 million for the three months ended March 31, 2013. The change in operating cash flows during 2014 was principally attributable to reduced profitability resulting from lower production volumes and changes in our operating assets and liabilities.

Investing activities used cash totaling $2.3 million during the three months ended March 31, 2014 as compared to $9.7 million during 2013. The decrease in cash used in investing activities was primarily due to the fact that we did not drill any developmental wells during the quarter.

Financing activities used cash flows of $0.3 million during the three months ended March 31, 2014 as compared to $0.4 million during 2013. Cash flows used by financing activities during both periods primarily related to repayments on our short-term notes payable.

Debt

At March 31, 2014, we had $178.3 million of indebtedness outstanding, consisting of $54.6 million in face amount of 10% First Lien Notes, less $0.3 million of debt discount, and $125.2 million in face amount of 12½% Senior Secured Notes due 2016 less $1.2 million of debt discount.

We had no letters of credit outstanding at March 31, 2014 that were not fully collateralized by cash.

10% First Lien Notes. In November 2013, we issued $54.6 million in aggregate principal amount of our 10.0% Senior Secured Notes due 2015 (the “First Lien Notes”).

The 10% First Lien 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 and senior in right of payment to 12½% Second Lien Notes.

The 10% First Lien Notes mature on December 31, 2015, and interest, accruing at 10% per annum, is payable on the notes on March 31, June 30, September 30 and December 31 of each year, commencing December 31, 2013.

We have the option to redeem all or a portion of the 10% First Lien Notes at any time at 100% of the principal amount to be redeemed plus accrued and unpaid interest. Upon the occurrence of a change of control, we are required to offer to purchase the 10% First Lien Notes at a price equal to 101% of the aggregate principal amount of 10% First Lien Notes repurchased plus accrued and unpaid interest. Further, upon the occurrence of certain asset sales, we are required to provide notice of the same and are required to offer to purchase a defined portion of the 10% First Lien Notes at a price equal to 100% of the principal amount of 10% First Lien Notes repurchased plus accrued and unpaid interest.

In connection with the issuance and sale of the 10% First Lien Notes, we, the First Lien Trustee and Second Lien Trustee entered into an Intercreditor Agreement. Pursuant to the Intercreditor Agreement, the parties agreed that the lien with respect to collateral securing the First Lien Indenture and related First Lien Obligations shall be senior in right, priority, operation, effect and all other respects to any lien with respect to collateral securing the obligations under Second Lien Indenture, by and among our company, the Guarantors named therein and the Second Lien Trustee, and the related 12½% Second Lien Notes.

12½% Second Lien Notes. In July 2011, we issued $127.5 million of our 12½% Second Lien 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 12½% Second Lien Notes. In November 2013, we retired $27.3 million in face amount of our 12½% Second Lien Notes pursuant to the issuance of a like amount of 10% First Lien Notes described above.

The 12½% Second Lien 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, subject, however, to the Intercreditor Agreement pursuant to which the 10% First Lien Notes are senior in right, priority, operation and effect to the lien securing the 12½% Second Lien Notes. The 12½% Second Lien Notes mature on July 1, 2016, and interest is payable on the notes on January 1 and July 1 of each year. We have the option to redeem all or a portion of the 12½% Second Lien Notes at any time on or after January 1, 2014 at the redemption prices specified in the Second Lien Indenture pursuant to which the 12½% Second Lien Notes were issued plus accrued and unpaid interest.

Capital Expenditures and Commitments

Our capital spending for the three months ended March 31, 2014 was $3.5 million relating primarily to development of our oil and gas properties, including 2 recompletions ($1.0 million), 7 workovers ($2.2 million), investments in multiple infrastructure projects ($0.2 million) and other leasehold costs ($0.1 million). Capital expenditures were down from $7.4 million during the 2013 quarter.

Drilling on our Rocky 3 prospect, a horizontal well, commenced during the second quarter of 2014 with dry holes costs budgeted at approximately $3.5 million. 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.

With the decline in our production and associated revenues and cash position accompanying the drop in run times during January and February, and the rebound in our run times and production levels beginning in March 2014, we presently expect to focus our efforts during the second and third quarters of 2014 on recompletions and workovers that have the potential to enhance production in a short time frame and at lower cost in order to build our cash position with a view to pursuing renewed development drilling beginning in the fall of 2014.

Risk Management Activities – Commodity Derivative Instruments

We periodically enter into price-risk management transactions (e.g., swaps, and floors) for a portion of our oil and natural gas production. In certain cases, this allows us to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. The commodity derivative instruments apply to only a portion of our production, and provide only partial price protection against declines in oil and natural gas prices, and partially limit our potential gains from future increases in prices. None of these instruments have been used for trading purposes. During the three months ended March 31, 2014, we recorded an unrealized gain on commodity derivatives of $0.5 million in current earnings and an unrealized gain on commodity derivatives of $0.1 million in accumulated other comprehensive income (loss).

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements or guarantees of third party obligations at March 31, 2014.

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. In the normal course of business we periodically enter into commodity derivative transactions, including fixed price and ratio swaps to mitigate exposure to commodity price movements, but not for trading or speculative purposes.

As of March 31, 2014, we had the following hedge contracts outstanding:


	Beginning	Ending	Fixed		Strike				Total
Instrument	Date	Date	Price		Price		Premium		Bbls
Fixed Price Swap	April 1, 2014	June 30, 2014	$	104.10	$	-	$	-	22,750
Fixed Price Swap	April 1, 2014	June 30, 2014		107.25		-		-	22,750
Covered Call	September 1, 2014	March 31, 2015	$	-	$	103.30	$	6.80	91,250
									136,750

We are exposed to market risk on derivative instruments to the extent of changes in market prices of crude oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. The change in the fair value of our commodity derivative contracts that are effective are recorded to Accumulated Other Comprehensive Income (Loss) in Stockholders’ Equity in the Consolidated Balance Sheet. The ineffective portion of the change in fair market value of derivatives is recorded currently in earnings as a component of Oil and Gas Hedging in the Consolidated Statements of Operations. We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. For the three months ended March 31, 2014, we recorded an unrealized gain on commodity derivatives of $100,353 in accumulated other comprehensive income (loss).

Koch Supply & Trading, LP is the counterparty to our present fixed price swap contracts and covered call options. We are exposed to credit losses in the event of nonperformance by the counterparty on our commodity derivatives positions. However, we do not anticipate nonperformance by the counterparty over the term of the commodity derivatives positions.

Interest Rate Risk

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

ITEM 4

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Under the supervision and the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation as of March 31, 2014 of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were not effective as of March 31, 2014.

Changes in Internal Control over Financial Reporting

No change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) occurred during the quarter ended March 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II

ITEM 6

EXHIBITS


Exhibit No.		Description

31.1		Certification of CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certification of CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1		Certification of CEO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2		Certification of CFO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS		XBRL Instance Document
101.SCH		XBRL Schema Document
101.CAL		XBRL Calculation Linkbase Document
101.DEF		XBRL Definition Linkbase Document
101.LAB		XBRL Labels Linkbase Document
101.PRE		XBRL Presentation Linkbase Document

SIGNATURES

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


	SARATOGA RESOURCES, INC.
Date: May 15, 2014
	By:	/s/ Thomas Cooke
		Thomas Cooke
		Chief Executive Officer

	By:	/s/ John Ebert
		John Ebert
		Vice President –Finance and Business Development