Edgar Filing: SARATOGA RESOURCES INC /TX

SARATOGA RESOURCES, INC.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2015


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.)

9225 Katy Freeway, Suite 100, Houston, Texas 77024

(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 August 10, 2015, we had 30,986,601 shares of $0.001 par value Common Stock outstanding.

SARATOGA RESOURCES, INC.

FORM 10-Q

INDEX


		Page No.
PART I FINANCIAL INFORMATION		3

ITEM 1. Financial Statements (Unaudited)		3
	Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	3
	Consolidated Statements of Operations and Other Comprehensive Loss for the three and six months ended June 30, 2015 and 2014	4
	Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014	5
	Notes to Consolidated Financial Statements	6
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		27
ITEM 4. Controls and Procedures		27

PART II OTHER INFORMATION		28

ITEM 6. Exhibits		28

PART I - FINANCIAL INFORMATION

ITEM 1

Financial Statements


SARATOGA RESOURCES, INC. (DEBTOR AND DEBTOR-IN-POSSESSION)
CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,		December 31,
	2015		2014
ASSETS

Current assets:
Cash and cash equivalents	$	5,414,363	$	10,911,070
Accounts receivable		3,315,321		3,778,808
Prepaid expenses and other		1,064,521		1,006,758
Other current asset		150,000		150,000
Total current assets		9,944,205		15,846,636

Property and equipment:
Oil and gas properties - proved (successful efforts method)		302,177,776		301,399,079
Other		1,031,779		1,031,779
		303,209,555		302,430,858
Less: Accumulated depreciation, depletion and amortization		(232,118,602)		(226,716,401)
Total property and equipment, net		71,090,953		75,714,457

Other assets, net		17,376,073		20,350,655
Total assets	$	98,411,231	$	111,911,748

LIABILITIES AND STOCKHOLDERS' DEFICIT

Current liabilities:
Accounts payable	$	769,518	$	6,722,116
Revenue and severance tax payable		2,426,326		2,711,229
Accrued liabilities		23,152,054		13,006,617
Derivative liabilities – short term		-		117
Short-term notes payable		694,135		329,964
First lien notes, net of unamortized discount of $151,169 at December 31, 2014		54,600,000		54,448,831
Second lien notes, net of unamortized discount of $847,947 at December 31, 2014		125,200,000		124,352,053
Total current liabilities		206,842,033		201,570,927

Long-term liabilities:
Asset retirement obligation		17,507,236		16,397,804
Total long-term liabilities		17,507,236		16,397,804

Liabilities subject to compromise		2,198,927		-

Commitment and contingencies (see notes)

Stockholders' equity:
Common stock, $0.001 par value; 100,000,000 shares authorized 30,986,601 shares issued and outstanding at June 30, 2015 and December 31, 2014, respectively		30,987		30,987
Additional paid-in capital		78,809,499		78,754,854
Retained deficit		(206,977,451)		(184,842,824)

Total stockholders' deficit		(128,136,965)		(106,056,983)

Total liabilities and stockholders' deficit	$	98,411,231	$	111,911,748

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


SARATOGA RESOURCES, INC. (DEBTOR AND DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE LOSS
(Unaudited)


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2015		2014		2015		2014
Revenues:
Oil and gas revenues	$	7,344,158	$	15,120,717	$	13,674,620	$	25,723,708
Oil and gas hedging		-		(201,456)		117		859,667
Other revenues		398,873		72,426		470,258		148,601
Total revenues		7,743,031		14,991,687		14,144,995		26,731,976

Operating Expense:
Lease operating expense		3,945,665		6,304,457		7,953,672		11,797,272
Workover expense		113,742		107,582		132,720		2,299,768
Exploration expense		19,223		200,298		38,321		421,650
Depreciation, depletion and amortization		2,653,807		4,507,996		5,402,201		7,250,055
Accretion expense		595,561		448,467		1,191,123		896,933
General and administrative		2,010,422		2,702,388		3,897,834		5,054,958
Severance taxes		751,700		1,309,592		1,331,904		1,810,342
Total operating expenses		10,090,120		15,580,780		19,947,775		29,530,978

Operating income (loss)		(2,347,089)		(589,093)		(5,802,780)		(2,799,002)

Other income (expense):
Interest income		55		17,027		59		33,348
Interest expense		(7,758,058)		(6,040,171)		(16,273,106)		(12,053,704)
Total other expense		(7,758,003)		(6,023,144)		(16,273,047)		(12,020,356)

Net loss before reorganization expense and income taxes		(10,105,092)		(6,612,237)		(22,075,827)		(14,819,358)

Reorganization expense		7,800		-		7,800		-

Net loss before income taxes		(10,112,892)		(6,612,237)		(22,083,627)		(14,819,358)

Income tax expense (benefit)		25,500		40,199		51,000		122,265

Net loss	$	(10,138,392)	$	(6,652,436)	$	(22,134,627)	$	(14,941,623)

Other comprehensive loss
Unrealized gain (loss) on derivative instruments		-		(112,804)		-		(12,451)
Total comprehensive loss	$	(10,138,392)	$	(6,765,240)	$	(22,134,627)	$	(14,954,074)

Net loss per share:
Basic	$	(0.33)	$	(0.21)	$	(0.71)	$	(0.48)
Diluted	$	(0.33)	$	(0.21)	$	(0.71)	$	(0.48)

Weighted average number of common shares outstanding:
Basic		30,986,601		30,949,678		30,986,601		30,948,148
Diluted		30,986,601		30,949,678		30,986,601		30,948,148

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


SARATOGA RESOURCES, INC. (DEBTOR AND DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	For the Six Months Ended
	June 30,
	2015		2014
Cash flows from operating activities:
Net loss	$	(22,134,627)	$	(14,941,623)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		5,402,201		7,250,055
Accretion expense		1,191,123		896,933
Amortization of debt issuance costs		4,077,060		1,199,287
Amortization of debt discount		999,116		291,383
Stock-based compensation		54,645		246,282
Unrealized gain on hedges		(117)		(1,059,520)
Changes in operating assets and liabilities:
Accounts receivable		463,487		(1,780,054)
Prepaids and other		909,330		371,578
Accounts payable		(2,832,847)		176,440
Revenue and severance tax payable		(284,903)		516,551
Payments to settle asset retirement obligations		(81,691)		-
Accrued liabilities		10,145,437		(460,697)
Net cash used in operating activities		(2,091,786)		(7,293,385)

Cash flows from investing activities:
Additions to oil and gas property		(1,699,521)		(6,290,509)
Additions to other property and equipment		-		(118,382)
Other assets		(1,102,478)		(40,919)
Net cash used in investing activities		(2,801,999)		(6,449,810)

Cash flows from financing activities:
Proceeds from issuance of common stock		-		61,200
Repayment of short-term notes payable		(602,922)		(517,098)
Net cash used in financing activities		(602,922)		(455,898)

Net decrease in cash and cash equivalents		(5,496,707)		(14,199,093)
Cash and cash equivalents - beginning of period		10,911,070		32,547,380
Cash and cash equivalents - end of period	$	5,414,363	$	18,348,287

Supplemental disclosures of cash flow information:
Cash paid for income taxes	$	-	$	122,265
Cash paid for interest		1,398,214		10,557,901

Non-cash investing and financing activities:
Unrealized gain (loss) on derivative instruments	$	-	$	(12,451)
Accounts payable for oil and gas additions		-		4,207,809
Accrued liabilities for oil and gas additions		-		(79,800)
Prepaid insurance financed with debt		967,093		1,607,278

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

SARATOGA RESOURCES, INC.

(DEBTOR AND DEBTOR-IN-POSSESSION)

Notes to Consolidated Financial Statements

June 30, 2015

(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.

Chapter 11 Bankruptcy and Going Concern

On June 18, 2015, the Company and its subsidiaries, The Harvest Group, LLC, LOBO Operating, Inc., LOBO Resources, Inc. and Harvest Oil & Gas, LLC (together the “Debtors”) each filed a voluntary petition under Chapter 11 in the United States Bankruptcy Court for the Western District of Louisiana (the “Bankruptcy Court”) to restructure our obligations and capital structure. The Chapter 11 cases are being jointly administered for procedural purposes by the Bankruptcy Court under the caption Harvest Oil & Gas, LLC, ET AL, Case No. 15-50748 (Jointly Administered).

The Debtors are currently operating our business as debtors in possession in accordance with the applicable provisions of title 11 of the United States Code (the “Bankruptcy Code”). Since the Chapter 11 filings, the Bankruptcy Court has entered all orders sufficient to enable the Debtors to conduct normal business activities, including orders to, among other things and subject to applicable caps for pre-petition items, pay employee wages and benefits, pay certain critical vendors, and forward funds belonging to third parties, including royalty holders, as well as the approval of the Debtors’ use of their secured lenders’ cash collateral and collateral, and the provision of adequate protection related thereto. While the Debtors are subject to Chapter 11, all transactions outside the ordinary course of their business will require the prior approval of the Bankruptcy Court.

Appointment of Creditors Committee. On July 24, 2015, the United States Trustee appointed the Creditors Committee. The Creditors Committee and its legal representatives have a right to be heard on all matters that come before the Bankruptcy Court with respect to the Debtors. There can be no assurance that the Creditors Committee will support the Debtors’ positions on matters presented to the Bankruptcy Court, including any plan of reorganization. Disagreements between the Debtors and the Creditors Committee could protract the Chapter 11 proceedings, negatively impact the Debtors’ ability to operate, and delay the Debtors’ emergence from the Chapter 11 proceedings.

Magnitude of Potential Claims. The Debtors have filed with the Bankruptcy Court Schedules and Statements setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The Schedules and Statements may be subject to further amendment or modification. Certain holders of pre-petition claims are required to file proofs of claim. Differences between amounts scheduled by the Debtors and claims by creditors will be investigated and resolved in connection with the claims resolution process. The ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

Costs of Reorganization. Debtors have incurred and will continue to incur significant costs associated with the reorganization. The amount of these costs, which are being expensed as incurred, are expected to significantly affect our results of operations.

Process for Plan of Reorganization. In order to successfully exit bankruptcy, the Debtors will need to propose, and obtain confirmation by the Bankruptcy Court of, a plan (or plans) of reorganization that satisfies the requirements of the Bankruptcy Code. A plan of reorganization would, among other things, resolve the Debtors’ pre-petition obligations, set forth the revised capital and debt structure of the newly reorganized entity and provide for corporate governance subsequent to exit from bankruptcy.

The timing of filing a plan of reorganization by the Debtors will depend on the timing and outcome of numerous other ongoing matters in the Chapter 11 proceedings. Although the Debtors expect to file a plan of reorganization that provides for our emergence from bankruptcy as a going concern, there can be no assurance at this time that the Debtors will be able to successfully develop, confirm and consummate one or more plans of reorganization or other alternative restructuring transactions, including a sale of all or substantially all of the Debtors’ assets, that satisfies the conditions of the Bankruptcy Code and is confirmed by the Bankruptcy Court, or that any such plan will be implemented successfully.

For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process. As a result of these risks and uncertainties, the number of our outstanding shares and our stockholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this Quarterly Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

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, 2014.

As a result of sustained losses and our Chapter 11 proceedings, the realization of assets and satisfaction of liabilities, without substantial adjustments and/or changes in ownership, are subject to uncertainty. Given the uncertainty surrounding our Chapter 11 proceedings, there is substantial doubt about our ability to continue as a going concern.

The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of our Chapter 11 proceedings. In particular, the financial statements do not purport to show (i) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (ii) as to pre-petition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (iii) as to stockholders’ equity accounts, the effect of any changes that may be made in our capitalization; or (iv) as to operations, the effect of any changes that may be made to our business.

In accordance with GAAP, we have applied ASC 852 “Reorganizations,” in preparing our consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in reorganization items, net in the accompanying condensed consolidated statements of income (loss) and comprehensive income (loss). In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on our condensed consolidated balance sheets at June 30, 2015 in Liabilities Subject to Compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

While operating as debtors in possession under Chapter 11 of the Bankruptcy Code, the Debtors may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected in our consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a plan of reorganization could materially change the amounts and classifications in our historical consolidated financial statements.

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 $5.2 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.

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. We receive proceeds for the sale of crude oil call options which carry a strike price. The call option, when combined with the Company’s long production position, represents a “covered call” and creates a ceiling, at the strike price, on the price to be received during the covered period for the related production.

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

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

As of June 30, 2015, the Company had no hedge contracts outstanding.

The following table presents the fair value of the Company’s commodity derivative instruments at June 30, 2015 and December 31, 2014:


	June 30,		December 31,
Description	2015		2014
Current liabilities:
Commodity derivatives	$	-	$	117
	$	-	$	117

The following tables present the effect of commodity derivative instruments on our consolidated statements of operations and comprehensive income (loss) for the three and six months ended June 30, 2015 and 2014:


	For the Three months Ended June 30,				For the Six months Ended June 30,
Description	2015		2014		2015		2014
Unrealized mark-to-market gain (loss)	$	-	$	(33,440)	$	-	$	1,059,520
Realized gain (loss) on settlements		-		(168,016)		117		(199,853)
Total gain (loss) on commodity derivative instruments	$	-	$	(201,456)	$	117	$	859,667


	For the Three months Ended June 30,				For the Six months Ended June 30,
Description	2015		2014		2015		2014
Unrealized mark-to-market gain (loss) in other comprehensive income	$	-	$	(112,804)	$	-	$	(12,451)
Total other comprehensive income (loss)	$	-	$	(112,804)	$	-	$	(12,451)

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 Company had no assets or liabilities recognized in the balance sheet and measured at fair value on a recurring basis as of June 30, 2015.

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 December 31, 2014:


	Level 1		Level 2		Level 3		Total
December 31, 2014
Liabilities:
Commodity derivatives	$	-	$	117	$	-	$	117
	$	-	$	117	$	-	$	117

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:


	June 30,		December 31,
	2015		2014
Site specific trust accounts - P&A escrow	$	5,564,129	$	5,564,129
Debt issuance cost, net		-		4,077,060
Restricted cash – P&A bond		10,628,903		10,628,903
Other		1,183,041		80,563
	$	17,376,073	$	20,350,655

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 December 31, 2014 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 – LIABILITIES SUBJECT TO COMPROMISE

As a result of the Chapter 11 Filings, the payment of prepetition indebtedness may be subject to compromise or other treatment under the Debtors’ plan of reorganization. Generally, actions to enforce or otherwise effect payment of prepetition liabilities are stayed. Refer to Note 1, Chapter 11 Bankruptcy and Going Concern.

The Debtors have been paying and intend to continue to pay undisputed post-petition claims in the ordinary course of business. In addition, the Debtors may reject prepetition executory contracts and unexpired leases with respect to the Debtors’ operations, with the approval of the Court. Damages resulting from rejection of executory contracts and unexpired leases are treated as general unsecured claims and will be classified as liabilities subject to compromise.

ASC 852 requires prepetition liabilities that are subject to compromise to be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. The amounts currently classified as liabilities subject to compromise may be subject to future adjustments depending on Court actions, further developments with respect to disputed claims, determinations of the secured status of certain claims, the values of any collateral securing such claims, or other events.

Liabilities subject to compromise consist of the following at June 30, 2015:


Accounts payable	$	2,198,927
Accrued liabilities		-
Total liabilities subject to compromise	$	2,198,927

NOTE 7 – 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 2015, the Company’s board of directors approved a stock option grant to purchase an aggregate of 30,000 shares of common stock to an executive officer. The options are exercisable for a term of seven years at $0.21 per share and vest 1/3 after six months and 1/3 on each of the first two grant date anniversaries. The grant date value of the options was $3,900. The options were valued using the Black-Scholes model with the following assumptions: 84% volatility; 4.1 year estimated life; zero dividends; 1.28% discount rate; and, quoted stock price and exercise price of $0.21.

In February 2015, the Company’s management approved a stock option grant to purchase an aggregate of 30,000 shares of common stock to a non-executive employee. The options are exercisable for a term of seven years at $0.21 per share and vest 1/3 after six months and 1/3 on each of the first two grant date anniversaries. The grant date value of the options was $3,900. The options were valued using the Black-Scholes model with the following assumptions: 84% volatility; 4.1 year estimated life; zero dividends; 1.28% discount rate; and, quoted stock price and exercise price of $0.21.

In February 2015, the Company’s management approved a stock option grant to purchase an aggregate of 15,000 shares of common stock to a non-executive employee. The options are exercisable for a term of seven years at $0.27 per share and vest 1/3 on each of the first three grant date anniversaries. The grant date value of the options was $2,700. The options were valued using the Black-Scholes model with the following assumptions: 86% volatility; 4.5 year estimated life; zero dividends; 1.57% discount rate; and, quoted stock price and exercise price of $0.27.

In April 2015, 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 $0.23 per share and vest 1/3 on each of the first three grant date anniversaries. The grant date value of the options was $9,000. The options were valued using the Black-Scholes model with the following assumptions: 86% volatility; 4.5 year estimated life; zero dividends; 1.19% discount rate; and, quoted stock price and exercise price of $0.23.

The following table summarizes information about stock option activity and related information for the six months ended June 30, 2015:


	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		1,652,500	$	2.59	$	1.81	4.8	$	-
Granted		135,000		0.23		0.14	6.7		-
Exercised		-		-		-	-		-
Forfeited		(165,000)		1.54		1.57	-		-
Outstanding at June 30, 2015		1,622,500	$	2.50	$	1.73	4.4	$	-
Exercisable at June 30, 2015		1,277,500	$	2.91	$	1.97	4.0	$	-

(1)

The intrinsic value of an option is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the option. On June 30, 2015, the last reported sales price of our common stock on the OTC Pink marketplace was $0.05 per share.

Share-Based Compensation Expense

The following table reflects share-based compensation recorded by the Company for the three and six months ended June 30, 2015 and 2014:


	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Share-based compensation expense included in reported net income	$	(46,861)	$	240,253	$	54,465	$	246,282
Basic earnings per share effect of share-based compensation expense	$	0.00	$	(0.01)	$	(0.00)	$	(0.01)

As of June 30, 2015, total unrecognized stock-based compensation expense related to non-vested stock options was $0.1 million. The unrecognized expense is expected to be recognized over a weighted average period of 0.5 years.

NOTE 8 – EQUITY

Common Stock Activity

There was no common stock activity during the six months ended June 30, 2015.

Warrant Activity

The following table summarizes information about stock warrant activity and related information for the six months ended June 30, 2015:


	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, 2014		146,998	$	6.64	$	5.33	1.4	$	-
Granted		-		-		-	-		-
Exercised		-		-		-	-		-
Forfeited		(146,998)		6.64		5.33	-		-
Outstanding at June 30, 2015		-	$	-	$	-	-	$	-
Exercisable at June 30, 2015		-	$	-	$	-	-	$	-

(1)

The intrinsic value of a warrant is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the warrant. On June 30, 2015, the last reported sales price of our common stock on the OTC Pink marketplace was $0.05 per share.

NOTE 9 – EARNINGS (LOSS) PER SHARE

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


	For the Three Months Ended June 30,
	2015					2014
	Income (Loss)		Weighted Average Common Shares Outstanding	Per Share		Income (Loss)		Weighted Average Common Shares Outstanding	Per Share
Basic:
Loss attributable to common stock	$	(10,138,392)	30,986,601	$	(0.33)	$	(6,652,436)	30,949,678	$	(0.21)
Effect of Dilutive Securities:
Stock options and other			-					-
Diluted:
Loss attributable to common stock, including assumed conversions	$	(10,138,392)	30,986,601	$	(0.33)	$	(6,652,436)	30,949,678	$	(0.21)


	For the Six Months Ended June 30,
	2015					2014
	Income (Loss)		Weighted Average Common Shares Outstanding	Per Share		Income (Loss)		Weighted Average Common Shares Outstanding	Per Share
Basic:
Loss attributable to common stock	$	(22,134,627)	30,986,601	$	(0.71)	$	(14,941,623)	30,948,148	$	(0.48)
Effect of Dilutive Securities:
Stock options and other			-					-
Diluted:
Loss attributable to common stock, including assumed conversions	$	(22,134,627)	30,986,601	$	(0.71)	$	(14,941,623)	30,948,148	$	(0.48)

NOTE 10 – 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, 2014	$	16,397,804
Accretion expense		1,191,123
Additions		-
Revisions		-
Settlements		(81,691)
Balance at June 30, 2015	$	17,507,236

NOTE 11 – DEBT

Debt consists of the following:


	June 30,		December 31
	2015		2014
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		-		(999,116)
	$	179,800,000	$	178,800,884

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”).

Interest accrued and owing as of December 31, 2014, in the amount of $1,365,000, was not paid as of the due date. Such interest was subsequently paid in connection with a Forbearance Agreement to First Lien Indenture (see below). Interest accrued and owing as of March 31, 2015 and June 30, 2015, in the amount of $2,730,000, has not been paid and, as a result, the First Lien Notes are in default and are included as a current liability in the accompany consolidated financial statements. The unpaid interest payments accrue interest computed at the default rate of 12%.

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.

Interest accrued and owing as of January 1, 2015 and July 1, 2015, in the amount of $15,650,000, has not been paid and, as a result, the Second Lien Notes are in default and are included as a current liability in the accompanying consolidated financial statements. The unpaid interest payments accrue interest at the default rate of 14.5%. The Company and the principal holders of the Second Lien Notes entered into a Forbearance Agreement to Second Lien Debenture in January 2015. See below.

Forbearance Agreements

On January 30, 2015, the Company, along with its subsidiaries, Lobo Operating, Inc., Lobo Resources, Inc., Harvest Oil & Gas, LLC and The Harvest Group, LLC entered into a forbearance agreement (the “First Lien Forbearance Agreement”) with the holders (the “First Lien Lenders”) of certain notes (the “First Lien Notes”) issued under that certain Indenture dated as of November 22, 2013 (the “First Lien Indenture”), by and among the Company and The Bank of New York Mellon Trust Company, N.A., as trustee (the “First Lien Trustee”). Also on January 30, 2015, the Company entered into a forbearance agreement (the “Second Lien Forbearance Agreement” and, together with the First Lien Forbearance Agreement, the “Forbearance Agreements”) with the holders (the “Second Lien Lenders”) of seventy-five percent (75%) or more in principal amount of the notes (the “Second Lien Notes”) issued under that certain Indenture dated as of July 12, 2011 (as supplemented or amended, the “Second Lien Indenture”), by and among the Company and The Bank of New York Mellon Trust Company, N.A., as trustee (the “Second Lien Trustee”).

The Forbearance Agreements were entered into following (i) the Company’s failure to pay to the First Lien Lenders an interest installment in the amount of $1.3 million scheduled for payment on December 31, 2014, and constituting a default if not paid by January 30, 2015 (the “Anticipated First Lien Default”), and (ii) the Company’s failure to pay to the Second Lien Lenders an interest installment in the amount of $7.9 million scheduled for payment on January 1, 2015, and constituting a default if not paid by February 2, 2015 (the “Anticipated Second Lien Default,” and, together with the Anticipated First Lien Default, the “Specified Defaults”).

The Company has received confirmation from the First Lien Lenders that they hold more than 75% of the principal amount of the outstanding Second Lien Notes and have each agreed, during the Forbearance Period (as defined below), not to provide any direction to the Second Lien Trustee or to take any steps to enforce any rights of the Second Lien Trustee or the holders of Second Lien Notes occasioned by the failure of the Company to make the January 1, 2015 interest payment.

Pursuant to the First Lien Forbearance Agreement, the First Lien Lenders agreed to forbear, until the earlier of March 16, 2015 or the occurrence of certain defaults defined in the First Lien Forbearance Agreement (the “Forbearance Period”), from exercising certain of their default-related rights and remedies against the Company with respect to the Specified Defaults in order to permit the Company an opportunity to effectuate a restructuring/refinancing or implement operational improvements.

Under the terms of the First Lien Forbearance Agreement, among other things, the Company agreed to (i) pay, by February 2, 2015, the December 31, 2014 interest payment owing to the First Lien Lenders, with interest at the default rate, in the amount of $1,378,650; (ii) pay expenses incurred by the First Lien Lenders in connection with the Forbearance Agreement, including paying a retainer to counsel for the First Lien Lenders; (iii) retain, by March 2, 2015, a financial advisor acceptable to the First Lien Lenders on terms acceptable to the First Lien Lenders; (iv) deliver to the First Lien Lenders a 6-week operating budget in form and methodology acceptable to the First Lien Lenders and to abide by that budget within permitted variances; (v) deliver to the First Lien Lenders, not later than March 2, 2015, certain financial, operating and other information and, not later than March 15, 2015, a two year business plan and 2015 budget; and (vi) cause its officers, financial advisors, investment bankers and others to furnish information reasonably requested by the First Lien Lenders.

Any breach by the Company of any covenant in the First Lien Forbearance Agreement, or the commencement of any bankruptcy, insolvency or creditor relief proceedings by or with respect to the Company, will constitute an event of default under the First Lien Forbearance Agreement.

Pursuant to the Second Lien Forbearance Agreement, the Second Lien Lenders agreed to forbear, during the Forbearance Period, from exercising certain of their default-related rights and remedies against the Company with respect to the Specified Defaults in order to permit the Company an opportunity to effectuate a restructuring/refinancing or implement operational improvements. Second Lien Forbearance Agreement is substantially identical to the First Lien Forbearance Agreement except that the January 1, 2015 interest payment on the First Lien Notes was not required to be made.

On March 16, 2015, the Company entered into amendments to the Forbearance Agreements extending the Forbearance Period to April 30, 2015

On April 30, 2015, the Company entered into amendments to the Forbearance Agreements extending the Forbearance Period to May 8, 2015 subject to a further extension of the Forbearance Period to May 11, 2015 if the Company paid an additional retainer to legal counsel for the First Lien Lenders in the amount of $200,000 and subject to a further extension of the Forbearance Period to May 22, 2015 if the Company appoints an additional independent director designated by the First Lien Lenders. The payment of an additional legal fee retainer and appointment of an additional director both occurred by the designated dates and the Forbearance Period was extended until May 22, 2015.

On May 18, 2015, the Company entered into further amendments to the Forbearance Agreements extending the Forbearance Period to June 5, 2015.

Appointment of Director

Pursuant to the terms of the April 30, 2015 amendment to the Forbearance Agreements, on May 11, 2015, the Company appointed an additional independent director to the Company’s board of directors and to the independent committee of the board.

Advisory Agreement

In March 2015, pursuant to the terms of the Forbearance Agreements, the Company entered into an engagement letter (the “Engagement Letter”) with Conway MacKenzie Management Services, LLC (“CMS”). Pursuant to the Engagement Letter, the Company appointed principals of CMS to the Interim Chief Financial Officer and Strategic Alternatives Officer positions. Those officers are engaged to assist the Company in connection with its efforts to restructure or repay the First Lien Notes and Second Lien Notes. The Company agreed to pay CMS a fee of $50,000 per month for services of the Interim Chief Financial Officer and hourly fees for services of other CMS personnel. The Engagement Letter was subsequently amended to provide that all services of CMS personnel, including the Interim Chief Financial Officer, would be billed at hourly rates.

NOTE 12 – COMMITMENTS AND CONTINGENCIES

Contingencies

From time to time the Company may become involved in litigation in the ordinary course of business. At June 30, 2015, except for the bankruptcy filing described in Note 1 and as described below, the Company’s management was not aware, and as of the date of this report is not aware, of any such litigation that could have a material adverse effect on its results of operations, cash flows or financial condition.

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of June 30, 2015, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company’s properties.

ITEM 2

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

Forward-Looking Information

This Form 10-Q quarterly report of Saratoga Resources, Inc. (the “Company”) for the three months ended June 30, 2015, 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, 2014.

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, 2014.

Chapter 11 Bankruptcy and Going Concern

On June 18, 2015, the Company and its subsidiaries, The Harvest Group, LLC, LOBO Operating, Inc., LOBO Resources, Inc. and Harvest Oil & Gas, LLC (together the “Debtors”) each filed a voluntary petition Chapter 11 in the United States Bankruptcy Court for the Western District of Louisiana (the “Bankruptcy Court”) to restructure our obligations and capital structure. The Chapter 11 cases are being jointly administered for procedural purposes by the Bankruptcy Court under the caption Harvest Oil & Gas, LLC, ET AL, Case No. 15-50748 (Jointly Administered).

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 approximately 51,500 acres at June 30, 2015, comprised of our principal producing properties covering approximately 31,700 acres in the transitional coastline and protected in-bay environment on parish and state leases of south Louisiana and approximately 19,800 acres of leases in the shallow Gulf of Mexico shelf.

At June 30, 2015, we operated or had interests in 105 producing wells and our principal properties covered approximately 51,500 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 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.

2015 Developments

Commodity Prices

During the six months ended June 30, 2015, we continued to be subject to a sharp decline in commodity prices that began during the second half of 2014 with average prices realized from the sale of crude being down to $51.39 per barrel during the six months ended June 30, 2015 as compared to $102.88 per barrel during the six months ended June 30, 2014 and average prices realized from the sale of natural gas being down to $2.99 per mcf during the six months ended June 30, 2015 as compared to $5.33 per mcf during the six months ended June 30, 2014.

Drilling and Development Activities

Drilling, development and infrastructure project operations to date in 2015 are summarized as follows:

Development Drilling. We did not drill any developmental wells during the six months ended June 30, 2015.

Exploratory Drilling. We did not drill any exploratory wells during the six months ended June 30, 2015.

Recompletion and Workover Program. During the six months ended June 30, 2015, we invested $0.5 million in four recompletions, two of which were successfully completed during the period and one of which was still in progress at quarter end, and an additional $0.1 million on two workovers, one of which was successfully completed during the period and one of which was still in progress at quarter end.

Infrastructure Program. During the six months ended June 30, 2015, we invested $0.3 million in infrastructure improvements and additions to support existing production and anticipated increases in production.

Drilling and Development Plans. We have an extensive inventory of drilling opportunities, including numerous proved behind pipe and proved undeveloped opportunities as well as a number of exploratory opportunities. With the drop in commodity prices we have put efforts to drill these prospects on hold. We expect to resume efforts to seek partners to drill at such time as commodity prices support such efforts.

For the six months ended June 30, 2015, we had approximately 105 gross, and 104 net, wells in production.

Compensation

During the six months ended June 30, 2015, we granted 30,000 stock options to an executive officer at an exercise price of $0.21 per share and a total of 105,000 stock options to three employees at exercise prices ranging from $0.21 to 0.27 per share.

We recorded $54,645 of compensation charges that is reflected in general and administrative expense for the six months ended June 30, 2015 and is attributable to equity grants during 2015 and prior years.

As of June 30, 2015, total compensation cost relating to unvested stock option awards not yet recognized in earnings was approximately $0.1 million, which is expected to be recognized over a weighted average period of approximately 0.5 years.

Operating Costs

During the six months ended June 30, 2015, we continued a program, begun during the fourth quarter of 2014, to decrease lease operating expenses and general and administrative expenses. Cost reduction measures have focused on bringing contract employees in-house, eliminating redundant positions, managing marine transportation, optimizing our chemical program, lowering communications costs, replacing/modifying our compressors, downsizing our Houston office, curtailing expenditures on certain longer term projects and tightening discretionary spending. Those cost cutting measures are targeted to reduce lease operating expenses and general and administrative expenses by $13.3 million (a 39% decrease), in the aggregate, during 2015 as compared to 2014. The anticipated cost reductions will be partially offset by additional legal fees, consulting and other expenses incurred pursuant to the Forbearance Agreements, our ongoing efforts to restructure/refinance existing debt, and the cost of the chapter 11 bankruptcy.

Forbearance Agreements

On January 30, 2015, we, along with our subsidiaries, Lobo Operating, Inc., Lobo Resources, Inc., Harvest Oil & Gas, LLC and The Harvest Group, LLC (collectively, the “Borrowers”) entered into a forbearance agreement (the “First Lien Forbearance Agreement”) with the holders (the “First Lien Lenders”) of certain notes (the “First Lien Notes”) issued under that certain Indenture dated as of November 22, 2013 (the “First Lien Indenture”), by and among the Borrowers and The Bank of New York Mellon Trust Company, N.A., as trustee (the “First Lien Trustee”). Also on January 30, 2015, the Borrowers entered into a forbearance agreement (the “Second Lien Forbearance Agreement” and, together with the First Lien Forbearance Agreement, the “Forbearance Agreements”) with the holders (the “Second Lien Lenders”) of seventy-five percent (75%) or more in principal amount of the notes (the “Second Lien Notes”) issued under that certain Indenture dated as of July 12, 2011 (as supplemented or amended, the “Second Lien Indenture”), by and among the Borrowers and The Bank of New York Mellon Trust Company, N.A., as trustee (the “Second Lien Trustee”).

The Forbearance Agreements were entered into following (i) the Borrower’s failure to pay to the First Lien Lenders an interest installment in the amount of $1.4 million scheduled for payment on December 31, 2014, and constituting a default if not paid by January 30, 2015 (the “Anticipated First Lien Default”), and (ii) the Borrower’s failure to pay to the Second Lien Lenders an interest installment in the amount of $7.9 million scheduled for payment on January 1, 2015, and constituting a default if not paid by February 2, 2015 (the “Anticipated Second Lien Default,” and, together with the Anticipated First Lien Default, the “Specified Defaults”).

We received confirmation from the First Lien Lenders that they hold more than 75% of the principal amount of the outstanding Second Lien Notes and have each agreed, during the Forbearance Period (as defined below), not to provide any direction to the Second Lien Trustee or to take any steps to enforce any rights of the Second Lien Trustee or the holders of Second Lien Notes occasioned by the failure of the Borrowers to make the January 1, 2015 interest payment.

Pursuant to the First Lien Forbearance Agreement, the First Lien Lenders agreed to forbear, until the earlier of March 16, 2015 or the occurrence of certain defaults defined in the First Lien Forbearance Agreement (the “Forbearance Period”), from exercising certain of their default-related rights and remedies against the Borrowers with respect to the Specified Defaults in order to permit the Borrowers an opportunity to effectuate a restructuring/refinancing or implement operational improvements.

Under the terms of the First Lien Forbearance Agreement, among other things, we agreed to (i) pay, by February 2, 2015, the December 31, 2014 interest payment owing to the First Lien Lenders, with interest at the default rate, in the amount of $1,378,650; (ii) pay expenses incurred by the First Lien Lenders in connection with the Forbearance Agreement, including paying a retainer to counsel for the First Lien Lenders; (iii) retain, by March 2, 2015, a financial advisor acceptable to the First Lien Lenders on terms acceptable to the First Lien Lenders; (iv) deliver to the First Lien Lenders a 6-week operating budget in form and methodology acceptable to the First Lien Lenders and to abide by that budget within permitted variances; (v) deliver to the First Lien Lenders, not later than March 2, 2015, certain financial, operating and other information and, not later than March 15, 2015, a two year business plan and 2015 budget; and (vi) cause our officers, financial advisors, investment bankers and others to furnish information reasonably requested by the First Lien Lenders.

Any breach by the Borrowers of any covenant in the First Lien Forbearance Agreement, or the commencement of any bankruptcy, insolvency or creditor relief proceedings by or with respect to the Borrowers, will constitute an event of default under the First Lien Forbearance Agreement.

Pursuant to the Second Lien Forbearance Agreement, the Second Lien Lenders agreed to forbear, during the Forbearance Period, from exercising certain of their default-related rights and remedies against the Borrowers with respect to the Specified Defaults in order to permit the Borrowers an opportunity to effectuate a restructuring/refinancing or implement operational improvements. Second Lien Forbearance Agreement is substantially identical to the First Lien Forbearance Agreement except that the January 1, 2015 interest payment on the First Lien Notes was not required to be made.

On March 16, 2015, we entered into amendments to the Forbearance Agreements extending the Forbearance Period to April 30, 2015.

On April 30, 2015, we entered into further amendments to the Forbearance Agreements extending the Forbearance Period to May 8, 2015 subject to a further extension of the Forbearance Period to May 11, 2015 if we paid an additional retainer to legal counsel for the First Lien Lenders in the amount of $200,000 and subject to a further extension of the Forbearance Period to May 22, 2015 if we appoint an additional independent director designated by the First Lien Lenders. The payment of an additional legal fee retainer and appointment of an additional director both occurred by the designated dates and the Forbearance Period was extended until May 22, 2015.

On May 18, 2015, the Company entered into further amendments to the Forbearance Agreements extending the Forbearance Period to June 5, 2015.

With our default in payment of interest as the same came due, since January 1, 2015, interest on the unpaid interest amounts on both our First Lien Notes and Second Lien Notes is accruing at the default rate, which is two percent higher than the stated rate of interest on each note.

Advisory Agreement

In March 2015, pursuant to the terms of the Forbearance Agreements, we entered into an engagement letter (the “Engagement Letter”) with Conway MacKenzie Management Services, LLC (“CMS”). Pursuant to the Engagement Letter, we appointed principals of CMS to the Interim Chief Financial Officer and Strategic Alternatives Officer positions. Those officers are engaged to assist in connection with our efforts to restructure or repay the First Lien Notes and Second Lien Notes. We agreed to pay CMS a fee of $50,000 per month for services of the Interim Chief Financial Officer and hourly fees for services of other CMS personnel. The Engagement Letter was subsequently amended to provide that all services of CMS personnel, including the Interim Chief Financial Officer, would be billed at hourly rates.

Independent Committee and Appointment of Director

In connection with our efforts to restructure our existing debt, our board established an independent committee charged with carrying out the restructuring process. Pursuant to the terms of the April 30, 2015 amendment to the Forbearance Agreements, on May 11, 2015, we appointed an additional independent director to our board of directors and to the independent committee of our board.

Results of Operations

Oil and Gas Revenue

Oil and gas revenue for the quarter ended June 30, 2015 decreased by 51.4% to $7.3 million from $15.1 million in the 2014 quarter. For the six month period ended June 30, 2015 oil and gas revenue decreased by 46.8% to $13.7 million from $25.7 million in the 2014 period.

For the quarter ended June 30, 2015, the decrease in revenue was attributable to a 51.6% decline in oil revenues on a 13.3% decrease in oil production volumes with average oil prices realized declining by 44.1% and a 50.0% decline in gas revenues on a 9.5% decrease in gas production volumes with average gas prices realized declining by 44.8%, each as compared to the 2014 quarter. For the six months ended June 30, 2015, the decrease in revenue was attributable to a 47.2% decline in oil revenues on a 50.0% decrease in average oil prices realized partially offset by a 5.6% increase in oil production volumes and a 42.6% decline in gas revenues on a 43.9% decrease in average gas prices realized partially offset by a 2.2% increase in gas production volumes, each as compared to the 2014 period.

The following table discloses the oil and gas sales revenues, net oil and natural gas production volumes and average sales prices for the three and six months ended June 30, 2015 and 2014:


	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Revenues
Oil	$	6,714,131	$	13,860,254	$	12,432,998	$	23,561,096
Gas		630,027		1,260,463		1,241,622		2,162,612
Total oil and gas revenues	$	7,344,158	$	15,120,717	$	13,674,620	$	25,723,708

Production
Oil (Bbls)		116,850		134,769		241,946		229,016
Gas (Mcf)		228,883		253,025		415,018		405,886
Total production (Boe)		154,997		176,940		311,116		296,664

Average sales price
Oil (per Bbl)	$	57.46	$	102.84	$	51.39	$	102.88
Gas (per Mcf)		2.75		4.98		2.99		5.33
Total average sales price (per Boe)	$	47.38	$	85.46	$	43.95	$	86.71

Oil production was down 17.9 MBbl, or 13.3%, and gas production was down 24.1 MMcf, or 9.5%, for the quarter ended June 30, 2015 as compared to the 2014 quarter. For the six months ended June 30, 2015, oil production was up 12.9 MBbl, or 5.6%, and gas production was up 9.1 MMcf, or 2.2%, as compared to the 2014 period. The decrease in production for the quarter was primarily due to flow line issues at the Grand Bay field which were resolved subsequent to the end of the quarter. The increase in production for the six month period was largely attributable to improved run times during the first quarter of 2015 as compared to the first quarter of 2014. Average run times and production rates during the first quarter of 2014 were negatively affected by elevated decline rates in certain high production wells, increased water-cut in selected wells, gas lift shortages, mechanical issues and flow line capacity constraints. Production optimization initiatives and infrastructure improvements undertaken throughout 2014 addressed the principal causes of the decreased run times, gas lift shortages, mechanical issues and flow line capacity constraints.

The decrease in realized oil and natural gas prices reflect the steep drop in global hydrocarbon prices during the second half of 2014. While prices stabilized during the first quarter of 2015, they remained at levels that were significantly lower than in the comparable period of 2014. In addition, prices have shown some weakening during the period subsequent to June 30, 2015.

Other Revenues

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

Operating Expenses

Operating expenses decreased by 8.5% to $10.1 million for the quarter ended June 30, 2015 from $15.6 million in the 2014 quarter. The following table sets forth the components of operating expenses for the 2015 and 2014 quarters:


	Three Months Ended				Three Months Ended
	June 30, 2015				June 30, 2014
	Total		Per Boe		Total		Per Boe
Lease operating expense	$	3,945,665	$	25.46	$	6,304,457	$	35.63
Workover expense		113,742		0.73		107,582		0.61
Exploration expense		19,223		0.13		200,298		1.13
Depreciation, depletion and amortization		2,653,807		17.12		4,507,996		25.48
Accretion expense		595,561		3.84		448,467		2.54
General and administrative		2,010,422		12.97		2,702,388		15.27
Severance taxes		751,700		4.85		1,309,592		7.40
	$	10,090,120	$	65.10	$	15,580,780	$	88.06

Operating expenses decreased by 24.9% to $20.0 million for the six months ended June 30, 2015 from $29.5 million in the 2014 period. The following table sets forth the components of operating expenses for the 2015 and 2014 periods:


	Six Months Ended				Six Months Ended
	June 30, 2015				June 30, 2014
	Total		Per Boe		Total		Per Boe
Lease operating expense	$	7,953,672	$	25.57	$	11,797,272	$	39.77
Workover expense		132,720		0.43		2,299,768		7.75
Exploration expense		38,321		0.12		421,650		1.42
Depreciation, depletion and amortization		5,402,201		17.36		7,250,055		24.44
Accretion expense		1,191,123		3.83		896,933		3.02
General and administrative		3,897,834		12.53		5,054,958		17.04
Severance taxes		1,331,904		4.28		1,810,342		6.10
	$	19,947,775	$	64.12	$	29,530,978	$	99.54

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

Lease Operating Expense

Lease operating expenses for the quarter ended June 30, 2015 decreased 37.4% to $3.9 million from $6.3 million in the 2014 quarter and, on a per BOE basis, decreased 28.5% to $25.46 per BOE from $35.63 per BOE, in the 2014 quarter. Lease operating expenses for the six months ended June 30, 2015 decreased 32.6% to $8.0 million from $11.8 million in the 2014 period and, on a per BOE basis, decreased 35.7% to $25.57 per BOE from $39.77 per BOE. The decrease in lease operating expenses was primarily due to (i) contract labor and repair and maintenance charges associated with our production optimization initiative that were included in lease operating expense for the 2014 periods (ii) one-time contract construction labor and building repair and maintenance expenses for the living quarters in Grand Bay Field incurred during 2014; and (iii) a reduction in our reliance on, and cost of, contract operating personnel. The decreases in lease operating expenses for the quarter and six months ended June 30, 2015 were partially offset by significant non-recurring expenses incurred during the quarter relating to (i) cleaning the sales line in the Breton Sound 32 field (ii) compressor station clean up at the Grand Bay field; and (iii) an overhaul of the compressor and 3 phase separator in the Breton Sound 18 field. We are negotiating reduced rates with many of our vendors and expect our lease operating expenses will continue to decrease if hydrocarbon prices continue to remain at lower levels during the remainder of the year.

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 decrease in lease operating expenses on a per BOE basis for the quarter was higher on a percentage basis than the overall decrease in lease operating expense primarily due to the increases in production volumes and the fixed nature of certain lease operating expenses.

Workover Expense

Workover expense for the quarter ended June 30, 2015 increased slightly to $113,742 from $107,582 in the 2014 quarter and decreased to $132,742 from $2,299,768 for the six months ended June 30, 2015 from the 2014 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 June 30, 2015 decreased to $19,223 from $200,298 in the 2014 quarter. Exploration expense for the six months ended June 30, 2015 decreased to $38,321 from $421,650 in the 2014 period. The decrease in exploration expenses was principally due to a reduction 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 June 30, 2015 decreased to $2,653,807 from $4,507,996 in the 2014 quarter and to $17.12 per BOE from $25.48 per BOE in the 2014 quarter. Depreciation, depletion and amortization for the six months ended June 30, 2015 decreased to $5,402,201 from $7,250,055 in the 2014 period and decreased to $17.36 per BOE from $24.44 per BOE in the 2014 period. The decreases in DD&A, on both an absolute dollar and a per BOE basis, were primarily due to a lower cost base as a result of impairments recorded during 2014.

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.

Accretion Expense

Accretion expense relating to our asset retirement obligations increased to $595,561 from $448,467 for the quarter ended June 30, 2015 as compared to the 2014 quarter and increased to $1,191,123 from $896,933 for the six months ended June 30, 2015 as compared to the 2015 period.

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

General and Administrative

General and administrative (“G&A”) expense for the quarter ended June 30, 2015 decreased 25.6% to $2,010,422 as compared to $2,702,388 in the 2014 quarter, and decreased 22.9% for the six months ended June 30, 2015 to $3,897,834 as compared to $5,054,958 in the 2013 period. The decreases in G&A expenses were primarily due to decreased legal and professional fees and a decrease in non-cash stock compensation expense.

Severance Taxes

Severance taxes for the quarter ended June 30, 2015 decreased to $751,700 from $1,309,592 in the 2014 quarter and decreased to $1,331,904 for the six months ended June 30, 2015 from $1,810,342 for the 2014 period. The decreases were primarily attributable to the declines in oil and natural gas revenues, which were partially offset by the fact that in 2014 we received refunds totaling $0.5 million for taxes paid in prior periods. We continue to receive the horizontal well severance tax exemptions for our Rocky and Zeke wells and the deep well severance tax exemption for our Mesa Verde well.

Other Income (Expense), Net

Net other expense increased to $7.8 million in for the quarter ended June 30, 2015 from $6.0 million for the 2014 quarter and increased to $16.3 million for the six months ended June 30, 2015 from $12.0 million in the 2014 period.

Interest expense reflects interest incurred on debt under our 10% First Lien Notes and 12.5% Second Lien Notes. The increases in interest expense were primarily attributable to an increase in the amortization of the debt discount and debt issuance costs associated with the notes as the amortization period was reduced to reflect the forbearance period and penalty interest accrued due to the non-payment of interest on the both the First and Second Lien Notes.

Income Tax Expense (Benefit)

For the quarter ended June 30, 2015 we recorded an income tax expense of $25,500 compared to $40,199 during the 2014 quarter. For the six months ended June 30, 2015 we recorded an income tax expense of $51,000 as compared to $122,265 for the 2014 period.

The decrease in income tax expense is primarily due to the fact that we expect lower state taxes during 2015 as a result of decreased revenues.

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 2014 and 2015 we funded operations out of operating cash flow and cash on hand. We did not have access to available capital under a revolving credit agreement and do not at this time have a revolving credit facility.

We developed, and beginning in 2011 commenced, a layered, multi-faceted development and maintenance program designed to achieve short-, mid- and long-term objectives. Short-term objectives are focused on restoration of shut-in and curtailed production through investments in infrastructure and deferred maintenance and recompletions, workovers and thru-tubing plugbacks each designed to increase or restore production volumes from wells producing below capacity and an inventory of proved developed nonproducing opportunities. Mid-term, following or in conjunction with execution of short-term opportunities, our focus is on the development of an inventory of proved undeveloped opportunities within our inventory of proved undeveloped wells targeting normally pressured oil and gas. Long-term, following or in conjunction with the execution of our short- and mid-term opportunities, our focus is on continuing development of our reserves and exploratory drilling of deep shelf opportunities. During 2014, while continuing to advance short-term objectives associated with continual investment in our infrastructure, we focused on our mid-term objectives through drilling proved undeveloped opportunities.

As a result of sharply lower commodity prices, and resulting operating losses and declines in cash flows, our liquidity position deteriorated substantially during 2014 and the first six months of 2015. In late 2014, we began implementing cost cutting measures and curtailed development of our proved undeveloped opportunities in favor of building our cash position to, among other things, support our scheduled payments of interest on outstanding debt and support basic operations in a low commodity price environment. In January 2015, we entered into forbearance agreements with our lenders, paying only the interest on first lien indebtedness but not paying interest on second lien indebtedness and, in June 2015, we filed for Chapter 11 bankruptcy protection. We are presently working with our lenders and with prospective financing sources to add liquidity and/or refinance our debt. Our cash on hand at June 30, 2015, together with operating cash flows, is expected to be adequate to support basic operations and maintenance but, absent increased commodity prices and/or production, is not expected to be adequate to support development activities or debt service obligations over the next twelve months. We are presently using cash on hand pursuant to a consensual cash collateral order. Our ability to continue to support operations is subject to ongoing use of cash collateral or securing financing to support operations and exit from bankruptcy. We do not presently have any commitments to provide financing and there is no assurance that any additional financing will be provided on acceptable terms or at all. Should we be unable to reach acceptable accommodations with our lenders to facilitate a satisfactory reorganization and/or are unable to secure additional financing to support operations, generally, and development of our assets, specifically, we may face any number of adverse consequences (including, among others, possible foreclosure of assets, substantial dilution or elimination of equity, liquidation, lack of financial resources to support operations) that could threaten our ability to continue as a going concern.

Cash, Cash Flows and Working Capital

We had a cash balance of $5.4 million and a working capital deficit of $196.9 million at June 30, 2015 as compared to a cash balance of $10.9 million and a working capital deficit of $185.7 million at December 31, 2014. The decrease in cash on hand was primarily attributable to reductions in operating cash flow and investments in our development program. The decrease in our working capital was primarily attributable to an increase in accrued interest on our First and Second Lien notes which was partially offset by the transfer of unsecured amounts relating to the period prior to the filing of Chapter 11 bankruptcy out of current liabilities.

Operations used cash flow of $2.1 million for the six months ended June 30, 2015 as compared to using cash of $7.3 million for the six months ended June 30, 2014. The change in operating cash flows during 2014 was principally attributable to reduced profitability resulting from lower commodity prices and changes in our operating assets and liabilities.

Investing activities used cash totaling $2.8 million during the six months ended June 30, 2015 as compared to $6.4 million used during the 2014 period. The decrease in cash used in investing activities was primarily due a reduction in development activities.

Financing activities used cash flows of $0.6 million during the six months ended June 30, 2015 as compared to $0.5 million during the 2014 period. Cash flows used by financing activities during both periods primarily related to repayments on our short-term notes payable.

Debt

At June 30, 2015, we had $179.8 million of indebtedness outstanding, consisting of $54.6 million in face amount of 10% First Lien Notes and $125.2 million in face amount of 12½% Senior Secured Notes due 2016.

We had no letters of credit outstanding at June 30, 2015 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.

In January 2015, we entered into forbearance agreements with respect to both the First Lien Notes and the Second Lien Notes and were in default under those notes, including being default on the payment of interest owing as of January 1, 2015 with respect to the Second Lien Notes in the amount of $7.8 million.

In March 2015, we entered into amendments to the forbearance agreements which extended the forbearance period to April 30, 2015.

In April 2015, we entered into further amendments to the forbearance agreements which extended the forbearance period to May 22, 2015.

On May 18, 2015, we entered into further amendments to the Forbearance Agreements extending the Forbearance Period to June 5, 2015.

Capital Expenditures and Commitments

Our capital spending for the six months ended June 30, 2015 was $0.9 million relating primarily to development of our oil and gas properties, including four recompletions ($0.5 million), two workovers ($0.1 million) and investments in multiple infrastructure projects ($0.3 million). Capital expenditures were down from $12.7 million during the 2014 period.

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.

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. At June 30, 2015 we had no hedge contracts outstanding.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements or guarantees of third party obligations at June 30, 2015.

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 June 30, 2014, we had no hedge contracts outstanding.

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

Interest Rate Risk

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

ITEM 4

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Under the supervision and the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation as of June 30, 2015 of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were not effective as of June 30, 2015.

Changes in Internal Control over Financial Reporting

No change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) occurred during the quarter ended June 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II

ITEM 6

EXHIBITS


Exhibit No.		Description

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

SIGNATURES

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


	SARATOGA RESOURCES, INC.
Date: August 19, 2015
	By:	/s/ Thomas Cooke
		Thomas Cooke
		Chief Executive Officer

	By:	/s/ Randal B. McDonald, Jr.
		Randal B. McDonald, Jr.
		Vice President –Finance and Accounting