Exhibit 99.1

For Immediate Release

Contacts:

Brad Holmes, Investor Relations (713) 654-4009; or Andrew Clifford, President (713) 458-1560; or Michael Aldridge, CFO (713) 458-1560

Website:

wwwžsaratogaresourcesžcom

SARATOGA RESOURCES, INC. REPORTS SECOND QUARTER 2013

FINANCIAL RESULTS

Houston, TX – August 9, 2013 – Saratoga Resources, Inc. (NYSE MKT: SARA; the “Company” or “Saratoga”) today announced financial and operating results for the quarter ended June 30, 2013.

Key Financial Results

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Oil revenue of $15.8 million for Q2 2013 compared to $21.5 million for Q2 2012;

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Gas revenue of $1.9 million for Q2 2013 compared to $2.3 million for Q2 2012;

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Discretionary cash flow of $3.8 million, or $0.12 per fully diluted share, for Q2 2013 compared to discretionary cash flow of $8.8 million, or $0.30 per fully diluted share, for Q2 2012;

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EBITDAX of $8.7 million for Q2 2013 compared to $13.4 million for Q2 2012;

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Operating income of $1.9 million, or $0.06 per fully diluted share, for Q2 2013 compared to operating income of $5.8 million, or $0.20 per fully diluted share, for Q2 2012; and

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Net loss of $(2.3) million, or $(0.07) per fully diluted share, for Q2 2013 compared to net income of $0.9 million, or $0.03 per fully diluted share, for Q2 2012.

Discretionary cash flow and EBITDAX are non-GAAP financial measures and are defined and reconciled to the most directly comparable GAAP measure under “Non-GAAP Financial Measures” below.

Total revenues declined 21.6% from the second quarter of 2012 to the second quarter of 2013.  The decline in total revenues reflects a 25.5% decline in oil and gas revenue and a 77.4% decline in other revenues partially offset by hedging gains of $1.1 million, associated with the reinstitution of our hedging program beginning late in 2012. The decline in other revenues was principally due to the loss of a net profits interest in Breton Sound 31 and non-renewal of production handling agreements which were in effect in the second quarter 2012.

Oil production was down 21.2% from the second quarter of 2012 to the second quarter of 2013, while gas production was down 43.5% over the same period. This decrease was primarily attributable to production declines in our Main Pass 25, Main Pass 46 and Grand Bay fields, which declines were attributable to a combination of mechanical, third party handling, flow line and gas lift issues, among others, and natural reservoir declines discussed more fully below.

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Average realized prices per barrel of oil equivalent were $78.62, up 6.4% quarter over quarter, primarily attributable to a 43.6% increase in natural gas prices realized partially offset by a 6.3% decline in crude oil prices realized.  While oil and gas revenues continued to benefit from premiums to WTI pricing attributable to LLS and HLS pricing for our oil production, prices realized reflected a general strengthening of natural gas prices and general moderation in oil prices during the quarter.

The decrease in operating income for the quarter reflects a $5.2 million decline in revenues partially offset by a $1.4 million decline in total operating expenses. The decline in operating expenses was principally attributable to lower workover expense (down $0.9 million, or 43.5%) due to decreased workover activity, zero plugging and abandonment expenses (down $0.9 million, or 100%) due to one-time P&A projects undertaken in the 2012 quarter, and a decline in severance taxes expense (down $0.3 million, or 13.3%).  Those decreases were partially offset by higher lease operating expense (up $0.5 million, or 10.4%) primarily due to nonrecurring cost of barge removal in the Little Bay Field. Exploration, DD&A, accretion, and general and administrative expenses increased slightly by $0.02 million, $0.09 million, $0.08 million and $0.011 million, respectively, (up $0.2 million, or 2.3%).

The net loss for the 2013 quarter reflected the decrease in operating income together with higher interest cost (up $1.0 million), as a result of our add-on note offering closed in late 2012 and partially offset by increased tax benefit (up $1.6 million).

Operational Highlights

Operational highlights for second quarter 2013 included:

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9 recompletions undertaken, of which 4 were successful and 5 were in progress at quarter end, including 8 wells in our tubing replacement program, of which 4 were in progress at quarter end;

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4 successful workovers completed, including 1 well in our tubing replacement program;

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105 gross (104 net) wells in production at June 30, 2013;

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32,219 gross/net acres in 12 fields under lease at June 30, 2013; and

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Submitted bids on four lease blocks covering 19,814 acres in the shallow GOM water which we acquired in July 2013, increasing our total leasehold to 52,033 acres.

During Q2 2013, we undertook 9 recompletions, 4 of which were successful and 5 were still in progress at quarter end, and 4 workovers, all of which were successful, the majority of which were included in our tubing replacement program.

Production Highlights

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Oil and gas production of 154 thousand barrels of oil (“MBO”) and 430 million cubic feet of gas (“MMCFG”), or 225 thousand barrels of oil equivalent (“MBOE”) (68.1% oil), in Q2 2013, down 30% from 322 MBOE (60.6% oil) in Q2 2012 and down 2% from Q1 2013;

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Oil and gas production of 311 MBO of oil and 874 MMCFG of gas, or 456 MBOE, for the 2013 six months period, down 20.8% from 576 MBOE (60% oil) for the 2012 six month period; and

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Substantial portions of the production decline were attributable to mechanical, gas lift, temporary interruptions associated with projects and related issues that are subject to possible resolution.

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

Partially offsetting the curtailment in production from the Main Pass 25 Field, Grand Bay Field and Main Pass 46 Field were additions to production attributable to new wells added through our development drilling program since Q2 2012 with Breton Sound 18 Field production increasing by 33 MBOE, or 311.3%, from Q2 2012 level.

Reserve Highlights

In addition to reserves associated with existing holdings, during the Q3 2013, we were awarded four leases totaling 19,814 acres in the Central Gulf of Mexico.  Preliminary unaudited resource potential for those leases has been estimated internally as 51.3 MMBOE, of which 5.4 MMBOE may be qualified as proved undeveloped reserves.

Development Plans

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Low risk recompletions, thru-tubing plugbacks and workovers from inventory of approximately 60 proved developed non-producing (“PDNP”) opportunities in 7 fields;

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Development of proved undeveloped (“PUD”) reserves from inventory of approximately 84 PUD opportunities in 26 wellbores in 4 fields;

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SL 1227-25 ”Rocky” well drilled with 750’ horizontal lateral in Breton Sound 32 field;

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Zeke well spud in August 2013;

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Production enhancement program (“PEP”) initiated to restore curtailed and shut-in production from inventory of approximately 20 wells in Grand Bay and Breton Sound 32 fields; 9 wells in PEP program completed to date;

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Main Pass 25 facilities upgrade program completed; and

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Strategic partnerships and joint ventures for risk-sharing on exploratory drilling of deep and ultra-deep prospects at Grand Bay and Vermilion 16 and on new Central Gulf of Mexico leases.

Our near term development plans are focused on proved undeveloped opportunities and conversion of PDNP opportunities. One PUD well, “Rocky”, was being drilled during the latter half of Q2 2013 and subsequently completed in Q3 2013 and is presently awaiting hook up and testing. We plan to drill two to three more wells during the remainder of 2013, including the Zeke well which spud in August, and five to six development wells annually thereafter.

The SL 1227-25 “Rocky” well was being drilled during Q2 2013 using the Parker 77B inland barge rig. An initial 70-degree directional pilot hole was drilled to the target 5800’ sand then plugged back before drilling a sidetrack well with a horizontal leg giving a 750’ lateral into the reservoir. The estimated completed well cost is less than $7 million. This is Saratoga’s first horizontal well. The Rocky well has been completed and awaiting hook up and testing and is expected to be in production during the Q3 2013.

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The SL 1227-26 “Zeke” PUD well, also in Breton Sound 32 field, was spud in August 2013. The Zeke well is being drilled as an 81-degree directional well targeting the 5800’sand.  There are several other horizontal completion opportunities under evaluation, including Charlie, also in the same Breton Sound 32 field, and other opportunities in Grand Bay field.

Our PEP program, which involves tubing replacement work, recompletions, workovers, gas lift optimization and gravel pack remediation in Grand Bay and Breton Sound 32 fields, began on May 27, 2013 and is on track with 9 wells done to date, of which 7 were tubing replacements, one well involved adding sand control, and one through tubing plugback. Additional perforations are being added to four of the PEP wells. We expect rates to increase after adding the additional perforations. While we continue to evaluate candidates for inclusion in our PEP program and have numerous additional candidates identified, additional investment in the program is being temporarily deferred in favor of prioritizing capital investment in higher potential impact projects such as our Rocky and Zeke wells.  We expect to resume projects in our PEP program as project economics dictate.

In Main Pass 25 Field, we completed a facilities upgrade project during the second quarter.  The project is intended to allow us to assume production handling, increase gas lift gas and reduce line pressures to eliminate third party handling issues and gas lift gas shortages that substantially curtailed our production in Main Pass 25 during the first half of 2013 and to allow us to ultimately increase production in Main Pass 25.  In conjunction with the Main Pass 25 facilities upgrade, we entered into an arrangement with a third party operator pursuant to which that operator provided certain equipment and we will handle production from a new discovery in the field by the third party operator.  That arrangement and the facilities upgrade adds production handling capacity at our Main Pass 25 facilities which is expected to allow us to generate production handling revenues from the other operator, bring our production from the field handled by a third party back to Main Pass 25 and reduce monthly operating costs in the field while lowering line pressures and potentially increasing production in that field while adding a potential source of additional gas lift gas.  While the facilities upgrade is now substantially complete and operational, we are still undertaking efforts to lower line pressures to accommodate desired increases in production.

In July 2013, we received final award of 4 Gulf of Mexico leases, covering 19,000+ acres, by the Bureau of Ocean Energy Management. We intend to seek partners to drill, develop and operate those prospects in the Central Gulf of Mexico. We also intend to initiate an effort to find joint venture partners to share risk on deeper objectives under Grand Bay field below 12,000 feet with a view to drilling the first deep well to a depth of at least 15,000 feet either in Q4 2013 or Q1 2014 and continue to monitor ongoing exploratory drilling operations of ultra-deep prospects near our lease holdings and to conduct discussions with potential partners regarding the development of our ultra-deep prospects.

Financial Position and CAPEX Highlights

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$30.2 million of cash on hand at June 30, 2013, up from $22.0 million at March 31, 2013;

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$18.0 million of working capital at June 30, 2013, down from $18.6 million at March 31, 2013;

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$5.1 million of CAPEX for Q2 2013 (including $1.4 million acquisition of Gulf of Mexico Shelf acreage);

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$12.8 million CAPEX budgeted for balance of 2013;

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2013 CAPEX budget fully funded by cash on hand and projected operating cash flow;

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Working capital adjusted debt to trailing twelve month EBITDAX of 3.2 times; and

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Net asset value per share of approximately $9 at year-end 2012 based on SEC proved reserves alone.

We continued to fund our operations, including our development program, from cash on hand and operating cash flows.  The 2013 CAPEX budget is expected to be fully funded from cash on hand and operating cash flow.

Management Comments

Thomas Cooke, Chairman and CEO, commented, “As we anticipated, our Q2 2013 production was virtually flat to Q1 2013. However, despite our frustration caused by delays in getting our projects started and completed and the effects of various issues that adversely effected our production for the quarter, our cash balance at the end of Q2 2013 has grown from the end of the first quarter.  Our development drilling program and the production enhancement program, or PEP, are just now showing positive results and we are confident that mechanical, gas lift and third party issues affecting our production are being resolved. We expect these results to be evident in the second half of Q3 2013 and oil volumes are expected to increase significantly towards the end of the 3^rd quarter and through the 4^th quarter because of resolution of these bottlenecks, results from our PEP work and new production expected to come from our drilling at Breton Sound 32 field.

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With our focus on oil and the continued high prices on LLS and HLS crude, we may have taken our eye off the ball a bit as natural reservoir declines caught us short on gas-lift gas that resulted in lower oil volumes. In this regard, we have re-prioritized our near-term gas projects to ensure adequate supply for gas lift operations. We have a deep inventory of opportunities and these are some of the least expensive recompletions in our portfolio.

In our PEP program, with 9 wells completed to date, we have spent less than $3 million with an estimated cost of finding and development of $13.69/BOE and an expected payout of less than 6 months on a project basis, both of which are expected to improve with additional perforations planned on 4 wells. We estimate that 215,000 net BOE has been moved from proved developed shut-in and proved developed behind pipe reserve categories to proved developed producing so far from the PEP program. We are currently evaluating the results from Phase 1 and focusing our capex on higher impact projects before proceeding to Phase 2.

In Main Pass 25 field, we had been experiencing production curtailments resulting from third-party handling issues and a temporary lack of gas lift. We successfully recompleted a gas sand in one the SL 16432-11 well during the 1^st quarter in order to address our gas needs. In order to address third party handling issues, we commenced a facilities upgrade program in the field. We have now completed the installation of the Main Pass 25 facility expansion project, including a 4-pile jacket and deck, and an oil storage barge, which will handle production from the field, is now in place and moored adjacent to the newly-installed jacket. This facility upgrade project is designed to allow lower system operating pressure, which is expected to result in increased well productivity in the field. The facilities upgrade is also expected to allow us to handle additional third party production and add gas supply for gas lift, while reducing operating costs through direct cost savings and cost sharing for common use systems. We are currently balancing back pressures in the field and expect to see improved performance in Q3 2013.

Our recently re-initiated field study program is making great progress and is yielding dividends in identifying more impactful drilling prospects.  Highlighting those prospects is our recently drilled the SL 1227-25 “Rocky” well, our first horizontal well, which was spud on June 30^th. We drilled a directional pilot well to a TD of 6254’ MD/5858’ TVD, as planned, before plugging back and drilling a sidetrack with a 750’ lateral section to a TD of 7178’ MD/5790’ TVD and reached our objective on July 24. The well was subsequently completed and the rig moved to our Zeke location in the same field on August 3^rd. The Rocky well final cost is expected to be below our pre-drill AFE of $7 million. The SL 1227-26 “Zeke” well was spud on August 5^th and is drilling ahead with a proposed TD of 6347’ MD/5821’ TVD. This well is an 81 degree directional well. Both wells are targeting the same 5800’ sand in the eastern portion of Breton Sound 32 field. We would expect to have both wells in production within Q3 2013 and are evaluating other drilling candidates such as the Charlie well, also in Breton Sound 32 field.

We have recently added several key operational positions in our Covington, Louisiana office. These staff additions are expected to enhance our ongoing evaluation of existing assets through new and comprehensive field studies and evaluation of accretive acquisition opportunities to supplement organic growth. The addition of these very experienced professionals is expected to help us further our ongoing field study efforts of existing properties, manage the recently acquired shallow Gulf assets and identify and evaluate accretive acquisition opportunities. While the field studies themselves are exciting and expected to yield new development opportunities and reserves, the additional resources will help us manage our new prospects and seek joint venture partners that can bring these opportunities to fruition. The deeper Grand Bay prospects have been enhanced by our recent 3-D seismic reprocessing. Furthermore, we are continually looking to high-grade in-field development opportunities and the additional staff will greatly assist us in this regard.

We have now officially been awarded the four leases in the Gulf of Mexico.  These four blocks are all located in the shallow Gulf of Mexico Shelf with water depths between 13 and 77 feet. Existing production facilities are abundant in these areas and we anticipate this will shorten our time and lower our cost to bring production to market and improve well economics on these projects. The four leases combined add 19,814 acres, gross and net. Most important, our internal estimates relative to these blocks, as yet not audited by third party reserve engineers, are 51.2 million gross barrels of oil equivalent potential resources of which we believe 5.4 million gross barrels equivalent may qualify as PUD’s. We were attracted by the high liquid content of these reserves, which we estimate may exceed 8 million gross barrels of oil in 3P reserves. There are several prospects already identified in the blocks in normally-pressured target reservoirs shallower than 15,000 feet, all generated using high-quality 3D seismic data. Lease bonus payments total $880,000 with first year rentals of $138,000, a price that we view very favorably relative to our estimate of resource potential for the prospects. The blocks include 100% working interest in each lease with 77% net revenue interests. Our plan is to seek joint venture partners with first drilling expected in 2014.

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About Saratoga Resources

Saratoga Resources is an independent exploration and production company with offices in Houston, Texas and Covington, Louisiana. Principal holdings cover 52,033 gross/net acres, mostly held by production, located in the transitional coastline and protected in-bay environment on parish and state leases of south Louisiana and shallow Gulf of Mexico Shelf. Most of the company's large drilling inventory has multiple pay objectives that range from as shallow as 1,000 feet to the ultra-deep prospects below 20,000 feet in water depths ranging from less than 10 feet to a maximum of approximately 80 feet. For more information, go to Saratoga's website at www.saratogaresources.com and sign up for regular updates by clicking on the Updates button.

Forward-Looking Statements

This press release includes certain estimates and other forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, including, but not limited to, statements regarding future ability to fund the company’s development program and grow reserves, production, revenues and profitability, ability to reach and sustain target production levels, ability to secure commitments to participate in exploration of deep shelf prospects, ability to secure leases and the ultimate outcome of such efforts. Words such as "expects”, "anticipates", "intends", "plans", "believes", "assumes", "seeks", "estimates", "should",  and variations of these words and similar expressions, are intended to identify these forward-looking statements. While we believe these statements are accurate, forward-looking statements are inherently uncertain and we cannot assure you that these expectations will occur and our actual results may be significantly different. These statements by the Company and its management are based on estimates, projections, beliefs and assumptions of management and are not guarantees of future performance. Important factors that could cause actual results to differ from those in the forward-looking statements include the factors described in the "Risk Factors" section of the Company's filings with the Securities and Exchange Commission. The Company disclaims any obligation to update or revise any forward-looking statement based on the occurrence of future events, the receipt of new information, or otherwise.

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Non-GAAP Financial Measures

Discretionary Cash Flow is a non-GAAP financial measure.

The company defines Discretionary Cash Flow as net income (loss) before income tax expense (benefit), interest expense and depreciation, depletion and amortization excluding interest income, realized gains on out-of-period derivative contract settlements, (gain) loss on the sale of assets, acquisition costs, settlements for prior claims, other various non-cash items (including asset impairments, income from equity investments, stock-based compensation, unrealized (gain) loss on derivative contracts and provision for doubtful accounts), exploration and dry hole costs and costs associated with the company’s bankruptcy.

Discretionary Cash Flow is a supplemental financial measure used by the company’s management and by securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of the company’s ability to internally fund exploration and development activities. Discretionary cash flow should not be considered as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with generally accepted accounting principles (“GAAP”). Discretionary cash flow excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, the company’s Discretionary Cash Flow may not be comparable to similarly titled measures used by other companies.

The table below reconciles the most directly comparable GAAP financial measure to Discretionary Cash Flow:

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EBITDAX is a non-GAAP financial measure.

The company defines EBITDAX as net income (loss) before income tax expense (benefit), interest expense and depreciation, depletion and amortization excluding interest income, realized gains on out-of-period derivative contract settlements, (gain) loss on the sale of assets, acquisition costs, settlements for prior claims, other various non-cash items (including asset impairments, income from equity investments, noncontrolling interest, stock-based compensation, unrealized (gain) loss on derivative contracts and provision for doubtful accounts), exploration and dry hole costs and costs associated with the company’s bankruptcy.

EBITDAX is a supplemental financial measure used by the company’s management and by securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of the company’s ability to internally fund exploration and development activities and to service or incur additional debt. The company also uses this measure because EBITDAX allows the company to compare its operating performance and return on capital with those of other companies without regard to financing methods and capital structure. EBITDAX should not be considered as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with generally accepted accounting principles (“GAAP”). EBITDAX excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, the company’s EBITDAX may not be comparable to similarly titled measures used by other companies.

The table below reconciles the most directly comparable GAAP financial measure to EBITDAX:

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