Saratoga Resources, Inc. (NYSE MKT:SARA; the “Company” or “Saratoga”) today announced financial and operating results for the quarter ended June 30, 2014.

Key Financial Results

• Oil and gas revenues of $15.1 million for Q2 2014 compared to $10.6 million for Q1 2014;
• Discretionary cash flow of $(0.5) million, or $(0.01) per fully diluted share, for Q2 2014 compared to discretionary cash flow of $(5.2) million, or $(0.17) per fully diluted share, for Q1 2014;
• EBITDAX of $4.8 million for Q2 2014 compared to $0.1 million for Q1 2014;
• Operating loss of $(0.6) million, or $(0.02) per fully diluted share, for Q2 2014 compared to operating loss of $(2.2) million, or $(0.07) per fully diluted share, for Q1 2014; and
• Net loss of $(6.7) million, or $(0.21) per fully diluted share, for Q2 2014 compared to net loss of $(8.3) million, or $(0.27) per fully diluted share, for Q1 2014.

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.

The decrease in net loss in Q2 2014 as compared to Q1 2014 reflects a 42.6% increase in oil and gas revenues while operating expenses increased 11.7%. The change in revenues quarter-over-quarter reflects an increase in production volumes (up 47.8% in aggregate; up 43.1% for oil; up 65.5% for natural gas) partially offset by lower average realized commodity prices (down 3.5%; oil pricing flat; natural gas pricing down 15.6%). The increase in production was attributable to increased average run-time, up to 77% for Q2 (80% in June) versus Q1 average run time of 61% (54% for January and February), drilling at Breton Sound Block 32 (Rocky 3), and recompletions at Grand Bay and Vermilion Block 16. During the first half of 2014, extensive changes in field operating personnel and in our Covington office personnel were undertaken, a new flow line was added and other field operating issues were addressed and production rates rebounded late in the quarter and following quarter end. The increase in production was partially offset by natural declines.

Operating expenses for Q2 2014 were up 11.7% from Q1 2014 levels. The increase in operating expenses quarter-over-quarter reflected increases in depreciation, depletion and amortization expense (up $1.8 million; or 64.4%), severance taxes (up $0.8 million; or 161.5%), lease operating expense (up $0.8 million; or 14.8%) and general and administrative expense (up $0.35 million; or 14.9%). Partially offsetting those increases was a reduction in workover expense (down $2.1 million; or 95.1%). The increases in DD&A and severance taxes relate principally to higher production volumes and, with respect to severance taxes, a severance tax refund during Q1 2014. The increase in lease operating expense was principally attributable to increased contract labor and repairs and maintenance expenses incurred in connection with our efforts to resolve field operating issues that had resulted in declines in average run time.

Operational Highlights

Operational highlights for second quarter 2014 included:

• Drilled and successfully completed Rocky 3 horizontal well;
• 3 recompletions successfully completed; 2 workovers in progress at June 30, 2014;
• 104 gross/net wells in production at June 30, 2014;
• Additional flow line to support added production from Rocky 3 well substantially completed;
• Prepared for compressor installation and infrastructure repairs at Grand Bay field for late July implementation;
• Continued exhaustive review, personnel changes and investments in facilities repairs and maintenance to address run time and field operating issues; and
• Approximately 52,000 gross/net acres under lease at June 30, 2014, including approximately 32,000 acres in 13 fields in the transitional coastline and protected in-bay environment on parish and state leases in south Louisiana and approximately 20,000 acres in the shallow Gulf of Mexico shelf.

During Q2 2014, we successfully drilled, completed and brought on line our Rocky 3 horizontal well in Breton Sound 32 field. The well was produced during the quarter well below tested capacity due to flow line constraints. During Q2 2014, we undertook 3 recompletions and 2 workovers. All of the recompletions were successful and the workovers were in progress at June 30, 2014 and were successfully completed following the quarter end. Two of the principal wells in the recompletion/workover program were gas objectives that were able to add significant gas supply to support field wide gas lift needs.

During Q2 2014, we commenced construction of an additional flow line in Breton Sound 32 to support new production from our Rocky 3 well along with existing production in the field. The flow line was completed and came on line in early July 2014. Also during July we were able to add compression capacity and make several infrastructure repairs at Grand Bay field, which should materially increase run-time and correct operational inefficiencies. We also made additional changes in personnel and investments in facilities in a continuation of our exhaustive review of field operations, commenced in Q1 2014, to address run time issues experienced in the second half of 2013 and into the first quarter 2014. Our management team continues to closely monitor field operations.

Production Highlights

• Oil and gas production of 134.8 thousand barrels of oil (“MBO”) and 253 million cubic feet of gas (“MMCFG”), or 176.9 thousand barrels of oil equivalent (“MBOE”) (76% oil) in Q2 2014, up 47.8% from 119.7 MBOE (79% oil) in Q1 2014;
• Rocky 3 well brought onto production at curtailed rate pending addition of flow line capacity;
• Added flow line in July 2014 to eliminate production capacity constraints in Breton Sound 32;
• Installed compression and made infrastructure repairs at Grand Bay field in late July 2014; and
• Following flow line construction, addition of gas lift gas supply, and production optimization initiatives undertaken during Q1 and Q2, average run times increased to approximately 77% in Q2 2014 (80% in June), up from 61% in Q1 2014 (54% in January and February 2014) and daily production rates reached an average of 1,944 BOEPD over Q2 2014 as compared to 1,330 BOEPD in Q1 2014.

The increase in production reflects overall 77% run time during Q2 2014 up from 61% in the prior quarter resulting from a focus on assuring adequate gas lift gas supply through gas-weighted workovers and recompletions together with the execution of a gas buy back agreement with an area operator, and personnel changes made in the field and the Covington office. Production volumes were also enhanced by the drilling, completion, and initiation of production from Rocky 3 on May 28, 2014 in Breton Sound Block 32 and the aforementioned recompletions at Grand Bay and Vermilion 16. Production increases were partially offset by natural decline in existing wells. With the addition of flow line capacity in Breton Sound 32 and compression optimization at Grand Bay field in Q3 2014, production rates have continued to improve.

Development Plans

• Low risk recompletions, thru-tubing plugbacks and workovers from inventory of approximately 62 proved developed non-producing (“PDNP”) opportunities in 6 fields;
• Development of proved undeveloped (“PUD”) reserves from inventory of approximately 95 PUD opportunities in 24 wellbores in 5 fields;
• Q3 focused on targeted recompletions, workovers and other projects with objective of further growing legacy well production rate;
• Reservoir simulations in Breton Sound 32 ongoing to identify additional horizontal prospects;
• Development drilling targeted to resume in Q4 2014/Q1 2015;
• Strategic partnerships and joint ventures for risk-sharing on exploratory drilling of deep prospects at Grand Bay and on Central Gulf of Mexico leases; and
• Commenced rollout of formal marketing program to prospective participants in initial Grand Bay deep prospect; formal marketing program for initial Gulf of Mexico prospects expected to commence before year-end 2014.

Our near term development plans during Q3 2014 are expected to be focused on workovers, recompletions and other opportunities to enhance production from our legacy wells.

We will look to resume our development drilling program following the peak of the Gulf hurricane season in Q4 2014 or Q1 2015 and are conducting exhaustive geological and engineering reviews, including reservoir simulations in Breton Sound 32 to identify additional horizontal prospects, to bring forward the most promising of our available prospects.

After exhaustive efforts, in house and outside the company, we completed packaging of geological, engineering, marketing and related materials to commence, and have commenced, a professional marketing presentation to prospective joint venture partners for the Goldeneye prospect, the first of our deep prospects in Grand Bay Field. Packaging of the first of our Gulf of Mexico prospects is in the final stages and we expect to commence a formal marketing program to prospective partners before year-end 2014.

Financial Position and CAPEX Highlights

• $18.3 million of cash on hand at June 30, 2014, down from $32.5 million at December 31, 2013;
• $4.6 million of working capital at June 30, 2014, down from $20.4 million at December 31, 2013;
• $9.1 million of CAPEX for Q2 2014; and
• Working capital adjusted debt to trailing twelve month EBITDAX of 10.9 times.

Saratoga continued to fund its operations, including its development program, from cash on hand and operating cash flows. The 2014 CAPEX budget is expected to be fully funded from cash on hand and operating cash flow.

Management Comments

Thomas Cooke, Chairman and CEO, commented, “Q2 2014 was a productive quarter as we drilled, completed and brought on line our Rocky 3 well, another horizontal well which tested as our best well in company history, and made substantial progress in addressing our field operations issues that have weighed on production and financial results for several quarters. Over the first half of the year we have taken a number of steps to improve run times and optimize production in the field, including numerous personnel changes in the field and in our Covington office, investments in facilities upgrades and repairs and maintenance, the addition of gas lift gas and salt water disposal capacity, the resolution of third party handling, flow line and other issues, and, shortly after quarter end, the addition of a new flow line in Breton Sound 32 and compression at Grand Bay.

Our efforts in the field have begun to bear fruit in the form of improved run times and marked growth in production from Q1 2014 levels. Our run times during Q2 2014 had returned to levels higher than our exit rate in 2013 and daily production rates had rebounded by June 2014 to levels exceeding those of 2013. Our growth in production rates was despite flow line capacity constraints in Breton Sound 32 where production was curtailed across the field, particularly at our newly completed Rocky 3 well, due to flow line capacity. With our new flow line completed in July, we now have the ability to produce our wells in the Breton Sound 32 area at peak rates. We are still analyzing the optimum production rate for Rocky 3 but are excited by its initial production and gratified to have validated our beliefs regarding the potential of horizontal wells in our fields.

We are also exceptionally proud of the results of our implementation of the compressor installation and infrastructure repairs at Grand Bay. Through extensive pre-planning and a collaborative effort by our field personnel and service companies, we were able to install additional compression and make several infrastructure repairs with only a minimal field shutdown. The results to our production rates in the field were immediate and substantial.

The additions to our professional staff and in the field over the first half of 2014 have brought new energy and talent to Saratoga. We have already seen benefits from those changes in the field and believe our newly strengthened team will pay dividends in terms of improved prospect selection, evaluation and execution.

While the quarter was filled with challenges, including field operating issues that have weighed on production, we believe that our intense focus on field operations has equipped us to more effectively and rapidly respond to conditions in the field and, thus, optimize production. We will continue to keep a close eye on field operations but believe that we are now in a position to return our emphasis to developing the most exciting and potentially productive prospects in our inventory.”

About Saratoga Resources

Saratoga Resources is an independent exploration and production company with offices in Houston, Texas and Covington, Louisiana. Principal holdings cover approximately 52,000 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 in the 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.

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.

      Q2 2014 Q1 2014   Net income (loss) as reported $ (6,652,436 ) $ (8,289,187 ) Depreciation, depletion and amortization 4,507,996 2,742,059 Exploration expense 200,298 221,352 Accretion Expense 448,467 448,466 Stock-based Compensation 240,253 6,029 Debt issuance and discount 758,237 732,433 Unrealized (gain) loss on hedges   33,440     (1,092,960 ) Discretionary Cash Flow $ (463,745 ) $ (5,231,808 )  

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:

      Q2 2014 Q1 2014   Net income (loss) as reported $ (6,652,436 ) $ (8,289,187 ) Depreciation, depletion and amortization 4,507,996 2,742,059 Income tax expense (benefit) 40,199 82,066 Exploration expense 200,298 221,352 Accretion expense 448,467 448,466 Stock-based compensation 240,253 6,029 Interest expense, net 6,023,144 5,997,212 Unrealized (gain) loss on hedges   33,440     (1,092,960 ) EBITDAX $ 4,841,361   $ 115,037    

Saratoga Resources, Inc.Brad Holmes, 713-654-4009Investor RelationsorAndrew Clifford, 713-458-1560PresidentorJohn Ebert, 985-809-9292Vice President – Finance and Business Development