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

Key Financial Results

  • Oil and gas revenues of $15.9 million for Q3 2014 compared to $15.1 million for Q2 2014;
  • Discretionary cash flow of $(0.9) million, or $(0.03) per fully diluted share, for Q3 2014 compared to $(0.5) million, or $(0.01) per fully diluted share, for Q2 2014;
  • EBITDAX of $4.4 million for Q3 2014 compared to $4.8 million for Q2 2014;
  • Operating loss of $(4.2) million, or $(0.13) per fully diluted share, compared to $(0.6) million, or $(0.02) per fully diluted share, for Q2 2014; and
  • Net loss of $(10.3) million, or $(0.33) per fully diluted share, for Q3 2014 compared to $(6.7) million, or $(0.21) per fully diluted share, for Q2 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 increase in net loss in Q3 2014 as compared to Q2 2014 is principally attributable to a $3.4 million charge associated with an arbitration award during Q3 and, to a lesser degree, higher workover expense (up $1.6 million) and higher lease operating expenses (up $0.3 million, or 5.4%) during Q3. The higher losses attributable to those expenses was partially offset by a rise in oil and gas revenues (up $0.8 million, or 5.5%) on higher production volumes (oil volumes up 11.1% and natural gas volumes up 15.2%) partially offset by a decline in average commodity prices realized (oil prices down 4.9% and natural gas prices down 9.4%). The increase in production was principally attributable to a full quarter’s production from the Rocky 3 well (volume up 83.7%) and increased average run-time following our production optimization initiatives undertaken during the first half of 2014.

The adverse portion of the arbitration award ($3.7 million), which resulted in the arbitration award expense of $3.4 million, has been appealed and is subject to a countersuit. We believe there are meritorious grounds to overturn the award in whole and, if the award stands, to substantially reduce the amount of the award.

Operating expenses for Q3 2014 were up $5.2 million or 33.2% from Q2 2014 levels. The increase in operating expenses quarter-over-quarter was attributable to the arbitration award ($3.4 million) and the increases in workover expenses (up $1.6 million). Increases in lease operating expenses (up $0.3 million, or 5.4%) were offset by reductions in general and administrative expense (down $0.3 million, or 11.1%). The increase in workover expense reflects higher workover activity during the quarter. The increase in lease operating expense reflects higher contract construction labor resulting from our production optimization initiatives. Cost containment measures, including reduced headcount, converting some contract personnel to company personnel, compression optimization, rerouting a production line, reduced reliance on consultants, and other initiatives, brought down our G&A expense for the quarter and are expected to lower our LOE and G&A in Q4 and later periods.

Operational Highlights

Operational highlights for third quarter 2014 included:

  • 6 workovers; 2 successfully completed, 1 unsuccessful and 3 in progress at September 30, 2014;
  • 104 gross/net wells in production at September 30, 2014;
  • Rerouting of flow line from Main Pass 52 and 46, reducing compressor rental and maintenance expense;
  • 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 September 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 Q3 2014, we conducted workover operations on 6 wells, 2 of which were successfully completed during the quarter, 1 of which was unsuccessful and 3 of which were in progress at quarter end. We also rerouted the flowline serving production in Main Pass 52 and 46, reducing compressor rental and associated maintenance expense and eliminating certain water handling issues. We also continued our ongoing cost reduction program designed to bring down both our G&A and LOE with an emphasis on right sizing operations through a combination of reduced headcount, lowering outside consulting costs by renegotiating certain contractual arrangements and bringing certain personnel and functions in house and other initiatives. Those initiatives reduced G&A during Q3 and are expected to result in continued reductions in G&A going forward and reductions in LOE commencing in Q4.

Q3 also reflected ongoing emphasis on maintaining improved run times in the field which contributed to the production gain for the quarter.

Production Highlights

  • Oil and gas production of 149.7 thousand barrels of oil (“MBO”) and 291.4 million cubic feet of gas (“MMCFG”), or 198.3 thousand barrels of oil equivalent (“MBOE”)(75.5% oil) in Q3 2014, up 12.1% from 176.9 MBOE (76.2% oil) in Q2 2014;
  • Rocky 3 well produced for full Q3 2014, increasing production by 10.5 MBOE from Q2 2014;
  • 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 to increase run-time, daily production rates reached an average of 2,155 BOEPD over Q3 2014 as compared to 1,944 BOEPD over Q2 2014 and 1,330 BOEPD over Q1 2014.

The increase in production reflects an increase in production from Rocky 3 (up 10.5 MBOE for Q3 vs. Q2) attributable to a full quarter’s production, improved run times during Q3 and recompletions in Grand Bay and Vermilion 16 undertaken earlier in 2014. The improvement in run times reflects our production optimization initiatives carried out during the first half of 2014 with initiatives ongoing, including 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 increases were partially offset by natural decline in existing wells and issues on SL 1227 #L-1 well in Breton Sound Block 32 Field, which are presently being evaluated.

Development Plans

  • Low risk recompletions, thru-tubing plugbacks and workovers from inventory of approximately 61 proved developed non-producing (“PDNP”) opportunities in 8 fields;
  • Development of proved undeveloped (“PUD”) reserves from inventory of approximately 95 PUD opportunities in 24 wellbores in 5 fields;
  • Q4 focused on targeted recompletions and other low cost thru-tubing 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 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 and Gulf of Mexico prospects.

Our near term development plans during Q4 2014 are focused on carrying out 6 to 9 low cost thru-tubing recompletions/projects and other opportunities to enhance production from our legacy wells.

As has historically been the case, during the peak of hurricane season in Q3 we conducted no development drilling operations. With the recent drop in commodity prices, we intend to curtail investments in our development drilling program pending stabilization/strengthening of prices and to focus on enhancing production from existing wells, bringing down operating costs and building cash reserves to support debt service obligations and to position for a future resumption of our development drilling program.

We have commenced marketing efforts to attract partners for drilling of our Goldeneye prospect in Grand Bay and the first of our Gulf of Mexico prospects. We have received indications of interest on each of those prospects and look to move those forward in 2015 although we anticipate that potential partners will look for stabilization/strengthening of commodity pricing before committing to fund such projects.

Management Comments

Thomas Cooke, Chairman and CEO, commented, “Q3 2014 saw continuing progress in our production optimization initiatives and our cost reduction program. We saw quarter over quarter rises in both oil and natural gas production while bringing down our G&A expense and putting in place measures that we expect will bring down LOE going forward. We are keenly focused on optimizing production from our existing wells while selectively investing in low cost operations that offer the potential of short paybacks from growing production. In that regard, we are pleased that the first three of our recent thru-tubing plugback operations have been successfully completed ahead of schedule and under internal cost estimates. We anticipate all projects being complete before the end of November.

We are proud of the dedication and efforts of our entire team in their contributions to our numerous initiatives that have produced a 62% increase in daily production rates from Q1 to Q3, our cost control program that have just recently begun to bear tangible results and our numerous infrastructure programs, highlighted by compressor installations and infrastructure repairs in Grand Bay, rerouting of flowlines to eliminate and/or reduce compressor rental and maintenance costs and numerous other initiatives that have dramatically improved efficiency in the field.

With the recent drop in commodity prices, like others in our industry, we are focused on operating in a lean manner and continue to push forward in our efforts to bring down both LOE and G&A. With the initiatives undertaken over the past year, management has a hands-on understanding of field operations and areas where costs control efforts offer the greatest opportunity for savings. We believe that our efforts in that regard will allow us to adjust to a lower commodity price environment although resumption of our development drilling will certainly be sidelined until pricing improves and we can once more build our cash position to support such efforts.”

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.

Q3 2014 Q2 2014
Net income (loss) as reported $ (10,273,485 ) $ (6,652,436 )
Depreciation, depletion and amortization 4,839,858 4,507,996
Exploration expense 225,949 200,298
Accretion Expense 448,466 448,467
Stock-based Compensation 173,872 240,253
Debt issuance and discount 800,119 758,237
Unrealized (gain) loss on hedges (533,781 ) 33,440
Arbitration loss 3,400,000
Discretionary Cash Flow $ (919,002 ) $ (463,745 )

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:

Q3 2014 Q2 2014
Net income (loss) as reported $ (10,273,485 ) $ (6,652,436 )
Depreciation, depletion and amortization 4,839,858 4,507,996
Income tax expense (benefit) 33,795 40,199
Exploration expense 225,949 200,298
Accretion expense 448,466 448,467
Stock-based compensation 173,872 240,253
Interest expense, net 6,086,746 6,023,144
Unrealized (gain) loss on hedges (533,781 ) 33,440
Arbitration loss 3,400,000
EBITDAX $ 4,401,420 $ 4,841,361