Saratoga Resources, Inc. Reports First Quarter 2014 Financial Results

Saratoga Resources, Inc. (NYSE MKT: SARA; the “Company” or “Saratoga”) today announced financial and operating results for the quarter ended March 31, 2014.

Key Financial Results

• Oil and gas revenues of $10.6 million for Q1 2014 compared to $19.3 million for Q1 2013;
• Discretionary cash flow of $(5.2) million, or $(0.17) per fully diluted share, for Q1 2014 compared to discretionary cash flow of $4.9 million, or $0.16 per fully diluted share, for Q1 2013;
• EBITDAX of $0.1 million for Q1 2014 compared to $9.7 million for Q1 2013;
• Operating loss of $(2.2) million, or $(0.07) per fully diluted share, for Q1 2014 compared to operating income of $3.7 million, or $0.12 per fully diluted share, for Q1 2013; and
• Net loss of $(8.3) million, or $(0.27) per fully diluted share, for Q1 2014 compared to net loss of ($1.1) million, or $(0.03) per fully diluted share, for Q1 2013.

Discretionary cash flow, EBITDAX, net asset value per share and PV-10 are non-GAAP financial measures and are defined and reconciled to the most directly comparable GAAP measure under “Non-GAAP Financial Measures” below.

The net loss for the quarter reflects a 45% decline in oil and gas revenues while operating expenses only declined 7.2%. The change in revenues for the 2014 quarter reflects a decrease in production volumes (down 48.1% in aggregate; down 39.9% for oil; down 65.5% for natural gas) partially offset by higher average realized commodity prices (up 6%; oil pricing down 7.2%; natural gas pricing up 39.8%). The decline in production was attributable to multiple field operating issues which adversely affected run times during the first two months of the quarter – discussed more fully below under “Operational Highlights” and “Production Highlights” – and to the depletion of several producing sands. Extensive changes in field operating personnel and in our Covington office personnel were untaken during the quarter and substantially all of the run time related issues had been resolved by quarter end. The declines in production were partially offset by new wells coming on line during 2013 and increases in production from several wells that underwent recompletions and workovers during 2013 and Q1 2014.

The decrease in operating expenses for the quarter related principally to the decrease in production volumes which resulted in a reduction in depreciation, depletion and amortization expense (down $2.5 million; or 47.4%) and a decline in severance taxes (down $1.6 million; or 76%) which was partially offset by increases in lease operating expenses (up $0.9 million; or 20.5%), workover expense (up $1.9 million; or 739%) and lesser increases in exploration expense and general and administrative expense. 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 the decline in average run time during the quarter. The increase in workover expense was attributable to an increase in the number of workovers undertaken during the quarter. The decline in severance taxes for the quarter reflects a combination of lower production volumes and refunds of severance taxes arising from exemptions available on our Rocky, Zeke and Mesa Verde wells drilled in prior periods.

The net loss for the quarter also reflects higher interest expense (up $0.8 million; or 15.1%) resulting from the addition of $27.4 million of borrowing during the fourth quarter of 2013 and an adverse change in income tax expense/benefit ($0.5 million) as a result of our recording a valuation allowance against our entire net deferred tax asset at December 31, 2013 and our resulting non-recognition of a deferred tax benefit from our current quarter loss.

Operational Highlights

Operational highlights for first quarter 2014 included:

• 1 recompletion successfully completed and 1 in progress at quarter end; 7 workovers successfully completed;
• 90 gross/net wells in production at March 31, 2014;
• Exhaustive review undertaken, personnel changes implemented and investments in facilities repairs and maintenance made to address run time issues;
• Secured a gas buyback agreement with an area operator to provide for redundant gas supply for gas-lift operations;
• 52,103 gross/net acres under lease at March 31, 2014, including 32,289 acres in 13 fields in the transitional coastline and protected in-bay environment on parish and state leases in south Louisiana and 19,814 acres in the shallow Gulf of Mexico shelf; and
• Added 4 seasoned veterans to our professional staff.

During Q1 2014, we undertook 2 recompletions and 7 workovers. All of the recompletions and workovers were successful other than one recompletion that was ongoing at quarter end and that was successfully completed after March 31, 2014. Four of the seven workovers were undertaken on salt water disposal wells to increase the disposal capacity of produced water associated with our oil and gas production.

During Q1 2014, our management team, together with consultants, undertook an exhaustive review of field operations to address run time issues experienced in the second half of 2013 and into the first quarter 2014. Issues evaluated included personnel, facilities, gas lift availability, salt water disposal and other potential causes of unexpected down time in numerous fields. As a result of such evaluation, we made extensive changes in our field operating personnel and in our Covington office personnel. We also undertook extensive repairs and maintenance projects to improve certain facilities in the field and invested in gas lift projects and salt water disposal wells. The majority of the personnel changes, facilities upgrades and other projects were completed in early March 2014 with additional personnel changes and facilities upgrades continuing following quarter end.

In addition to extensive changes in our field level personnel, we have strengthened and added depth to our professional staff with hiring 4 seasoned professionals who are expected to enhance our prospect analysis and development capabilities.

Production Highlights

• Oil and gas production of 94.2 thousand barrels of oil (“MBO”) and 152.9 million cubic feet of gas (“MMCFG”), or 119.7 thousand barrels of oil equivalent (“MBOE”) (78.7% oil) in Q1 2014, down 48.1% from 230.7 MBOE (68% oil) in Q1 2013;
• Increased gross gas production to 5.9 Mmcf/d by quarter end, last seven days average, versus 4.6 Mmcf/d and 3.9 Mmcf/d in Q3 2013 and Q4 2013, respectively; and
• Following production optimization initiatives undertaken during Q1, average run times increased to 76% in March 2014, up from 54% in January and February 2014 and daily production rates reached an average of 1,875 MBOE per day (MBOEPD) over the last seven days of the quarter compared to an average of 1,330 MBOEPD over the full quarter and 1,800 MBOEPD in Q4 2013.

The decrease in production reflects a substantial decline in run times during the first two months of 2014 and the depletion of producing sands in three wells. Run times averaged 61% for the quarter and 54% for January and February as compared to 73% in Q1 2013 and 75% for fiscal 2013.

Partially offsetting declines in production attributable to decreased run times and depleted sands were the addition of production from wells drilled during the final three quarters of 2013 and increased production or renewal of production from wells that have undergone recompletions or workovers since the end of Q1 2013.

Following our exhaustive review of field operations with respect to the decline in run times and other issues holding down our production, we identified a number of specific issues and implemented extensive personnel changes at the field level and in our Covington office, invested in facilities repairs, maintenance and upgrades, added gas lift availability, executed a gas buyback agreement with an area operator, worked over several salt water disposal wells, all of which were identified as adversely affecting our run times and production. The majority of those changes were implemented during March 2014.

Following the implementation of the various field level initiatives, and taking into account our workover and recompletion program, run times and production rates began to grow in March 2014, with estimated run times in March 2014 averaging 76% up from 54% in January and February 2014 and up from 73% in Q1 2013 and 75% for fiscal 2013. Production rates had risen to an average of 1,875 MBOEPD over the last seven days of the quarter compared to 1,330 MBOEPD for the full quarter and 1,800 MBOEPD in Q4 2013.

Development Plans

• Low risk recompletions, thru-tubing plugbacks and workovers from inventory of approximately 56 proved developed non-producing (“PDNP”) opportunities in 7 fields;
• Development of proved undeveloped (“PUD”) reserves from inventory of approximately 85 PUD opportunities in 22 wellbores in 5 fields;
• Rocky 3 horizontal well with 750’ lateral in Breton Sound 32 field commenced drilling during Q2;
• Q2 and Q3 focused on targeted recompletions and workovers with objective of further growing legacy well production rate;
• Development drilling planned to resume in Fall 2014; and
• 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.

Drilling operations on our Rocky 3 horizontal well in Breton Sound 32 field commenced in early May 2014 with drilling expected to be completed before month end.

Our near term development plans during Q2 and Q3 2014 are expected to be focused on workover and recompletion opportunities to enhance production from our legacy wells.

We plan to resume our development drilling program in the Fall of 2014 and are conducting exhaustive geological and engineering reviews to bring forward the most promising of our available prospects.

We have commenced marketing efforts with respect to our efforts to secure drilling partners for our Goldeneye prospect in Grand Bay Field and, subject to securing commitments from potential partners, are planning to commence drilling of that prospect during 2014.

Financial Position and CAPEX Highlights

• $ 20.4 million of cash on hand at March 31, 2014, down from $32.5 million at December 31, 2013;
• Cash balance had grown to $21.0 million by end of April 2014;
• $14.6 million of working capital at March 31, 2014, down from $20.4 million at December 31, 2013;
• $1.3 million of CAPEX for Q1 2014;
• Working capital adjusted debt to trailing twelve month EBITDAX of 8.6 times; and
• Net asset value per share (based on working capital adjusted PV-10) of approximately $7.93.

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, “As noted in our year end 2013 earnings call, Q1 2014 was a challenging period during which I, and our entire management team, took a hard look at our field operations in order to ferret our issues that continued to plague Saratoga and result in unsatisfactory run times and production levels below those considered acceptable by management. As a result of our exhaustive review, we made a number of wide ranging changes that began to go into effect in early March. Those changes included extensive changes in field operating personnel and in our Covington office, investments in repairs and maintenance on our facilities in the field and a focus on adding gas lift gas and salt water disposal capacity that have curtailed our production in the past and, in particular, over the first two months of the current quarter.

While the review of operations was time consuming and took us away from our planned development operations, I am pleased to say that the initiatives implemented as a result of that review began to show results almost immediately with run times, and production, growing markedly over the last month of the quarter. We intend to continue to keep an eye on field level operations to assure that the issues that plagued us during the first two months of the quarter, and in prior periods, will not reoccur.

With the run time issues seemingly behind us, we are focused on continuing to move up our production from our legacy wells and to reinstituting our development drilling program.

Our next development well is already well along in drilling. The SL 1227 #29 “Rocky 3” well in Breton Sound 32 field, an analog to our successful SL 1227 #25 “Rocky 1” horizontal well, began drilling in early May and reached a total depth of 7,178’ MD/5,818’ TVD on May 14, 2014. Based on drilling results and analysis of log data, we are optimistic that Rocky 3 will perform as well as, or better than, Rocky 1.

We also have a rig in Grand Bay finalizing the completion of the SL 195 QQ #24 well, which will be followed by a non-rig wireline recompletion in our SL 195 QQ #25 well. We expect the Rocky 3, QQ #24 and QQ #25 wells to all be in production within the next two to three weeks. Over the next several months we intend to focus our efforts on increasing production from our legacy wells with a view to growing our cash position to support renewed development drilling in the Fall.

While we are continually reviewing our prospect inventory to bring forward the most promising drilling prospects, we are presently targeting drilling of our Goldeneye prospect in Grand Bay. We have completed an exhaustive analysis of the prospect and have begun an active marketing effort to secure partners to drill the prospect.

I am also pleased with the additions to our professional staff over the past quarter and since quarter end. We now have the deepest and most experienced staff in our company’s history 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 a disappointing drop in production and revenues and the incurrence of additional costs to address issues in the field, we believe that the issues in question are largely behind us. We are optimistic about our Rocky 3 well as well as our planned recompletion and workover program and planned resumption of our development drilling post-Rocky 3. Run times and production levels improved over the last month of the past quarter and those improvements continue to hold. We are now optimistic that our legacy well production can serve its intended purpose as a platform on which we can grow production through our development drilling program.”

About Saratoga Resources

Saratoga Resources is an independent exploration and production company with offices in Houston, Texas and Covington, Louisiana. Principal holdings cover 52,103 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.

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:

Net Asset Value is a non-GAAP financial measure.

The company defines Net Asset Value per Share, NAV, as the per share value of the PV-10 value of its reserves plus working capital less long-term debt. Net Asset Value Per Share 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 net value of its tangible assets less liabilities. Net Asset Value per Share assumes no future re-investment to find or acquire new reserves and that a company stops operating once its reserves are depleted. Net Asset Value Per Share should not be considered as a substitute for any other measure of financial performance or liquidity presented in accordance with generally accepted accounting principles (“GAAP”). Net Asset Value per Share excludes certain intangible and other assets and certain liabilities that may affect the realized in the event of liquidation. Therefore, the company’s Net Asset Value per Share may not be comparable to similarly titled measures used by other companies.

PV10 is the estimated present value of the future net revenues from proved oil and natural gas reserves before income taxes, discounted using a 10% discount rate. PV 10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. Saratoga believes that PV10 is an important measure that can be used to evaluate the relative significance of its oil and natural gas properties and that PV10 is widely used by security analysts and investors when evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. Saratoga believes that most other companies in the oil and natural gas industry calculate PV10 on the same basis. PV10 is computed on the same basis as the standardized measure of discounted future net cash flows, but without deducting income taxes.