Saratoga Resources, Inc. Reports First Quarter 2013 Financial Results
Saratoga Resources, Inc. Reports First Quarter 2013 Financial Results
HOUSTON--(BUSINESS WIRE)-- Saratoga Resources, Inc. (NYSE MKT: SARA; the "Company" or "Saratoga") today announced financial and operating results for the quarter ended March 31, 2013.
Key Financial Results
- Oil and gas revenues of $19.26 million for Q1 2013 compared to $19.34 million for Q1 2012;
- Discretionary cash flow of $5.1 million, or $0.16 per fully diluted share, for Q1 2013 compared to discretionary cash flow of $5.8 million, or $0.21 per fully diluted share, for Q1 2012;
- EBITDAX of $9.9 million for Q1 2013 compared to $10.0 million for Q1 2012;
- Operating income of $3.7 million, or $0.12 per fully diluted share, for Q1 2013 compared to operating income of $2.5 million, or $0.09 per fully diluted share, for Q1 2012; and
- Net loss of $(1.1) million, or $(0.03) per fully diluted share, for Q1 2013 compared to net loss of ($1.2) million, or $(0.04) per fully diluted share, for Q1 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.
Production was down 9.3% from the first quarter of 2012 to the first quarter of 2013. This decrease was primarily attributable to curtailed production in the Main Pass 25 Field associated with issues on a neighboring third party operated platform to which we produce and a temporary lack of gas lift gas in the field. In addition, in the Grand Bay Field, the QQ24 well was shut-in for five weeks during the drilling of the QQ25 well and there were shut-ins associated with infrastructure improvements. To a lesser extent, production was also impacted by the lingering effects of Hurricane Isaac. These decreases were partially offset by production added from our development drilling program over the last three quarters of 2012.
Average realized prices per barrel of oil equivalent were $83.51, up 9.7% quarter over quarter, primarily attributable to an 18.2% increase in natural gas prices realized partially offset by a 2.4% 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.
Total revenues declined 7.3% from the first quarter of 2012 to the first quarter of 2013. In addition to the nominal decline in oil and gas revenue, the decline in total revenue reflects hedging losses of $0.6 million, associated with the reinstitution of our hedging program beginning late in 2012, and a decline in other revenues of $0.8 million principally reflecting a one-time gain of $0.6 million on the settlement of lawsuits during the 2012 quarter.
The increase in operating income for the quarter reflects a 15.2% decline in operating expenses which was principally attributable to lower workover expense (down $1.2 million, or 82.2%) due to decreased workover activity, lower plugging and abandonment expenses (down $1.6 million, or 100%) due to one-time P&A projects undertaken in the 2012 quarter, and a decline in general and administrative expense (down $0.6 million, or 23.4%) due to lower headcount and lower stock-based compensation expense. Those decreases were partially offset by higher DD&A expense (up $0.3 million, or 5.5%) due to increased investments in our development program, and an increase in production and severance taxes (up $0.4 million, or 24.4%) as a result of a reduction in the number of wells qualifying for reduced severance taxes. The improvement in operating income was partially offset by higher interest cost (up $0.8 million), as a result of our add-on note offering closed in late 2012 and a reduced tax benefit (down $0.2 million).
Operational highlights for first quarter 2013 included:
- 2 development wells completed, including 1 well in progress at the close of 2012, 3 recompletions completed and 1 workover completed and 1 in progress;
- 105 gross (104 net) wells in production at March 31, 2013;
- Restoration of production from remaining wells shut-in due to Hurricane Isaac;
- 32,027 gross/net acres in 11 fields under lease at March 31, 2013; and
- Apparent high bids submitted on four lease blocks covering 19,814 acres in the shallow GOM water.
During Q1 2013, Saratoga completed 2 successful development wells, the Buddy well in Grand Bay Field, which was started in late 2012, and the Roux Toux well in Main Pass Block 47 Field, which was drilled and completed during the quarter.
Saratoga also undertook 3 recompletions and 2 workovers during the quarter. All the recompletions were successful and 1 of the workovers was in progress as of the end of the quarter.
- Oil and gas production of 156.7 thousand barrels of oil ("MBO") and 443.3 million cubic feet of gas ("MMCFG"), or 230.7 thousand barrels of oil equivalent ("MBOE") (68% oil) in Q1 2013, down 9.3% from 254.2 MBOE (59% oil) in Q1 2012; and
- Curtailments of production during Q1 2013 associated with third party handling issues and temporary lack of gas lift gas in Main Pass 25 Field, shut-ins due to drilling operations and infrastructure projects primarily in Grand Bay field and residual effects of Hurricane Isaac resolved by quarter end.
The decrease in production reflects curtailment of production from the Main Pass 25 Field where third party handling issues and temporary lack of gas lift gas resulted in a 21.5 MBOE (85%) decline in production from the field from Q1 2012 levels and shut-in of the QQ24 well in Grand Bay Field for 5 weeks during the drilling of the Roux Toux well which resulted in a 4.5 MBOE decline in production from the QQ24 well from Q1 2012 levels. Additionally, residual effects of Hurricane Isaac marginally decreased production.
Partially offsetting the curtailment in production from the Main Pass 25 Field and Grand Bay Field were additions to production attributable to new wells added through our development drilling program since Q1 2012. By the end of Q1 2013, all curtailments attributable to third party handling and gas lift issues in Main Pass 25 Field and drilling of the Roux Toux well, as well as residual curtailments associated with Hurricane Isaac, had been resolved.
In addition to reserves associated with existing holdings, during the Q1 2013, Saratoga was the apparent high bidder on four leases totaling 19,814 acres in the Central Gulf of Mexico. Preliminary unaudited reserve potential for those leases has been estimated internally at 51.2 gross MMBOE, of which 5.4 gross MMBOE are expected to subsequently be qualified as PUD reserves.
- Low risk recompletions, thru-tubing plugbacks and workovers from inventory of approximately 60 proved developed non-producing ("PDNP") opportunities in 7 fields;
- Development of proved undeveloped ("PUD") reserves from inventory of approximately 84 PUD opportunities in 26 wellbores in 4 fields;
- Rocky horizontal well with 750' lateral in Breton Sound 32 field planned for late Q2;
- Tubing replacement program being implemented to restore curtailed and shut-in production from inventory of approximately 20 wells;
- Main Pass 25 facilities upgrade program; 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.
Our near term development plans are focused on proved undeveloped opportunities and conversion of PDNP opportunities. Two PUD wells were completed during Q1 2013 with a target of drilling and completing four to six total PUD wells during 2013, and five to six development wells annually thereafter.
We are negotiating for a barge rig to drill our first horizontal well in Breton Sound 32 field, the SL 1227-25 "Rocky" well. Saratoga plans to drill an initial 70-degree directional pilot hole to the target 5800' sand then to plug back and drill a horizontal leg with a 750' lateral into the reservoir. The estimated completed well cost is less than $7 million. The current water level in that part of the Breton Sound 32 field has already been established by running a PNL log in the SL 1227-21 well, determining that the oil-water contact has only risen by 6 inches in over 20 years. This significantly reduces the risk for the proposed horizontal completion.
After Rocky, there are several other horizontal completion opportunities including Zeke and Charlie, both in the same Breton Sound 32 field, and other opportunities in Grand Bay field under evaluation.
At Grand Bay, approximately 20 shut-in wells have been identified that appear to be candidates for tubing replacement and resumption of production. These wells were each producing between 20-50 BOPD prior to being shut-in. The tubing replacement program involves mounting a pulling unit on a shallow water barge at an estimated cost of less than $200,000 per well. If successful, for an approximate cost of $4 million, up to 400 net BOPD might be added to production, representing a payout of less than 6 months. Evaluation of candidates for the tubing replacement program is ongoing and initial operations in that program are expected to commence in June 2013.
Saratoga continues 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. The results of ongoing third party ultra-deep exploratory drilling are expected to drive the ultimate determination regarding potential development of Saratoga's ultra-deep prospects.
Subject to final award of leases by the Bureau of Ocean Energy Management, Saratoga also intends to seek partners to drill, develop and operate its prospects in the Central Gulf of Mexico on which it was the apparent high bidder in the recent lease sale.
In Main Pass 25 Field, discussions with a third party operator regarding upgrades to our facilities are continuing. The objective of those discussions is to increase production, improve economics in that field and reduce dependency upon third party facilities operators which caused the shut-in of most of our production in that field during the first quarter of 2013 due to third party production issues on a neighboring platform to which we produce. The initiatives include a recompletion of the 7900' sand in the SL 16432 #2 well, which was successfully carried out during the quarter, and pursuit of an arrangement with another operator to increase handling capacity at our facilities in Main Pass 25. Recompletion of the 7900' sand provided sufficient gas lift gas to unload oil wells in the field. The anticipated arrangement with the third party operator includes our handling of production from a new discovery in the field by the third party operator and the provision by that operator of certain equipment to upgrade the handling capacity of our Main Pass 25 facilities. If that arrangement is carried out, we would potentially add production handling capacity at our Main Pass 25 facilities which may 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 by up to 400 gross barrels of oil per day while adding a potential source of additional gas lift gas.
Financial Position and CAPEX Highlights
- $ 22.0 million of cash on hand at March 31, 2013, down from $32.3 million at December 31, 2012;
- Cash balance had grown to $24.8 million by end of April 2013;
- $18.6 million of working capital at March 31, 2013, down from $21.2 million at December 31, 2012;
- $7.1 million of CAPEX for Q1 2013;
- $37.1 million CAPEX budgeted for balance of 2013;
- 2013 CAPEX budget fully funded by cash on hand and projected operating cash flow;
- Working capital adjusted debt to trailing twelve month EBITDAX of 2.9 times; and
- Net asset value per share of approximately $9.
Saratoga continued to fund its operations, including its 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.
Thomas Cooke, Chairman and CEO, commented, "As noted in our year end 2012 earnings release, production levels during the first quarter of 2013 were down due to factors largely beyond our control, most notably, third party processing issues and lack of gas lift gas which effectively resulted in the shut-in of production in Main Pass 25 for the entire quarter causing our production in the field to decline 21.5 MBOE from 2012 levels. Adding to such drop in production was the shut-in of our QQ24 well in Grand Bay Field for five weeks while we drilled our Roux Toux well which accounted for a 4.5 MBOE decline in production for that well compared to the first quarter 2012.
Notwithstanding the decrease in production during the quarter, we are pleased with a number of key advances during the quarter and since quarter end, including progress made in returning production to a positive trajectory, reinstituting our field study program, initiation of our tubing replacement program, the addition of key employees and the exciting prospect of commencing drilling operations on our first horizontal well.
While the issues noted affecting production levels resulted in a decline in daily production levels to a disappointing 2,563 BOE per day during the quarter, the resolution of the issues in question have allowed us to bring our daily production levels back up to approximately 3,000 BOE currently. That rise in production does not reflect any of the contemplated additions to production that we expect to derive from our tubing replacement program, infrastructure upgrades in Main Pass 25 and other routine maintenance projects presently planned to restore declines in production from a handful of wells.
In our tubing replacement program, we have completed our evaluation of a substantial number of candidate wells and have identified 21 wells to this point that we believe are prime prospects for restoration of production in that program and believe that as many as 30 wells will ultimately be included in the program. We expect to begin seeing results in the form of production adds before the end of the second quarter and have targeted completion of the program by mid-third quarter.
In Main Pass 25, we have made progress and expect to finalize our arrangement with an operator and to upgrade production facilities to both handle processing of that operator's production in the field and lower system pressure, facilitating an increase in our production in the field by the end of the second quarter.
Finally, and most importantly in our minds, 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 planned Rocky well, our first horizontal well. Having closely examined the results attained in prior horizontal wells drilled in the area which, though limited in number, have typically been among the most productive wells drilled in and around our acreage. We believe Rocky holds similar potential and are presently targeting having that well drilled, completed and on production during the second quarter.
I would also note that we have made a number of key additions to our operating team since the end of the first quarter, including adding two seasoned reservoir engineers and a geophysicist who, together, are working with Andy Clifford to maximize the payback on our field study program. We have also added an experienced land manager to bring in-house our land management operations.
With our cash balance having grown to more than $24 million and increasing and our payables down substantially since quarter end, we are well positioned to execute on our projects. While we have much on our plate, we are pleased to have moved past the challenges that weighed on our production during the first quarter and are excited to see the fruits of multiple potentially high impact projects that offer the prospects of significant production adds over the second and third quarters and beyond."
About Saratoga Resources
Saratoga Resources is an independent exploration and production company with offices in Houston, Texas and Covington, Louisiana. Principal holdings cover 32,027 gross/net acres, mostly held-by-production (all depths), currently located in the transitional coastline and protected in-bay environment on parish and state leases of south Louisiana. 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 of less than 10 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.
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.
For the Three Months Ended
Net income (loss) as reported
|Depreciation, depletion and amortization||5,208,494||4,937,152|
|Income tax expense (benefit)||(487,247||)||(768,243||)|
|Loss on plugging and abandonment||-||1,612,290|
|Dry hole costs||-||89,874|
|Debt issuance and discount||438,788||301,476|
|Discretionary Cash Flow||$||5,068,065||$||5,828,158|
EBITDAX is a non-GAAP financial measure.
The company defines EBITDAX as net income (loss) before income tax expense (benefit), interest expense and depreciation, depletion and amortization excluding interest income, realized gains on out-of-period derivative contract settlements, (gain) loss on the sale of assets, acquisition costs, settlements for prior claims, other various non-cash items (including asset impairments, income from equity investments, noncontrolling interest, stock-based compensation, unrealized (gain) loss on derivative contracts and provision for doubtful accounts), exploration and dry hole costs and costs associated with the company's bankruptcy.
EBITDAX is a supplemental financial measure used by the company's management and by securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of the company's ability to internally fund exploration and development activities and to service or incur additional debt. The company also uses this measure because EBITDAX allows the company to compare its operating performance and return on capital with those of other companies without regard to financing methods and capital structure. EBITDAX should not be considered as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with generally accepted accounting principles ("GAAP"). EBITDAX excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, the company's EBITDAX may not be comparable to similarly titled measures used by other companies.
The table below reconciles the most directly comparable GAAP financial measure to EBITDAX:
For the Three Months Ended
|Net income (loss) as reported||$||(1,061,393||)||$||(1,219,074||)|
|Depreciation, depletion and amortization||5,208,494||4,937,152|
|Income tax expense (benefit)||(454,150||)||(735,743||)|
|Loss on plugging and abandonment||-||1,612,290|
|Dry hole costs||-||89,874|
|Interest expense, net||5,216,862||4,407,795|
Saratoga Resources, Inc
Brad Holmes, 713-654-4009
Andrew Clifford, 713-458-1560
Michael Aldridge, 713-458-1560
KEYWORDS: United States North America Texas
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