HOUSTON–(BUSINESS WIRE)–Saratoga Resources, Inc. (OTC Pink Market: SARAQ; the “Company” or “Saratoga”) today announced updated reserve information as of June 1, 2015. The updated reserve totals reflect management’s internal estimates and incorporate updated audited reserves associated with the Company’s 100% operated Breton Sound Block 32 and Main Pass Block 25 fields, both located in Plaquemines Parish, Louisiana.
In Breton Sound Block 32 and Main Pass Block 25 fields, combined, total proved reserves have increased by 1,206 thousand barrels of oil equivalent (“MBOE”), a 66% increase over January 1, 2015 estimates, and proved plus probable plus possible reserves (“3P”) have increased by 12,221 MBOE, a 407% increase over January 1, 2015 estimates. In both cases, reserves were audited by Netherland, Sewell & Associates, Inc. (“NSAI”), one of the world’s premier independent oil and gas reserves auditors.
The Company’s internal estimate of total proved reserves for all fields, as of June 1, 2015, are 12.4 million barrels of oil and natural gas liquids (“MMBO”) plus 68.0 billion cubic feet of gas (“BCF”), or 23.7 million barrels of oil equivalent (“MMBOE”), including 4.8 MMBO plus 38.8 BCF, or 11.2 MMBOE of probable P90 reserves, with net present value discounted at ten percent (“PV10”) of $328 million, based on June 1, 2015 strip pricing starting at $66.09 oil, $2.83 gas, adjusted for quality, transportation fees and market differentials. Probable P90 reserves are proven undeveloped (“PUD”) reserves that have been re-categorized to probable reserves due to the Securities and Exchange Commission (“SEC”) five-year PUD reserves re-categorization. Total probable reserves, excluding the probable P90 reserves, are 13.7 MMBO plus 59.6 BCF, or 23.6 MMBOE with PV10 of $452 million and total possible reserves are 31.4 MMBO plus 150.4 BCF, or 56.4 MMBOE with PV10 of $1,060 million, giving total proved plus probable plus possible (“3P”) reserves of 103.8 MMBOE with PV10 of $1.82 billion.
Reserve additions identified in Breton Sound Block 32 Field reflect NSAI audited totals as of April 1, 2015 as compared to December 31, 2014 totals as audited by Collarini Associates, which totals have been rolled forward to June 1, 2015 in preparing management’s internal estimates. At Breton Sound Block 32 Field, the Company had proved reserves, as of April 1, 2015, of 1.5 MMBO plus 1.6 BCF, or 1.7 MMBOE with PV10 of $25.3 million, using April 1, 2015 strip pricing starting at $66.58 oil, $2.70 gas, adjusted for quality, transportation fees and market differentials. These proved reserves are a 3% increase over January 1, 2015 estimates. Of these proved reserves, 820 thousand barrels of oil (“MBO”) plus 205 million cubic feet of gas (“MMCF”), or 854 thousand barrels of oil equivalent (“MBOE”), are proved developed producing (“PDP”), 3 MBO plus 121 MMCF, or 23 MBOE, are proved developed non-producing (“PDNP”) and 654 MBO plus 1,297 MMCF, or 870 MBOE are proved undeveloped (“PUD”). In addition, as of April 1, 2015, there are probable reserves of 4,318 MBO plus 2,557 MMCF, or 4,744 MBOE, with PV10 of $129.2 million, and possible reserves of 5,461 MBO plus 2,799 MMCF, or 5,928 MBOE, with PV10 of $123.8 million. Total 3P reserves, as of April 1, 2015, are 12,420 MBOE with PV10 of $278.2 million, a 326% increase over earlier estimates by Collarini Associates from December 31, 2014.
Reserve additions identified in Main Pass Block 25 Field reflect NSAI audited totals as of June 1, 2015 as compared to December 31, 2014 totals as audited by Collarini Associates. At Main Pass Block 25 Field, the Company had proved reserves, as of June 1, 2015, of 1,005 MBO plus 1,627 MMCF, or 1,277 MBOE with PV10 of $23.4 million, using June 1, 2015 strip pricing. These proved reserves are a 964% increase over January 1, 2015 estimates. Of these proved reserves, 235 MBO plus 219 MMCF, or 272 MBOE, are PDP, 28 MBO plus 312 MMCF, or 80 MBOE, are PDNP and 742 MBO plus 1,096 MMCF, or 925 MBOE are PUD. In addition, as of June 1, 2015, there are probable reserves of 804 MBO plus 785 MMCF, or 955 MBOE, with PV10 of $32.0 million, and possible reserves of 783 MBO plus 933 MMCF, or 939 MBOE, with PV10 of $23.0 million. Total 3P reserves are 3,171 MBOE with PV10 of $78.3 million, a 1,733% increase over earlier estimates by Collarini Associates from December 31, 2014.
Each year, the Society of Petroleum Evaluation Engineers (“SPEE”) conducts a survey of oil and gas industry producers, energy banking and finance professionals, private equity specialists and consultants relating to parameters used in property evaluation. SPEE has 558 members and poses a large number of questions in order to compile and summarize the methods and procedures used by respondents in performing valuations for acquisition and divestiture, calculating fair market value, or estimating loan value. 168 respondents participated in the 34th Annual Survey, dated June 1, 2015, as it relates to valuation methodologies and criteria. By far the most common method of evaluation used by respondents is the discounted cash flow (“DCF”) method, which was ranked #1 by 80% of the respondents. As stated within the SPEE Annual Survey, an important variable within DCF analysis is the use of a prescribed discount rate and the SEC regulations requires that DCFs be calculated and reported using a 10% discount rate. The unrisked discount rate is a rate used to calculate the unrisked present value of a future cash flow profile. The median discount rate most commonly used is 10%. Most evaluations of oil and gas reserves are initially performed in an unrisked manner, with reserve categorizations (proved, probable and possible) and reserve status (producing, non-producing/behind pipe and undeveloped) serving as the only indicators of relative risk, although these indicators are qualitative at best. In order to develop a value from unrisked DCF models, risk factors are usually applied. Two of the most common methods of incorporating risk into DCF models include risking the reserves, such as application of Reserve Adjustment Factors (“RAF”) and Risk Adjusted Discount Rate (“RADR”). RAFs were identified as the most common method of incorporating risk with 42% of respondents indicating that they use this method exclusively and another 25% indicating that they use this method in conjunction with some additional adjustment in discount rates and 28% of respondents indicated that they used RADRs exclusively.
The median, or P50, RAFs most commonly used by respondents are 100% for PDP, 85% for proved developed shut-in (“PDSI”), 75% for proved developed behind-pipe (“PDBP”), 50% for PUD, 50% for probable producing, 32.5% for probable shut-in, 35% for probable behind-pipe, 25% for probable undeveloped reserves and 10% for possible reserves. Slightly higher RAFs are commonly used in the case of unconventional reserves. The median, or P50, RADRs most commonly used by respondents are 10% for PDP, 15% for PDNP, 21% for PUD, 25% for probable reserves and 27.5% for possible reserves.
Using the June 1, 2015 internal unrisked reserve numbers, the Company calculates its RAF value as $342 million and its RADR value as $794 million. These numbers compare with the Company’s unrisked Proved PV10 value of $328 million.
About Saratoga Resources
Saratoga Resources is an independent exploration and production company with offices in Houston, Texas and Covington, Louisiana. Principal holdings cover approximately 51,500 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. The Company filed voluntary Chapter 11 petitions for itself and certain operating subsidiaries in the U.S. Bankruptcy Court for the Western District of Louisiana on June 18, 2015. For more information, go to Saratoga’s website at www.saratogaresources.com and sign up for regular updates by clicking on the Updates button.
Oil and Gas Information
In estimating probable and possible reserves, it should be noted that those reserve estimates inherently involve greater risk and uncertainty than estimates of proved reserves. While analysis of geoscience and engineering data provides reasonable certainty that proved reserves can be economically producible from known formations under existing conditions and within a reasonable time, with at least a 90% probability that the quantities actually recovered will equal or exceed the estimate, probable reserves involve less certainty with reserves supporting a probable classification from a probabilistic analysis supported where there is at least a 50% probability that the actual quantities recovered will equal or exceed proved plus probable reserve estimates. Possible reserves involving even less certainty than probable reserves and possible classification is supported when there is at least a 10% probability that total quantities recovered equal or exceed proved plus probable plus possible reserve estimates.
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 the Company’s ability to realize the quantities and values of reserves indicated. 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. Specific risks pertaining to the reserve estimates stated in this press release include the Company’s ability to continue to operate its business and to manage its properties as debtors-in-possession, the sufficiency of cash on hand to support operations in the intermediate term, the ability of the Company to operate without debtor-in-possession financing, the ability of the Company to arrive at a satisfactory arrangement with its creditors, the ability of the Company to arrive at a satisfactory resolution of the Harvest Operating arbitration award, uncertainty as to expected future increases in oil and gas prices, the ability of the Company to fund development activities, the ultimate preservation of equity and the ultimate outcome of the Chapter 11 proceeding. 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.