Item 1.

Business

General

We are an independent oil and natural gas company engaged in the production, development, acquisition and exploitation of crude oil and natural gas properties. As of December 31, 2014, our properties consisted of approximately 51,500 acres under lease, including 31,700 acres gross/net located in the transitional coastline in protected in-bay environments on parish and state leases in south Louisiana and 19,800 acres gross/net under federal leases in the shallow Gulf of Mexico shelf.

Our state and parish leases span 11 fields which are characterized by over 30 years of development drilling and production history, including Grand Bay field which has over 70 years of production history and over 258 MMBoe produced to date, yet remains virtually unexplored at depths greater than 15,000 feet. Substantially all of our state and parish leases are held by production (“HBP”) without near-term lease expirations. Most of those properties offer multiple stacked reservoir objectives with substantial behind pipe potential.

Our shallow Gulf of Mexico shelf properties were acquired during 2013. At December 31, 2014, our shallow Gulf of Mexico shelf properties did not include any producing wells and we were engaged in efforts to seek partners to participate in development of such properties.  We continually seek to enhance our acreage position through leasing and evaluation of opportunistic acquisitions primarily within, but not limited to, the transition zone and in the shallow Gulf of Mexico.

As of December 31, 2014, our total proved reserves were 10.2 MMBoe, consisting of 5.8 MMBbls of oil and 26.6 Bcf of natural gas, approximately 73% of which was attributable to state and parish properties. The PV-10 of our proved reserves at December 31, 2014 was $209.3 million, based on SEC pricing. The PV-10 of our proved reserves, based on NYMEX strip pricing, was $69.4 million. Additionally, we had probable reserves of 25.9 MMBoe, consisting of 10.4 MMBbls of oil and 93.2 Bcf of natural gas. Moreover, our reserve base includes significant undeveloped and exploratory drilling opportunities.  We operate over 99% of the wells that comprise our PV-10, enabling us to effectively exercise management control of our operating costs, capital expenditures and the timing and method of development of our properties.

During 2014, we produced 670.1 MBoe, of which approximately 76% was oil and all of which was attributable to our state and parish properties. As of December 31, 2014, our development opportunities included 61 proved behind pipe and shut-in opportunities in 44 wells in 6 fields, 36 proved undeveloped opportunities within 15 proposed wells in 5 fields. An additional 61 formerly proved undeveloped opportunities within 21 proposed wells in 3 fields were re-classified as probable P90 reserves as required by the SEC five-year PUD rule.  Additionally, at December 31, 2014, we had 37 probable behind pipe and shut-in development opportunities. Additionally, at December 31, 2014, 41 probable undeveloped opportunities within 24 proposed wells in 4 fields, 13 possible behind pipe and shut-in development opportunities and 86 possible undeveloped opportunities within 33 wells in 5 fields.  During the year ended December 31, 2014, we successfully completed one development well, 6 recompletions, and 9 workovers.

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Our principal and administrative offices are located at 9225 Katy Freeway, Suite 100, Houston, Texas. Our telephone number is (713) 458-1560.

Our Strengths

High-Quality Resource Base.  Our principal assets are located in shallow waters on parish and state leases of south Louisiana in fields that are characterized by over 30 years of development drilling and production history. These assets are in close proximity to several other fields operated by leading industry companies such as Energy XXI Limited, Helis Oil and Gas Company, Hilcorp Energy Company, Swift Energy Company and Texas Petroleum Investment Company. Additionally, our shallow Gulf of Mexico shelf assets include proved reserves and prospects identified by 3-D seismic and are located in proximity to existing field infrastructure. We believe the quality and location of our properties reduce our development risk and promote operating efficiencies which help to reduce our lifting costs. Additionally, the oil produced by our assets currently commands a premium to WTI crude oil pricing.  We also believe that our reserve base has significant undeveloped and exploratory drilling opportunities.

Geographically Focused Assets Without Exposure to Deep Water Operating Risks.  Our proved reserves are primarily located in the shallow waters of the Grand Bay Field, Breton Sound 32 Field and 11 other fields on state and parish leases of south Louisiana and, to a lesser degree, in the shallow waters of the Gulf of Mexico shelf. This focused asset base allows us to leverage our technical knowledge of the geological features and operating dynamics within this region. Our geographic focus also enables us to establish economies of scale in both drilling and production operations, allowing us to manage a greater amount of acreage and minimize the marginal costs associated with development activities. Because our present operations are primarily in shallow state waters and, to a lesser extent, in the shallow Gulf of Mexico shelf, we are not exposed to the extreme risk associated with deep water operations. In addition, we are able to avoid the long lead times to first production and ultra-high costs associated with deep water development.

Extensive Workover and Drilling Inventory.  At December 31, 2014, we controlled approximately 51,500 gross/net acres, of which more than half is HBP. Approximately 81% of our proved reserves are classified as proved developed nonproducing and proved undeveloped reserves. We believe our properties hold substantial additional behind pipe reserves beyond the amounts quantified in the proved reserves category and provide us with a significant number of exploration prospects.  As of December 31, 2014, our development opportunities included 61 proved behind pipe and shut-in opportunities in 44 wells in 6 fields, 36 proved undeveloped opportunities within 15 proposed wells in 5 fields.  An additional 61 formerly proved undeveloped opportunities within 21 proposed wells in 3 fields were reclassified as probable P90 reserves as required by the SEC five year PUD rule.  Additionally, at December 31, 2014, we had 37 probable behind pipe and shut-in development opportunities, 41 probable undeveloped opportunities within 24 proposed wells in 4 fields, 13 possible behind pipe and shut-in development opportunities and 86 possible undeveloped opportunities within 33 wells in 5 fields.

High Net Revenue Interests and Operational Control.  We own an average net revenue interest in our properties of approximately 75%, which enhances our returns by reducing royalty payments and provides us flexibility in negotiating potential farm-outs, joint ventures, and other opportunities. Additionally, we own a 100% working interest in substantially all of our properties and operate over 99% of the wells that comprise our PV-10 as of December 31, 2014. As an operator, we can more efficiently manage our operating costs, capital expenditures and the timing and method of development of our properties. Our significant operational control and expertise in the area should allow us to operate with a lower cost structure and maximize returns on capital employed.

Control of Infrastructure and Third-Party Processing Revenues.  Our extensive infrastructure assets include six production platforms and over 100 miles of pipeline, mostly within the Main Pass and Breton Sound areas. Our infrastructure assets enhance our ability to expand our existing resource base through joint ventures with, and acquisitions of, neighboring producing properties and to generate revenues from third-party handling and processing.

Experienced Management Team.  Our directors and executive officers have over 270 combined years of industry experience and a proven track record of successfully leading independent oil and natural gas companies. In addition, our management team has extensive major oil company operational expertise with particular emphasis on cost-control and reservoir management.

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Our Strategy

We intend to use our competitive strengths to increase our reserves, production and cash flow. The following are key elements of our strategy:

Grow Through Exploitation, Development and Exploration of Our Properties.  We believe that our extensive HBP acreage position will allow us to grow organically through lower-risk development drilling and recompletion work. We have attractive opportunities to expand our reserve base through field extensions, delineating shallower and deeper formations within existing fields and exploratory drilling. Most of our locations offer multiple stacked reservoir objectives with substantial behind pipe potential. We intend to focus our efforts on exploiting our inventory of opportunities with a view to growing our production through a combination of field optimization efforts, including infrastructure upgrades, and conversion of PDNP and proved undeveloped reserves to PDP, and through participation via farm-outs or promoted deals in development of our acreage on the Gulf of Mexico shelf.  Development work is expected to be spread over several fields.  In order to enhance our organic growth initiatives, we have made significant investments in, and will continue to invest in, our infrastructure to support increased handling capacity and create operating efficiencies to lower handling and other operating costs.

Actively Manage the Risks and Rewards of Our Drilling Program.  We operate over 99% of the wells that comprise our proved reserves as of December 31, 2014, and we own net revenue interests in our properties that average approximately 75% on a net acreage leasehold basis. We believe operating our properties is important because it allows us to control the timing and costs in our drilling budget, as well as control operating costs and production marketing. In addition, our high net revenue interests enhance our returns from each successful well we drill by generating a higher percentage of cash flow. We believe our high net revenue interests provide us with a unique opportunity to retain a substantial economic interest in riskier wells, including wells that may be drilled on the Gulf of Mexico shelf acreage, while mitigating the risk associated with these projects through farm-outs or promoted deals. Additionally, we will review and rationalize our properties on a continuous basis in order to optimize our existing asset base.

Leverage Technological Expertise.  We believe that 3-D seismic analysis and other advanced technologies and production techniques are useful tools that help improve drilling results and ultimately enhance our production and returns. At December 31, 2014, we either owned or held licenses for 3-D seismic data covering over 90 square miles in Grand Bay and other fields. We intend to utilize these technologies and production techniques in exploring for, developing and exploiting oil and natural gas properties to help us reduce drilling risks, lower finding costs and provide for more efficient production of oil and natural gas from our properties. We believe that the use of these technologies enhances our probability of locating and producing reserves that might not otherwise be discovered.

We have conducted and will continue to complete full field studies over all of our properties.  Such field studies include an exhaustive review and integration of well data, wellbore utilization analysis, incorporation of 3-D seismic interpretation results and detailed geological mapping of each sand.

Optimize Development Results and Well Production Through Identification and Development of Horizontal and High Angle Prospects.  As a result of our exhaustive field studies, and based on initial drilling results, we believe that our assets offer opportunities to optimize our investment of development capital and resulting production through focusing on the identification and development of horizontal and high angle prospects.  Consistent with limited historical horizontal development activities on our properties, we undertook our first horizontal and high angle wells during 2013 with favorable results.  We intend to capitalize on our experience in such wells to identify and develop additional horizontal and high angle prospects going forward and, based on results to date, expect to see improved well economics on such prospects.

Pursue Opportunistic Acquisitions.  We are an opportunity driven company and, to that end, evaluate potential acquisitions that are compatible with and enhance our growth objectives.  We continually review opportunities to acquire producing properties, leasehold acreage and drilling prospects. In addition to a large inventory of exploration prospects within our HBP lease position, we have identified a large inventory of exploration prospects in unleased state acreage in close proximity to our existing infrastructure in the Main Pass and Breton Sound areas and shallow Gulf of Mexico shelf acreage that we may pursue in the near future.  When identifying acquisition candidates, we focus primarily on underdeveloped assets with significant growth potential that we believe will allow us to enhance and exploit properties without assuming significant geologic, exploration or integration risk.

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Properties

The following table describes our properties, proved reserves and production profile at December 31, 2014:

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*

Not meaningful

(1)

Based on unweighted average benchmark prices as of the first of each month during 2014 of $94.99 per Bbl and $4.35 per MMBtu and before future income taxes. The average realized price after applying differential to unweighted average benchmark prices was $96.30 per Bbl and $4.47 per Mcf. PV 10 is a non GAAP financial measure as defined by the SEC.

(2)

Calculated by dividing total net proved reserves by current net production for December 2014.

Louisiana Transition Zone

Our principal producing properties are located in the transitional coastline in protected in-bay environments on parish and state leases in south Louisiana, an area commonly referred to as the “transition zone.”  The majority of those properties were acquired in, and we have operated those properties since, 2008.  Our properties in the transition zone span 11 fields with principal properties, by production and reserves, being in Grand Bay, Breton Sound 18 and Breton Sound 32 fields.

Grand Bay Field.  The Grand Bay Field is located in Plaquemines Parish, approximately 70 miles southeast of New Orleans, Louisiana. It is situated in the transitional coastline in a protected in-bay environment on parish and state leases on the east side of the Mississippi River. Gulf Oil discovered the field in 1938. Saratoga is the operator of all of the Grand Bay Field with 100% working interest and net revenue interests ranging from70% to 79%. Our leases in the Grand Bay Field, which are all HBP, cover an estimated 17,391 gross and net acres.

The Grand Bay Field is a large, faulted anticlinal structure. It lies on a northwest/southeast trending, deep-seated salt ridge that also sets up Coquille Bay Field, to the northwest, and Romere Pass Field, to the southeast. Trapping is predominantly from intersecting fault closures associated with this anticlinal feature, although there are cases of stratigraphic trapping. The predominant drive mechanism is water drive. Some productive formations are clean, blocky sands with high-resistivity pay. Other laminated, low-resistivity sands are also productive. Shallow sands are predominantly gas-filled and associated with anomalous amplitudes. There are additional shallow amplitudes in the field that have not yet been drilled or logged.

The Grand Bay field has produced oil and gas from over 65 different sand formations located at depths between approximately 1,600 and 13,500 feet. Our field holdings include approximately 66 active wellbores, 50 proved developed nonproducing opportunities and 23 proved undeveloped opportunities in 8 proposed drilling locations within the field.  An additional 48 formerly proved undeveloped opportunities within 14 proposed wells were reclassified as probable P90 reserves as required by the SEC five year PUD rule. There are also 28 probable developed nonproducing, 27 probable undeveloped opportunities in 18 proposed drilling locations, 12 possible developed nonproducing and 41 possible undeveloped opportunities in 16 proposed drilling locations within the field.  We are planning to undertake one or more reservoir simulations in the field in 2015. Based on one previous horizontal well drilled in Grand Bay field, with favorable results, we are actively seeking horizontal and high angle well candidates in Grand Bay field. Another important part of our ongoing analysis of Grand Bay is the geopressured sequence incorporating the Tex L (25 sand) and Cib Carst (43 sand) reservoirs, below 13,000 feet, which has been largely unexplored to date.  We have identified multiple opportunities within the sequence and will continue our efforts to seek third parties to drill the initial prospect within the sequence once commodity prices recover.

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We own a license to 90 square miles of proprietary 3-D seismic data relating to the Grand Bay Field, which was originally acquired by Greenhill in 1994 and reprocessed by Saratoga in 2008, 2010, 2012 and 2013.  We expect to use this dataset to better locate proposed development wells and deep oil and gas targets below existing production.

Facilities include a central compressor station, four tank batteries, numerous gas lift manifolds and a bunk house, from which all field operations are controlled. Low pressure, high Btu-content gas at Grand Bay Field is used to lift oil and high pressure, lower Btu-content gas. We continue to look for ways to decrease operating costs in all fields.

Breton Sound Block 32 Field. Breton Sound Block 32 field is located in Plaquemines Parish, Louisiana, approximately 45 miles ESE of New Orleans, Louisiana. It is situated in the transitional coastline in a protected in-bay environment on parish and state leases on the east side of the Mississippi River.  The field was discovered by Barnsdall in 1949 but most of the field development was undertaken by Kerr-McGee who sold the field to LLOG who, in turn, sold the field to Amerada Hess. Saratoga acquired its interest from Amerada Hess in September 2006. Saratoga operates the field with 100% WI. There are two principal HBP leases associated with the field, SL 1227 and SL 15536 plus an additional 9 HBP leases and an additional primary term lease, SL 21247, associated with a deeper Tex W objective with shallow PUD reserves.

Breton Sound Block 32 field is a broad, low-relief anticlinal structure with rollover into a large west-east trending down-to-the-south fault. The reservoir drive mechanisms are water drive for the principal 5750’ and 5800’ sands and combination water drive/pressure depletion for other reservoirs. Production has been from between approximately 5,300' and 11,500', subsea. Our field holdings include approximately 17 active wellbores and 5 proved undeveloped opportunities in 3 proposed drilling locations within the field. There are also 2 probable developed nonproducing, 4 probable undeveloped opportunities in 1 proposed drilling location and 5 possible undeveloped opportunities in 4 proposed drilling locations within the field. Saratoga has successfully drilled and completed 3 horizontal wells in the field since 2013 and plans more horizontal development wells once the results of its reservoir simulation project have been analyzed in the first half of 2015.

Facilities include a centrally-located, manned, platform complex in 10 feet of water to which wells are tied back subsea. Production from the field is transported approximately 2 miles to the NW via Saratoga-owned flowlines to where it ties into a 20” sales line. We have licensed a high-quality 3-D seismic survey that covers the field and we have undertaken seismic reprocessing of these data to enhance data quality.

During 2014, we drilled and completed the “Rocky 3” horizontal development well in Breton Sound 32 field which targeted an elongated ridge in the 5,800’ sand with a 750’ lateral completion.

Breton Sound Block 18 Field. The Breton Sound Block 18 Field is located in Plaquemines Parish, Louisiana, approximately 45 miles east-southeast of New Orleans, Louisiana. It is situated in the transitional coastline in a protected in-bay environment on parish and state leases on the east side of the Mississippi River. The older field proper was discovered in 1963. The newer portion of the field, where Saratoga's interests are located, was discovered in 2000 by LLOG, who sold the field to Amerada Hess. Saratoga acquired their interest from Amerada Hess in September 2006. Saratoga owns 100% and is the operator. There are 7 HBP leases associated with the field and one primary term lease.

The Breton Sound Block 18 Field is a faulted, anticlinal structure, with outlying stratigraphic traps. It is one of a series of stratigraphic trap-type fields in the eastern Louisiana coastal offshore Middle Miocene trend that was discovered with 3-D seismic technology. The reservoir drive mechanisms are water drive and combination water drive/pressure depletion. Production has been between approximately 3,500' and 9,700', subsea.

Facilities include a centrally-located, unmanned, platform in 10 feet of water to which wells are tied back subsea. Production from the field is transported to the Breton Sound Block 32 Field. We have licensed a high-quality 3-D seismic survey that covers the field and we have undertaken seismic reprocessing of these data to enhance data quality.

Other Fields.  We hold interests in 10 other fields, 8 of which are located in shallow waters on state leases in Plaquemines, St. Bernard and St. Mary parishes of southern Louisiana and 2 of which are in the shallow waters of the Gulf of Mexico. We have 100% working interest in all fields, except for the Main Pass 47 Field, where we have a 7.5% overriding royalty interest in one producing well.  Our net revenue interests in these fields average 75%.  The leases, which are mostly HBP, cover 29,137 gross/net acres.

Among the other fields in which we hold interests are the Main Pass Block 25, Main Pass Block 46, Main Pass Block 52 and Vermilion Block 16 fields. We operate all these fields with a 100% working interest. We have unmanned platforms at each of these fields and wells are tied back subsea to our facilities.

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There appears to be renewed interest in the high profile, ultra-deep play following Freeport-McMoRan’s recent onshore success at their Highlander Prospect so we will continue to evaluate the ultra-deep potential underlying our Grand Bay and Vermilion Block 16 fields.

Gulf of Mexico Shelf.

In July 2013, final leases were awarded pursuant to our high bid on four leases, with seismic maps included, totaling 19,814 acres in the Central Gulf of Mexico Lease Sale 227.  The acreage is in the shallow Gulf of Mexico shelf in water depths of 13 to 77 feet.  Two of the leases are in the Vermilion area and two of the leases are in the Ship Shoal area.  The leases have a primary term of five years and can be extended for an additional three years.  Lease bonuses on the prospects totaled $880,000 and we paid a prospect fee of $500,000 to a third party consultant.  The cost of the leases, in the amount of $1,380,000, has been recorded in oil and gas properties.  Annual rentals on the leases total $138,698 during the primary term.

Using licensed 3-D surveys, four initial prospects, two of which have proved undeveloped reserves, have been identified within the Gulf of Mexico shelf acreage.  With the drop in commodity prices during the second half of 2014, we have put efforts to drill those prospects on hold.  We expect to resume efforts to seek partners to drill the first of the prospects at such time as commodity prices support such efforts.  The acreage includes proved undeveloped reserves at December 31, 2014 of 2.74 MMBOE.

Field Infrastructure

We own significant infrastructure assets that are used to service our properties and third-party customers, including over 100 miles of pipeline connecting several of the fields as well as outlying wellheads. There are five platform facilities plus 35 active producing wellbores associated with the Main Pass and Breton Sound fields and one platform plus two active producing wellbores at Vermilion Block 16 field. Facilities at the Grand Bay Field include four tank batteries, a compressor station, various flow lines and a bunk house and there are 58 active producing wellbores in the field. In addition to serving our wells and improving field economics, we generate processing and production handling revenues from third-party customers. We also operate approximately eight saltwater disposal wells.

Oil and Natural Gas Reserves

Reserve Estimates

SEC Case.  The following tables sets forth, as of December 31, 2014, our estimated net proved oil and natural gas reserves, the estimated present value (discounted at an annual rate of 10%) of estimated future net revenues before future income taxes (PV-10) and after future income taxes (Standardized Measure) of our proved reserves and our estimated net probable and possible oil and natural gas reserves, each prepared in accordance with assumptions prescribed by the Securities and Exchange Commission (SEC). All of our reserves are located in the United States.

The PV-10 value is a widely used measure of value of oil and natural gas assets and represents a pre-tax present value of estimated cash flows discounted at ten percent. PV-10 is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the estimated discounted future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies because of differences in the amounts and timing of deductible basis, net operating loss carry-forwards and other factors. We believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.

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(1)

In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the PV-10 set forth herein reflect estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions at December 31, 2014. For purposes of determining prices, we used the unweighted arithmetical average of the prices on the first day of each month within the 12-month period ended December 31, 2014 which were $94.99 per Bbl and $4.35 per MMBtu. The prices utilized for purposes of estimating our proved reserves were $96.30 per Bbl and $4.47 per Mcf, after adjustment by property for energy content, quality, transportation fees and regional price differentials. The prices should not be interpreted as a prediction of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate general administrative expenses and debt service, future income taxes or to depreciation, depletion and amortization.

(2)

Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent.

(3)

Probable and possible reserves have not been discounted for the risk associated with future recovery.

(4)

The Standardized Measure differs from PV-10 only in that the Standardized Measure reflects estimated future income taxes.

Due to the inherent uncertainties and the limited nature of reservoir data, proved, probable and possible reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

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, probable reserves involve less certainty with reserves supporting a probable classification from a probabilistic analysis where those reserves are “as likely as not to be recovered.” 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.

Alternative Pricing Case.  We use forward-looking market-based data in developing our drilling plans, assessing our capital expenditure needs and projecting future cash flows. The table below compares our estimated proved reserves and associated present value (discounted at an annual rate of 10%) of estimated future revenue before income taxes using the 2014 12-month average prices reflected in our reported reserve estimates and the NYMEX future strip prices as of December 31, 2014.

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(1)

Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent.

(2)

The NYMEX Strip Pricing Case discloses our estimated proved reserves using future market-based commodities prices instead of the average historical prices used in the SEC Case. Under the NYMEX Strip Pricing Case, we used futures prices, as quoted on the New York Mercantile Exchange (“NYMEX”) on December 31, 2014, as benchmark prices for 2015 through 2022, and continued to use the 2022 futures price for all subsequent years. These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $67.58 per barrel of oil and $3.84 per Mcf of natural gas over the remaining life of the proved reserves. There is no change to our cost or other assumptions between this higher price scenario and those used in the estimation of our reported reserves.

Reserve Estimation Process, Controls and Technologies

The reserve estimates, including PV-10 and Standard Measure estimates, set forth above were prepared by Collarini Associates for our transition zone reserves (83.6% of PV-10 of our total proved reserves) and internally for our Gulf of Mexico shelf reserves (16.4% of PV-10 of our total proved reserves).

These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.

We maintain an internal staff of engineering and geoscience professionals that prepare and review internal reserve estimates and work with third-party engineering firms in the preparation of their reserve estimates, all under the leadership and direction of our President, a degreed petroleum geologist/geophysicist with over 30 years of technical experience involving petroleum reserve assessment and estimation and geoscience-based evaluation. Our technical staff works closely with Collarini Associates (the “outside reserve engineers”) in connection with their preparation of our reserve estimates, including assessing the integrity, accuracy and timeliness of the methods and assumptions used in this process. Our technical team members meet with outside reserve engineers periodically throughout the year to discuss the assumptions and methods used in the reserve estimation process. We provide historical information to the outside reserve engineers for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Our engineering and geosciences staff coordinate with our accounting and other departments to provide the appropriate data to the outside reserve engineers in support of the reserve estimation process and to assure that information derived from the outside reserve engineers’ reports is properly disclosed in our reports.

Collarini Associates is an independent Houston and New Orleans-based professional engineering firm specializing in technical and financial evaluation of oil and gas assets. Their report with respect to our transition zone reserves was prepared under the direction of Collarini Associates’ President and Engineering Manager, Mitch Reece. Mr. Reece holds a B.S. in petroleum engineering from Texas A&M University, is a registered professional engineer and has approximately 30 years of experience in production engineering, reservoir engineering, acquisitions and divestments, field operations and management.

The SEC’s rules with respect to technologies that a company can use to establish reserves, effective for years ending after December 31, 2008, allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Our technical staff and our outside reserve engineers used a combination of production and pressure performance, simulation studies, offset analogies, seismic data and interpretation, geophysical logs and core data to calculate our reserves estimates.

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Proved Undeveloped Reserves

Our proved undeveloped reserves accounted for approximately 63% of our total reserves at December 31, 2014.  As of December 31, 2014, none of our proved reserved had been classified as proved undeveloped for more than five years and the majority of the properties for which we have proved undeveloped reserves have ongoing production from currently developed zones.  The following table summarizes activity within our proved undeveloped reserve category for the years ended December 31, 2014 and 2013:

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(1)

Proved undeveloped reserves added through acquisitions during 2013 relate to Gulf of Mexico shelf acreage leased during 2013.

(2)

Represents downward revisions at December 31, 2014 and 2013 associated with SEC’s “five year” rule under which reserves are generally to be removed from presentation as proved reserves if not developed within five years of initially being booked in the proved undeveloped category.

Our proved undeveloped reserves at December 31, 2014 were associated with our Louisiana properties (3,719 MMBoe) and our Gulf of Mexico shelf properties (2,737 MMBoe).

We incurred costs relating to the development of proved undeveloped reserves of $5.7 million and $17.3 million during 2014 and 2013, respectively.

All proved undeveloped locations are scheduled to be drilled, or otherwise converted into proved developed reserves, before the end of 2019. None of our proved undeveloped locations have been booked for longer than five years.

Production, Price and Production Cost History

The table below sets forth certain information regarding the production volumes, average prices received and average production costs associated with our sale of oil and natural gas for the three years ended December 31, 2014.

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(1)

Average production cost per Boe excludes severance taxes.

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Drilling and Development Activity

The following table summarizes our drilling activity for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.

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(1)

The success ratio is calculated as follows: (total wells drilled—non-productive wells—wells awaiting completion)/(total wells drilled—wells awaiting completion).

A well’s completion is reported in the year of completion regardless of when drilling was initiated. Productive wells are wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

In addition to the wells completed, during 2014 we successfully completed 6 out of 9 recompletion and 9 out of 14 workover operations, with one workover operation still in progress at year end.  During 2013 we successfully completed 17 out of 22 recompletion and 9 out of 10 workover operations.

The foregoing information should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and natural gas that may ultimately be recovered by us. We do not own any drilling rigs and all of our drilling activities are conducted by independent drilling contractors.

At December 31, 2014, there were no wells being drilled or recompletion or workover operations being conducted.

Productive Wells

The following table sets forth information with respect to our ownership interest in productive wells, all of which are located in the United States, as of December 31, 2014:

Productive wells are producing wells and wells mechanically capable of production. A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. Wells with multiple completions are counted as one well in the table above. The total gross wells at December 31, 2014 included no wells with multiple completions.

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Developed and Undeveloped Acreage

The following table sets forth information with respect to our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2014:

Developed acreage is comprised of leased acres that are within an area spaced by or assignable to a productive well. Undeveloped acreage is comprised of leased acres with defined remaining terms and not within an area spaced by or assignable to a productive well.

As is customary in the oil and natural gas industry, we can generally retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which we have an interest are for varying primary terms and, if production under a lease continues from our developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production.

Marketing, Customers and Pricing

General

We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.

Marketing

Effective April 1, 2010, we entered into a Natural Gas, Crude and Processing Marketing/Administration Agency Agreement pursuant to which Transparent Energy Services, Inc. markets substantially all of our oil and natural gas production.

We generally market our oil and natural gas production under “month-to-month” or “spot” contracts.

We receive a premium price for our Light Louisiana Sweet (LLS) and Heavy Louisiana Sweet (HLS) crude oil produced. We attribute this premium pricing to the high quality and geographic location of the crude oil product. This combination of production location and crude oil quality have allowed us to sell our crude oil at prices above WTI price postings beginning in the second half of 2011 and continuing through 2014, and we anticipate that market conditions should allow us to continue to receive pricing above WTI postings into 2015.

Sales of oil and gas production to Shell Trading (US) Company and Shell Energy North America (US), L.P. (collectively “Shell”) and Chevron Natural Gas, Inc. and Chevron Products Company (collectively “Chevron”) accounted for 50% and 37% of our consolidated sales in 2014, respectively. Sales of oil and gas production to Shell and Chevron accounted for 57% and 32% of our consolidated sales in 2013, respectively. We believe that the loss of any of these purchasers would not have a material adverse effect on us because alternative purchasers are readily available.

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Derivatives

During the third quarter of 2012, we resumed our hedging program which had previously been suspended in February 2010. We use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and future capital programs. From time to time, we may enter into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts; however, it is our preference to utilize hedging strategies that provide downside commodity price protection without unduly limiting our revenue potential in an environment of rising commodity prices. We use hedging primarily to manage price risks and returns on certain drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive.

As of December 31, 2014, we had the following crude oil hedge contracts outstanding:

Koch Supply and Trading, LP is the counterparty to our present covered call option. We are exposed to credit losses in the event of nonperformance by the counterparty on our commodity derivatives positions.  However, we do not anticipate nonperformance by the counterparty over the term of the commodity derivatives positions.

Competition

We encounter intense competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and gas companies, numerous independent oil and gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and gas business for a much longer time than our company. These companies may be able to pay more for productive oil and gas properties, exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

Employees

As of December 31, 2014, we had 32 full time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are positive. From time to time, we utilize the services of independent contractors to perform various field and other services.

Regulation of the Oil and Gas Industry

The oil and gas industry is subject to regulation by numerous national, state and local governmental agencies and departments. Compliance with these regulations is often difficult and costly and noncompliance could result in substantial penalties and risks. Most jurisdictions in which we operate also have statutes, rules, regulations or guidelines governing the conservation of natural resources, including the unitization or pooling of oil and gas properties and the establishment of maximum rates of production from oil and gas wells. Some jurisdictions also require the filing of drilling and operating permits, bonds and reports. The failure to comply with these statutes, rules and regulations could result in the imposition of fines and penalties and the suspension or cessation of operations in affected areas.

We operate various gathering systems and pipelines servicing the areas in which we operate. The United States Department of Transportation and certain governmental agencies regulate the safety and operating aspects of the transportation and storage activities of these facilities by prescribing standards. However, based on current standards concerning transportation and storage activities and any proposed or contemplated standards, we believe that the impact of such standards is not material to our operations, capital expenditures or financial position. All of our sales of our natural gas are currently deregulated, although governmental agencies may elect in the future to regulate certain sales.

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Regulations Affecting Production

The jurisdictions in which we operate generally require permits for drilling operations, drilling bonds and operating reports and impose other requirements relating to the exploration and production of oil and gas. Such jurisdictions also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production.

These laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many jurisdictions impose a production or severance tax with respect to the production and sale of oil and natural gas within their jurisdiction. There is generally no regulation of wellhead prices or other, similar direct economic regulation of production, but there can be no assurance that this will remain true in the future.

Regulation of Transportation and Sale of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Interstate oil pipeline rates are typically set based on a cost of service methodology (“Cost-Based Rates”); however, they may also be set based on the competitive market (“Market-Based Rates”) or by agreement between the pipeline and its shippers (“Settlement Rates”). Some oil pipeline rates may be increased pursuant to an index methodology, whereby the pipeline may increase its rates up to a ceiling set by reference to the Producer Price Index for Finished Goods (unless the rate increase is shown to be substantially in excess of the actual cost increases incurred by the pipeline). Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

The FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

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Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Gathering Regulations

Section 1(b) of the federal Natural Gas Act (“NGA”) exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. Although FERC has not made any formal determinations with respect to any of the natural gas gathering pipeline facilities that we own, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to establish a pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities, however, has been the subject of substantial litigation and, over time, FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and gathering facilities, on the other, is a fact-based determination made by FERC on a case-by-case basis. The classification and regulation of our gathering lines may be subject to change based on future determinations by FERC, the courts or the U.S. Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation. Our gathering operations may also be subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. In addition, our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner differently than other companies in our areas of operation.

Outer Continental Shelf Regulations

Our planned operations on federal oil and gas leases in the Gulf of Mexico are subject to regulation by the Bureau of Safety and Environmental Enforcement (“BSEE”) and the Bureau of Ocean Energy Management (“BOEM”), successor agencies to the Minerals Management Service. These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the Outer Continental Shelf Lands Act (“OCSLA”). These laws and regulations are subject to change, and many new requirements were imposed by the BSEE and BOEM subsequent to the April 2010 Deepwater Horizon incident. For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency, (the “EPA”), lessees must obtain a permit from the BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the OCS, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities. To cover the various obligations of lessees on the OCS, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, the BOEM generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the BOEM exempts the lessee from such obligations. The cost of such bonds or other surety can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. As a result of the recent bankruptcy of ATP Oil and Gas, the BOEM has indicated that it may review the estimated cost of future plugging, abandonment, decommissioning and removal obligations of other OCS operators and may increase the amount of financial assurance required with respect to these obligations. Under certain circumstances, the BSEE, a new federal agency created to enforce compliance with safety and environmental rules applicable to OCS activities, may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations.

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Environmental Regulation

Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the discharge and disposition of generated waste materials and waste management, the reclamation and abandonment of wells, sites and facilities, financial assurance under the Oil Pollution Act of 1990 and the remediation of contaminated sites. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.

We routinely obtain permits for our facilities and operations in accordance with applicable laws and regulations on an ongoing basis. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations.

The ultimate financial impact of environmental laws and regulations is neither clearly known nor easily determined as new standards are enacted and new interpretations of existing standards are rendered. Environmental laws and regulations are expected to have an increasing impact on our operations. In addition, any non-compliance with such laws could subject us to material administrative, civil or criminal penalties, or other liabilities. Potential permitting costs are variable and directly associated with the type of facility and its geographic location. Costs, for example, may be incurred for air emission permits, spill contingency requirements, and discharge or injection permits. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations.

We are committed to the protection of the environment throughout our operations and believe our operations are in substantial compliance with applicable environmental laws and regulations. We believe environmental stewardship is an important part of our daily business and will continue to make expenditures on a regular basis relating to environmental compliance. We maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully insured against all such risks. The insurance coverage maintained by us provides for the reimbursement to us of costs incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course of our operations, but such insurance does not fully insure pollution and similar environmental risks. We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our consolidated and combined financial position or our results of operations. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.

The environmental laws and regulations applicable to us and our operations include, among others, the following United States federal laws and regulations:

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Resource Conservation and Recovery Act, which governs the management of solid waste;

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Comprehensive Environmental Response, Compensation and Liability Act, which imposes liability where hazardous releases have occurred or are threatened to occur (commonly known as “Superfund”);

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Clean Water Act, which governs discharges to waters of the United States;

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Oil Pollution Act of 1990, which imposes liabilities resulting from discharges of oil into navigable waters of the United States;

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Clean Air Act, and its amendments, which govern air emissions;

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Emergency Planning and Community Right-to-Know Act, which requires reporting of toxic chemical inventories;

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Safe Drinking Water Act, which governs the underground injection and disposal of wastewater;

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Endangered Species Act and Migratory Bird Treaty Act, which prohibit certain actions that adversely affect endangered or threatened species and migratory birds and their habitat;

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U.S. Department of Interior and U.S. Environmental Protection Agency regulations, which impose liability for pollution cleanup and damages; and

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Occupational Safety and Health Act (OSHA) and comparable state laws and regulations that establish workplace standards for the protection of the health and safety of employees.

The following is a summary of certain existing laws, rules and regulations to which our business operations are subject:

Waste Handling

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are not currently regulated under RCRA or state hazardous waste provisions though our operations may produce waste that does not fall within this exemption. However, these oil and gas production wastes may be regulated as solid waste under state law or RCRA. It is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation, and Liability Act

The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the Superfund Law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

In the course of our operations, we generate wastes that may fall within CERCLA’s definition of hazardous substances. Further, we currently own, lease or operate properties that have been used for oil and natural gas exploration and production for many years. Hazardous substances or petroleum may have been released on, at, under or from the properties owned, leased or operated by us, or on, at, under or from other locations, including off-site locations, where such hazardous substances or other wastes have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose handling, treatment and disposal of hazardous substances, petroleum, or other materials or wastes were not under our control. These properties and the substances or materials disposed or released on, at, under or from them may be subject to CERCLA, RCRA or analogous or other state laws. Under such laws, we could be required to remove previously disposed hazardous substances and address any resulting impacts.

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances into waters of the United States or state waters. Under these laws, the discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

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The Oil Pollution Act of 1990, or OPA, which amends and augments the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. In addition, OPA and regulations promulgated pursuant thereto impose a variety of regulations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. OPA also requires certain oil and natural gas operators to develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance.

Air Emissions

The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations. Oil and gas operations may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants, including volatile organic compounds, nitrous oxides, and hydrogen sulfide.

Endangered Species, Wetlands and Damages to Natural Resources

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and gas exploration or production or seek damages to species, habitat, or natural resources resulting from filling or construction or releases of oil, wastes, hazardous substances or other regulated materials.

Climate Change Legislation and Greenhouse Gas Regulation

Federal, state and local laws and regulations are increasingly being enacted to address concerns about the effects the emission of “greenhouse gases” may have on the environment and climate worldwide. These effects are widely referred to as “climate change.” Since its December 2009 endangerment finding regarding the emission of greenhouse gases, the EPA has begun regulating sources of greenhouse gas emissions under the federal Clean Air Act. Among several regulations requiring reporting or permitting for greenhouse gas sources, the EPA finalized its “tailoring rule” in May 2010 that determines which stationary sources of greenhouse gases are required to obtain permits to construct, modify or operate on account of, and to implement the best available control technology for, their greenhouse gases. In November 2010, the EPA also finalized its greenhouse gas reporting requirements, beginning in March 2012, for certain oil and gas production facilities.

Moreover, in the recent past the U.S. Congress has considered establishing a cap-and-trade program to reduce U.S. emissions of greenhouse gases. Under past proposals, the EPA would issue or sell a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of such legislation, if ever adopted, would be to impose increasing costs on the combustion of carbon-based fuels such as crude oil, refined petroleum products, and natural gas. In addition, while the prospect for such cap-and-trade legislation by the U.S. Congress remains uncertain, several states have adopted, or are in the process of adopting, similar cap-and-trade programs.

As a crude oil and natural gas company, the debate on climate change is relevant to our operations because the equipment we use to explore for, develop and produce crude oil and natural gas emits greenhouse gases. Additionally, the combustion of carbon-based fuels, such as the crude oil and natural gas we sell, emits carbon dioxide and other greenhouse gases. Thus, any current or future federal, state or local climate change initiatives could adversely affect demand for the crude oil and natural gas we produce by stimulating demand for alternative forms of energy that do not rely on the combustion of fossil fuels, and therefore could have a material adverse effect on our business. Although our compliance with any greenhouse gas regulations may result in increased compliance and operating costs, we do not expect the compliance costs for currently applicable regulations to be material. Moreover, while it is not possible at this time to estimate the compliance costs or operational impacts for any new legislative or regulatory developments in this area, we do not anticipate being impacted to any greater degree than other similarly situated competitors.

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Web Site Access to Reports

Our Web site address is www.saratogaresources.com. We make available, free of charge on or through our Web site, our annual report, Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments to these reports as soon as reasonably practicable after such material is electronically filed with, or furnished to, the United States Securities and Exchange Commission.  Information contained on, or accessible through, our website is not incorporated by reference into this Form 10-K.

Item 1A.

Risk Factors

Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments.

Risks Related to Our Business

The nature of our business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

We engage in exploration and development drilling activities, which are inherently risky. These activities may be unsuccessful for many reasons. In addition to a failure to find oil or natural gas, drilling efforts can be affected by adverse weather conditions (such as hurricanes and tropical storms in the U.S. Gulf Coast region), cost overruns, equipment shortages and mechanical difficulties. Therefore, the successful drilling of an oil or gas well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, could cause a well to become uneconomic or only marginally economic. In addition to their costs, unsuccessful wells could impede our efforts to replace reserves.

Our business involves a variety of operating risks, which include, but are not limited to:

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fires;

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explosions;

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blow-outs and surface cratering;

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uncontrollable flows of gas, oil and formation water;

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natural disasters, such as hurricanes and other adverse weather conditions;

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pipe, cement, subsea well or pipeline failures;

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casing collapses;

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mechanical difficulties, such as lost or stuck oil field drilling and service tools;

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abnormally pressured formations; and

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environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharge of toxic gases.

If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses due to costs and/or liability incurred as a result of:

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injury or loss of life;

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severe damage to and destruction of property, natural resources and equipment;

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pollution and other environmental damage;

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clean-up responsibilities;

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regulatory investigations and penalties;

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suspension of our operations; and

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repairs to resume operations.

Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.

Unlike other entities that are geographically diversified, all of our assets and operations are located in , and offshore of, South Louisiana and we do not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. Our lack of diversification may:

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subject us to numerous economic, competitive and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate; and

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result in our dependency upon a single or limited number of hydrocarbon basins.

In addition, the geographic concentration of our properties in the Gulf Coast region means that some or all of the properties could be affected should the region experience:

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severe weather, such as hurricanes and other adverse weather conditions;

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delays or decreases in production, the availability of equipment, facilities or services;

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delays or decreases in the availability of capacity to transport, gather or process production; and/or

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changes in the regulatory environment.

For example, our oil and gas properties were damaged, prior to our acquisition of those properties, by both Hurricanes Katrina and Rita, and, since our acquisition of the properties, by Hurricanes Gustav, Ike and Isaac. This damage required us, and the prior owners, to spend time and capital on inspections, repairs and debris removal. In accordance with industry practice, we maintain insurance against some, but not all, of these risks and losses. For additional information, please read “—Our insurance may not protect us against all of the operating risks to which our business is exposed.”

Because all or a number of the properties could experience many of the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.

Oil and natural gas prices are volatile, and a substantial or extended decline in oil and natural gas prices would adversely affect our financial results and impede our growth.

Our financial condition, revenues, profitability and carrying value of our properties depend upon the prevailing prices and demand for oil and natural gas. Commodity prices also affect our cash flow available for capital expenditures and our ability to access funds through the capital markets. The markets for these commodities are volatile and even relatively modest drops in prices can affect our financial results and impede our growth.

Natural gas and oil prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

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domestic and foreign supplies of oil and natural gas;

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price and quantity of foreign imports of oil and natural gas;

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actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;

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level of consumer product demand, including as a result of competition from alternative energy sources;

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level of global oil and natural gas inventories;

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political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;

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weather conditions;

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technological advances affecting oil and natural gas production and consumption;

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overall U.S. and global economic conditions; and

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price and availability of alternative fuels.

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower oil and natural gas prices may not only decrease our expected future revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in us having to make downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.

During the second half of 2014 and continuing into 2015, commodity prices, particularly oil prices, dropped sharply attributable to a number of factors, including growing supplies attributable to U.S. shale and other development and foreign supplies coming on line in the face of a projected slowing global economy and expected lower demand. As a result, we have seen our average price realized from the sale of oil decline from $97.45 per barrel of crude oil in December 2013 to $58.26 per barrel in December 2014.  The sharp decline in prices has resulted in lower sales revenues and operating cash flow and downward adjustments to our estimated reserves and has resulted in the curtailment of numerous planned operations as well as the implementation of severe cost cutting measures.  If prices do not recover sufficiently, or quickly enough, we may be unable to generate sufficient revenues to operate profitably and to meet our financial obligations.

Our actual recovery of reserves may differ from our proved reserve estimates.

This Form 10-K contains estimates of our proved oil and gas reserves. Estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us. Any inaccuracies in these interpretations or assumptions could also materially affect the estimated quantities of reserves shown in the reserve reports summarized in this Form 10-K. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, decommissioning liabilities and quantities of recoverable oil and gas reserves most likely will vary from estimates. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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We may be limited in our ability to maintain or book additional proved undeveloped reserves under the SEC’s rules.

We have included in this Form 10-K certain estimates of our proved reserves as of December 31, 2014 prepared in a manner consistent with our and our independent petroleum consultant’s interpretation of the SEC rules relating to modernizing reserve estimation and disclosure requirements for oil and natural gas companies. Included within these SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Further, if we postpone drilling of proved undeveloped reserves beyond this five-year development horizon, we may have to write off reserves previously recognized as proved undeveloped.  During 2014 and 2013, we reclassified 7,755 MBoe and 2,439 MBoe, respectively, of reserves previously classified as proved undeveloped reserves as a result of the failure to develop those reserves within five years of their being recorded as proved undeveloped.  We may incur similar reclassifications and charges in the future if we are unable to develop some or all of our proved undeveloped reserves within five years of booking.

As of December 31, 2014, approximately 63% of our total proved reserves were undeveloped and approximately 18% of our total proved reserves were developed non-producing. There can be no assurance that all of those reserves will ultimately be developed or produced.

While we have plans or are in the process of developing plans for exploiting and producing a majority of our proved reserves, there can be no assurance that we will have the resources to fully develop those reserves or that all of those reserves will ultimately be developed or produced. While we presently act as operator on substantially all of our properties, to the extent that we are not the operator with respect to our proved undeveloped reserves, we may not be in a position to control the timing of all development activities. Furthermore, there can be no assurance that all of our undeveloped and developed non-producing reserves will ultimately be produced during the time periods we have planned, at the costs we have budgeted, or at all, which could result in the write-off of previously recognized reserves.

Unless we replace crude oil and natural gas reserves, our future reserves and production will decline.

In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of crude oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. As a result of declining cash flow from operations during 2013 and 2014, we have limited ability to fund exploration and development activities in the absence of outside funding. At December 31, 2014, we lacked a revolving credit facility and had limited funds on hand to support our drilling and development budget.  In the absence of additional external financing, our ability to make planned capital investments to maintain and expand our reserves is limited and would be further impaired to the extent cash flow from operations is reduced due to natural declines in production, declines in commodity prices or otherwise.  Even if we have sufficient financing to support our optimum development plan, we may not be successful in exploring for, developing or acquiring additional reserves.

The nature and age of our wells may result in fluctuations in our production resulting from mechanical failures and other factors.

The majority of our wells have been in operation and have produced for many years. As a result of the age of those wells and their location in bay environments, those wells typically experience higher maintenance requirements than newer wells and wells located onshore. As a result, some of our wells may periodically be shut-in to perform maintenance or to restore optimal production levels or as a result of maintenance by third parties that operate facilities that serve our wells. Due to the periodic need to shut-in wells, we experience routine fluctuations in production levels with production declining below normal operating capacity during periods of maintenance. During 2014, deferred maintenance and needed facilities modernizations associated with aging facilities contributed to a marked decline in production early in the year and required substantial investments and devotion of resources to address the same over the course of the year. Further, because of their location in a bay environment, we sometimes experience delays in identifying and addressing production declines.

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Our offshore operations involve special risks that could affect our operations adversely.

Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. In particular, we are not intending to put in place business interruption insurance due to its high cost. We therefore may not be able to rely on insurance coverage in the event of such natural phenomena.

Our participation in, and realization of value from, shallow water ultra-deep shelf wells is subject to certain financing and operating risks that may prevent us from realizing the value of our deep reserve potential and expose us to delays, unexpected costs and other adverse financial consequences.

We have identified potential ultra-deep prospects underlying our transition zone acreage. The cost of exploration of such prospects, even when limited to our proportionate interest in such costs, is likely beyond that which we could fund from our current financial resources. Accordingly, we intend to seek partners to absorb a substantial portion of our share of such exploration costs. To that end, we have conducted discussions with various parties with respect to the potential formation of a joint venture to explore one or more ultra-deep prospects. We have not, as of December 31, 2014, entered into a definitive agreement with any prospective partner to fund or participate in the exploration of our ultra-deep prospects and, in light of the weak commodity price environment at December 31, 2014, we do not anticipate finalizing any such arrangements until a recovery in commodity prices has occurred. In the event that we enter into such a joint venture arrangement but are unable to make satisfactory arrangements to fund our portion of exploration costs, our interests in some of our ultra-deep prospects may be substantially reduced or lost with little or no benefit from such interests accruing to our benefit. Further, the shallow water ultra-deep wells are subject to very high pressures and temperatures. The drilling, logging and completion techniques associated with such wells may near the limits of existing technologies. As a result, new technologies and techniques are being developed to deal with these challenges. The use of advanced drilling technologies involves a higher risk of technological failure and potentially higher costs. In addition, there can be delays in completion due to necessary equipment that is specially ordered to handle the challenges of ultra-deep wells. Even if we are able to participate in drilling ultra-deep wells there is no assurance that such wells will be commercially viable. Such wells are presently expected to be natural gas wells and, based on the current low price of natural gas, there is no assurance that the wells can be operated in an economically feasible manner even if successfully completed.

Our participation in, and realization of value from, Gulf of Mexico shelf prospects is subject to participation of partners in the financing and development of those prospects and subjects us to risk associated with operating under rules of the U.S. Bureau of Ocean Energy Management (“BOEM”).

During 2013, we acquired four leases totaling 19,814 acres in the shallow Gulf of Mexico outer continental shelf (“OCS”).  The leases are located in the federal waters of the Gulf of Mexico and are subject to rules and regulations of the BOEM.  We have no history of developing and operating properties subject to BOEM regulation or in the deeper waters that characterize those leases and lack the financial resources to develop those prospects.  Accordingly, we intend to seek partners in the development of such prospects which may entail farm-outs, promoted deals or other similar arrangements with partners having greater experience and financial resources to carry out such development and operating activities.  If we are unable to secure partners to participate in such activities we may realize no value from the prospects and may lose our investment in those prospects.  Even if we are able to secure necessary partners to fund, develop and operate those prospects, there is no guaranty that such activities will result in commercially viable wells.

To cover the various obligations of lessees on the OCS, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, the BOEM generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. As a result of the recent bankruptcy of ATP Oil and Gas, the BOEM has indicated that it may review the estimated cost of future plugging, abandonment, decommissioning and removal obligations of other OCS operators and may increase the amount of financial assurance required with respect to these obligations. While we believe that we are currently exempt from the supplemental bonding requirements of the BOEM, the BOEM could increase bonding requirements associated with planned development of our OCS properties. The cost of these bonds or other surety could be substantial and there is no assurance that bonds or other surety could be obtained in all cases. In addition, we may be required to provide letters of credit to support the issuance of these bonds or other surety. The cost of compliance with these supplemental bonding requirements could materially and adversely affect our financial condition, cash flows and results of operations.

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Our insurance may not protect us against all of the operating risks to which our business is exposed.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Due to market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. Consistent with industry practice, we are not fully insured against all risks, including high-cost business interruption insurance and drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations. Due to a number of catastrophic events in recent years, including Hurricanes Ivan, Katrina, Rita, Gustav, Ike and Isaac and the April 2010 Deepwater Horizon incident, insurance underwriters increased insurance premiums for many of the coverages historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry suffered damage from Hurricanes Ivan, Katrina, Rita, Gustav, Ike and Isaac. As a result, insurance costs for many operators in the Gulf Coast region have increased significantly from the costs that similarly situated participants in this industry have historically incurred. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major wind storm in the event that damages are incurred. If storm activity in the future is as severe, insurance underwriters may no longer insure assets in the Gulf Coast region against weather-related damage. In addition, we do not intend to put in place business interruption insurance due to its high cost. This insurance may not be economically available in the future, which could adversely impact business prospects in the Gulf Coast region and adversely impact our operations. If an accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a vendor, it could adversely affect our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.

Competition for oil and gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that could give them an advantage in evaluating and obtaining properties and prospects.

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors are major or independent oil and gas companies that possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than ours. We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases may be acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. Further, our competitors may be able to expend greater resources on the existing and changing technologies that we believe will impact attaining success in the industry. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves.

This Form 10-K contains estimates of our future net cash flows from our proved reserves. We base the estimated discounted future net cash flows from our proved reserves on average prices for the preceding twelve-month period and costs in effect on the day of the estimate. However, actual future net cash flows from our natural gas and oil properties will be affected by factors such as:

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the volume, pricing and duration of our natural gas and oil hedging contracts;

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supply of and demand for natural gas and oil;

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actual prices we receive for natural gas and oil;

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our actual operating costs in producing natural gas and oil;

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•

the amount and timing of our capital expenditures and decommissioning costs;

•

the amount and timing of actual production; and

•

changes in governmental regulations and taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute exploration and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.

We utilize third-party services to maximize the efficiency of our organization. The cost of oil field services may increase or decrease depending on the demand for services by other oil and gas companies. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploitation and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.

Market conditions or transportation impediments may hinder access to oil and gas markets, delay production or increase our costs.

Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines or trucking and terminal facilities. In offshore operations, market access depends on the proximity of and our ability to tie into existing production platforms and, where those facilities are owned or operated by third parties, the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. Restrictions on our ability to sell our oil and natural gas may have several other adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possible loss of a lease due to lack of production. In the event that we encounter restrictions in our ability to tie our production to a gathering system, we may face considerable delays from the initial discovery of a reservoir to the actual production of the oil and gas and realization of revenues. In some cases, our wells may be tied back to platforms owned by parties with no economic interests in these wells. There can be no assurance that owners of such platforms will continue to operate the platforms. If the owners cease to operate the platforms or their processing equipment, we may be required to shut in the associated wells, which could adversely affect our results of operations.

We may not be the operator on all of our properties and therefore are not in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves on such properties.

As we carry out our planned drilling program, we may not serve as operator of all planned wells. We currently operate over 99% of our proved reserves, but do not expect to operate any wells that may be drilled on ultra-deep prospects or the Gulf of Mexico shelf prospects acquired during 2013. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

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the timing and amount of capital expenditures;

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the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

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the operator’s expertise and financial resources;

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approval of other participants in drilling wells;

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selection of technology; and

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the rate of production of the reserves.

Each of these factors, and others, could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our price risk management arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. Declines in the credit markets and the availability of credit or declines in equity values of our vendors, customers and counterparties, as well as declines in cash flow resulting from declines in commodity prices, may result in a significant reduction in our vendors, customers and counterparties liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could reduce our cash flows.

We sell the majority of our production to a small number of customers.

Two customers accounted for approximately 87% of our total oil and natural gas revenues during the year ended December 31, 2014. Our inability to continue to sell our production to those customers, if not offset by sales with new or other existing customers, could have a material adverse effect on our business and operations.

Unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.

We may become responsible for unanticipated costs associated with abandoning and reclaiming wells, facilities and pipelines. Abandonment and reclamation of facilities and the costs associated therewith is often referred to as “decommissioning.” Should decommissioning be required that is not presently anticipated or the decommissioning be accelerated, such as can happen after a hurricane, such costs may exceed the value of reserves remaining at any particular time. We may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could have a material adverse effect on our financial position and results of operations.  During 2012 and 2013, we incurred decommissioning costs in excess of our estimates and established reserve and we may incur costs in excess of our reserves in the future.

Lower oil and gas prices and other factors may result in impairments of our asset carrying values.

Under the successful efforts method of accounting, whenever circumstances indicate that an asset may be impaired, we are required to compare the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset.  If the future undiscounted cash flows are lower than the unamortized capitalized cost, an impairment charge is realized to reduce the capitalized cost to fair value.  In computing future undiscounted cash flows of assets, we take into account estimates of future crude oil and natural gas prices as well as operating costs, anticipated production from proved reserves and other relevant data.  Accordingly, a decline in oil and natural gas prices could cause a future write-down of capitalized costs and a non-cash impairment charge against future earnings.

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Our success depends on dedicated and skillful management and staff, whose departure could disrupt our business operations.

Our success depends on our ability to retain and attract experienced engineers, geoscientists and other professional staff. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.

Risks Related to Our Risk Management Activities

If we place hedges on future production and encounter difficulties meeting that production, we may not realize the originally anticipated cash flows.

Our assets consist of a mix of reserves, with some being developed while others are undeveloped. To the extent that we sell the production of these reserves on a forward-looking basis but do not realize that anticipated level of production, our cash flow may be adversely affected if energy prices rise above the prices for the forward-looking sales. In this case, we would be required to make payments to the purchaser of the forward-looking sale equal to the difference between the current commodity price and that in the sales contract multiplied by the physical volume of the shortfall. There is the risk that production estimates could be inaccurate or that storms or other unanticipated problems could cause the production to be less than the amount anticipated, causing us to make payments to the purchasers pursuant to the terms of the hedging contracts.

Our price risk management activities could result in financial losses or could reduce our income, which may adversely affect our cash flows.

We enter into derivative contracts to reduce the impact of natural gas and oil price volatility on our cash flow from operations. Currently, we use a combination of natural gas and crude oil swap and physical arrangements to mitigate the volatility of future natural gas and oil prices received on our production.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial decrease in our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our price risk management activities are subject to the following risks:

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a counterparty may not perform its obligations under the applicable derivative instrument;

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production is less than expected;

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there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

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the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.

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If we are unable to effectively manage the commodity price risk of our production if energy prices fall, we may not realize the anticipated cash flows from our assets.

During the third quarter of 2012, we instituted a hedging program in an effort to manage our commodity price risk. If we fail to effectively manage the commodity price risk of our production and energy prices fall, we may not be able to realize the cash flows from our assets that are currently anticipated even if we are successful in increasing the production and ultimate recovery of reserves. Compared to some other participants in the oil and gas industry, we are a relatively small company with modest resources. Moreover, our lack of a revolving credit facility may limit the scope and nature of commodity price risk management tools available to us. There is the possibility that we may be unable to find counterparties willing to enter into derivative arrangements with us or be required to either purchase relatively expensive put options, or commit to deliver future production, to manage the commodity price risk of our future production. To the extent that we commit to deliver future production, we may be forced to make cash deposits available to counterparties as they mark to market these financial hedges. Proposed changes in regulations affecting derivatives may further limit or raise the cost, or increase the credit support required to hedge. This funding requirement may limit the level of commodity price risk management that we are prudently able to complete. In addition, we are unlikely to hedge undeveloped reserves to the same extent that we hedge the anticipated production from proved developed reserves.

Risks Related to Our Acquisition Strategy

Our acquisitions may be stretching our existing resources.

We acquired our principal properties in 2008 and may make acquisitions in the future. Future transactions may prove to stretch our internal resources and infrastructure. As a result, we may need to invest in additional resources, which will increase our costs. Any further acquisitions we make over the short term would likely intensify these risks.

We may be unable to successfully integrate the operations of the properties we acquire.

Integration of the operations of the properties we acquire with our existing business is a complex, time-consuming and costly process. Failure to successfully integrate the acquired businesses and operations in a timely manner may have a material adverse effect on our business, financial condition, results of operations and cash flows. The difficulties of combining the acquired operations include, among other things:

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operating a larger organization;

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coordinating geographically disparate organizations, systems and facilities;

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integrating corporate, technological and administrative functions;

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diverting management’s attention from other business concerns;

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diverting financial resources away from existing operations;

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an increase in our indebtedness; and

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potential environmental or regulatory liabilities and title problems.

The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer.

In addition, we face the risk of identifying, competing for and pursuing other acquisitions, which takes time and expense and diverts management’s attention from other activities.

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We may not realize all of the anticipated benefits from our acquisitions.

We may not realize all of the anticipated benefits from our future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or other difficulties, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices.

The properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the acquired properties or obtain protection from sellers against such liabilities.

Our business strategy includes acquisitions, which may include acquisitions of exploration and production companies, producing properties and undeveloped leasehold interests. The successful acquisition of oil and natural gas properties requires assessments of many factors that are inherently inexact and may be inaccurate, including the following:

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acceptable prices for available properties;

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amounts of recoverable reserves;

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estimates of future oil and natural gas prices;

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estimates of future exploratory, development and operating costs;

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estimates of the costs and timing of plugging and abandonment; and

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estimates of potential environmental and other liabilities.

Our assessment of acquired properties will not reveal all existing or potential problems nor will it permit us to become familiar enough with the properties to fully assess their capabilities and deficiencies. In the course of our due diligence, we may not physically inspect every well, platform or pipeline. Even if we physically inspect each of these, our inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination. We may not be able to obtain contractual indemnities from the seller for liabilities associated with such risks. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. If an acquired property does not perform as originally estimated, we may have an impairment, which could have a material adverse effect on or financial position and results of operations.

Risks Related to Our Indebtedness and Access to Capital and Financing

Our level of indebtedness may limit our ability to borrow additional funds or capitalize on acquisition or other business opportunities.

As of December 31, 2014, we had total indebtedness of $179.8 million. Our leverage and the current and future restrictions contained in the agreements governing our indebtedness may reduce our ability to incur additional indebtedness, engage in certain transactions or capitalize on acquisition or other business opportunities. Our indebtedness and other financial obligations and restrictions could have financial consequences. For example, they could:

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impair our ability to obtain additional financing in the future for capital expenditures, potential acquisitions, general business activities or other purposes;

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increase our vulnerability to general adverse economic and industry conditions;

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result in higher interest expense in the event of increases in interest rates to the extent that our debt is at a variable rates of interest;

•

have a material adverse effect if we fail to comply with financial and restrictive covenants in any of our debt agreements, including an event of default if such event is not cured or waived;

•

require us to dedicate a substantial portion of future cash flow to payments of our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate requirements;

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limit our flexibility in planning for, or reacting to, changes in our business and industry; and

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place us at a competitive disadvantage to those who have proportionately less debt.

If we are unable to meet future debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness and other financial transactions, seek additional equity or sell assets. We may then be unable to obtain such financing or capital or sell assets on satisfactory terms, if at all.

To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures and development and exploration efforts will depend on our ability to generate cash in the future. Our future operating performance and financial results will be subject, in part, to factors beyond our control, including interest rates and general economic, financial and business conditions. We cannot assure that our business will generate sufficient cash flow from operations or that future borrowings or other facilities will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs.

If we are unable to generate sufficient cash flow to service our debt, we may be required to:

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refinance all or a portion of our debt;

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obtain additional financing;

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sell some of our assets or operations;

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reduce or delay capital expenditures, research and development efforts and acquisitions; or

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revise or delay our strategic plans.

If we are required to take any of these actions, it could have a material adverse effect on our business, financial condition and results of operations. In addition, we cannot assure that we would be able to take any of these actions, that these actions would enable us to continue to satisfy our capital requirements or that these actions would be permitted under the terms of the our various debt instruments.

The covenants in the indenture governing our senior notes impose restrictions that may limit our ability and the ability of our subsidiaries to take certain actions. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.

The indentures governing our senior notes contain various covenants that limit our ability and the ability of our subsidiaries to, among other things:

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incur dividend or other payment obligations;

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incur indebtedness and issue preferred stock; or

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sell or otherwise dispose of assets, including capital stock of subsidiaries.

If we breach any of these covenants, a default could occur. A default, if not waived, would entitle certain of our debt holders to declare all amounts borrowed under the breached indenture to become immediately due and payable, which could also cause the acceleration of obligations under certain other agreements and the termination of our credit facility. In the event of acceleration of our outstanding indebtedness, we cannot assure that we would be able to repay our debt or obtain new financing to refinance our debt. Even if new financing was made available to us, it may not be on terms acceptable to us.

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In early 2015, we entered into short term forbearance agreements with the principal holders of our outstanding indebtedness.  Pursuant to the forbearance agreements, we paid interest accrued and owing as of December 31, 2014 on our most senior debt but did not pay interest accrued and owing as of January 1, 2015 on other debt.  Additionally, we agreed to provide information to our debt holders, to retain financial advisors acceptable to our debt holders and undertook additional obligations with a view to recapitalizing or restructuring our company.  The forbearance agreements were entered into in light of the steep drop in commodity prices that resulted in reduced revenues and operating cash flows.  If we are unable to substantially improve operating cash flows, secure additional funding or reach a longer term accommodation from our debt holders, we may be required to sell assets or take other measures to address upcoming payment obligations, which measures may include seeking protection in bankruptcy.

We expect to have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms.

We expect to make substantial capital expenditures for the acquisition, development, production, exploration and abandonment of oil and gas properties. Our capital requirements depend on numerous factors and we cannot predict accurately the timing and amount of our capital requirements. We have historically financed our capital expenditures through cash flow from operations and cash on hand, including cash received through multiple equity and debt offerings undertaken during 2011, 2012 and 2013. However, if our capital requirements vary materially from those provided for in our current projections, we may require additional financing to support future capital expenditures.  At December 31, 2014, we lacked a revolving credit facility, had inadequate resources on hand to fully fund our planned development operations and had no existing commitments to provide financing to support future capital requirements. A decrease in expected revenues or an adverse change in market conditions could make obtaining this financing economically unattractive or impossible.

The cost of raising money in the debt and equity capital markets may increase substantially while the availability of funds from those markets may diminish significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets may increase as lenders and institutional investors could increase interest rates, impose tighter lending standards, refuse to refinance existing debt at maturity at all or on terms similar to our current debt and, in some cases, cease to provide funding to borrowers.

An increase in our indebtedness, as well as the credit market and debt and equity capital market conditions discussed above could negatively impact our ability to secure, and remain in compliance with the financial covenants under, any revolving credit facility which could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth as expected, we could be required to seek alternative financing, the terms of which may be less favorable to us, or not pursue growth opportunities.

Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and this will adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition and results of operations. We may also be unable to obtain sufficient credit capacity with counterparties to finance the hedging of our future crude oil and natural gas production which may limit our ability to manage price risk. As a result, we may lack the capital necessary to complete potential acquisitions, obtain credit necessary to enter into derivative contracts to hedge our future crude oil and natural gas production or to capitalize on other business opportunities.

Any future financial crisis may impact our business and financial condition. We may not be able to obtain funding in the capital markets on terms we find acceptable because of the decline in commodity prices.

The recent turmoil in energy markets reflected in a steep drop in oil prices has had an impact on our business and our financial condition, and we may face challenges if market conditions do not improve or deteriorate in the future. Historically, we have used our cash flow from operations and funds provided by debt and equity offerings to fund our capital expenditures. The drop in commodity prices has decreased cash flow from operations to fund capital expenditures and debt service.

The drop in energy prices has also made it more difficult to obtain funding in the public and private capital markets. In particular, the cost of raising money in the debt and equity capital markets increased substantially while the availability of funds from those markets generally diminished significantly.

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Risks Related to Environmental and Other Regulations

Our operations are subject to environmental and other government laws and regulations that are costly and could potentially subject us to substantial liabilities.

Our oil and gas exploration, production, and related operations are subject to extensive rules and regulations promulgated by federal, state, and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.

All of the jurisdictions in which we operate generally require permits for drilling operations, drilling bonds, and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such jurisdictions also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain jurisdictions also limit the rate at which oil and gas can be produced from our properties.

Our sales of oil and natural gas liquids are not presently regulated and are made at market prices. The price we receive from the sale of those products is affected by the cost of transporting the products to market. FERC regulations establish an indexing system for transportation rates for oil pipelines, which, generally, index such rate to inflation, subject to certain conditions and limitations. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.

FERC has civil penalty authority to impose penalties for current violations. While our operations have not been regulated by FERC, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional entities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

Our oil and gas operations are subject to stringent laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:

•

require the acquisition of a permit before drilling commences;

•

restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

•

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

•

impose substantial liabilities for pollution resulting from operations.

Failure to comply with these laws and regulations may result in:

•

the imposition of administrative, civil and/or criminal penalties;

•

incurring investigatory or remedial obligations; and

•

the imposition of injunctive relief, which could limit or restrict our operations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Although we intend to be in compliance in all material respects with all applicable environmental laws and regulations, we cannot assure shareholders that we will be able to comply with existing or new regulations. In addition, the risk of accidental spills, leakages or other circumstances could expose us to extensive liability.

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Under certain environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination, or if current or prior operations were conducted consistent with accepted standards of practice. Such liabilities can be significant, and if imposed could have a material adverse effect on our financial condition or results of operations.

We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.

Our sales of oil and natural gas, and any hedging activities related to such energy commodities, expose us to potential regulatory risks.

FERC holds statutory authority to monitor certain segments of the physical and futures energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil and natural gas, and any hedging activities related to these energy commodities, we are required to observe the market-related regulations enforced by these agencies, which hold enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect our financial condition or results of operations.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act (“CAA”). Among the EPA’s rules regulating greenhouse gas emissions under the CAA, one requires a reduction in emissions of greenhouse gases from motor vehicles and another regulates emissions of greenhouse gases from certain large stationary sources. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries and certain onshore oil and natural gas production facilities.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and a number of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

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The adoption of financial reform legislation by Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), signed into law in 2010, requires the Commodities Futures Trading Commission (“CFTC”), the SEC and other regulators to promulgate rules and regulations relating to, among other things, the over-the-counter derivatives market. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. The financial reform legislation may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require certain counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The final rules will be phased in over time according to a specified schedule which is dependent on the finalization of certain other rules to be promulgated jointly by the CFTC and the SEC. The Dodd-Frank Act and any new regulations could increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas liquids and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas liquids and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

If we are unable to acquire or renew permits and approvals required for operations, we may be forced to suspend or cease operations altogether.

The construction and operation of energy projects require numerous permits and approvals from governmental agencies. We may not be able to obtain all necessary permits and approvals, and as a result our operations may be adversely affected. In addition, obtaining all necessary permits and approvals may necessitate cash expenditures and may create a risk of expensive delays or loss of value if a project is unable to proceed as planned due to changing requirements or local opposition.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

President Obama and members of Congress have, on multiple occasions, advocated and proposed legislation that, if enacted, would eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. Several bills have been introduced in Congress that would implement these proposals. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

Our By-laws contain provisions that discourage corporate takeovers and could prevent shareholders from realizing a premium on their investment.

Our by-laws contain provisions that could delay or prevent changes in our management or a change of control that a shareholder might consider favorable. For example, they may prevent a shareholder from receiving the benefit from any premium over the market price of our common shares offered by a bidder in a potential takeover. Even in the absence of a takeover attempt, these provisions may adversely affect the prevailing market price of our common shares if they are viewed as discouraging takeover attempts in the future. For example, provisions in our by-laws that could delay or prevent a change in management or change in control include:

•

the board is permitted to issue preferred shares and to fix the price, rights, preferences, privileges and restrictions of the preferred shares without any further vote or action by our shareholders;

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•

shareholders have limited ability to remove directors; and

•

in order to nominate directors, shareholders must provide advance notice and furnish certain information with respect to the nominee and any other information as may be reasonably required by the Company.

These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common shares.

Item 1B.

Unresolved Staff Comments

Not applicable

Item 2.

Properties

A description of our properties is included in “Item 1. Business.”

Item 3.

Legal Proceedings

Saratoga Resources. v. Professional Oil and Gas Marketing and Henry Calongne

In February 2010, Saratoga filed a complaint in the United States Bankruptcy Court for the Western District of Louisiana against Barry Ray Salsbury, Brian Carl Albrecht, Shell Sibley, Willie Willard Powell and Carolyn Monica Greer, each being former owners of The Harvest Group LLC and/or Harvest Oil & Gas, LLC. The complaint alleged breach of the Purchase and Sale Agreements with the former owners arising from the underpayment or nonpayment of royalties to the State of Louisiana for periods prior to Saratoga’s acquisition of the Harvest Companies and related claims for damages. Specifically, the complaint alleged that the underpayment or nonpayment of such royalties constituted a breach, by the former owners, of the representations and warranties that all royalty payments of the Harvest Companies had been paid in full as of the closing of Saratoga’s purchase of the Harvest Companies. Saratoga subsequently amended its complaint to add to the breach of contract claims additional claims based on fraud arising from the willful and knowing concealment of the underpayment of royalties. In its amended complaint, Saratoga named Henry Calongne and Professional Oil & Gas Marketing as additional defendants based on substantially identical facts as alleged in the complaint against the former owners of the Harvest Companies. Mr. Calongne and Professional Oil & Gas Marketing served as the agent of the Harvest Companies in computing the applicable royalty payments. Saratoga asserted that Mr. Calongne and Professional Oil & Gas Marketing either negligently or knowingly colluded with the former owners with respect to the underpayment of royalties to the State of Louisiana. Saratoga was seeking monetary damages with the total principal claims against all defendants being $1.4 million. Professional Oil & Gas Marketing asserted counterclaims against Saratoga for $0.2 million for unpaid fees and reimbursable tax payments. During 2012, Saratoga concluded settlements with Barry Ray Salsbury, Shell Sibley, Willie Willard Powell and Carolyn Monica Greer and received approximately $769,000 and the claims and counterclaims involving those defendants were dismissed. In 2012, the case with respect to the remaining defendants was removed to the U.S. District for the Southern District of Louisiana and the matters relating to Brian Carl Albrecht were converted to an arbitration proceeding (see below). During 2013, Henry Calongne and Professional Oil and Gas Marketing were granted partial summary judgment and awarded $126,280 of marketing fees with said amount being placed in escrow pending final resolution of Saratoga’s claims against each. The claim against Mr. Calongne and Professional Oil and Gas Marketing went to trial in March 2014 and in February 2015 all remaining claims by and between Saratoga against Mr. Calongne and Professional Oil and Gas Marketing were dismissed and the amounts deposited in escrow to pay marketing fees were released to Professional Oil and Gas Marketing.

The Harvest Group, LLC, et al. v. Brian Carl Albrecht; Harvest Operating LLC v. The Harvest Group, LLC, et al.

As noted above, in February 2010, Saratoga filed a complaint in the United States Bankruptcy Court for the Western District of Louisiana against Barry Ray Salsbury, Brian Carl Albrecht, Shell Sibley, Willie Willard Powell and Carolyn Monica Greer, each being former owners of The Harvest Group LLC and/or Harvest Oil & Gas, LLC. The complaint alleged breach of the Purchase and Sale Agreements with the former owners arising from the underpayment or nonpayment of royalties to the State of Louisiana for periods prior to Saratoga’s acquisition of the Harvest Companies and related claims for damages. The claims against all parties other than Brian Carl Albrecht were subsequently settled and the claim against Mr. Albrecht was converted to an arbitration proceeding.

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Harvest Operating, LLC, a company controlled by Mr. Albrecht, brought a separate cause of action against The Harvest Group, LLC, Harvest Oil & Gas, LLC and Saratoga Resources, Inc. (the “Saratoga Parties”), which cause of action was consolidated with the arbitration proceedings noted above.  Harvest Operating’s cause of action asserted a claim for damages based on the alleged wrongful termination of rights to use a pipeline owned and operated by the Saratoga Parties and the loss in value of a property operated by Harvest Operating based on its inability to transport production from that property via the pipeline in question.

The consolidated arbitration proceeding was conducted before a single arbitrator and, in August 2014, the arbitrator issued an Award and Reasons ruling (1) in favor of Saratoga, as relates to the royalty claim, and awarding to Saratoga $355,879, and (2) in favor of Harvest Operating, as relates to the pipeline use claim, and awarding to Harvest Operating $3,757,050.

Saratoga believes that the award based on the pipeline use claim is wholly unsupported by the facts or the law.  In November 2014, Saratoga filed a motion with the arbitrator to reconsider and clarify the arbitration award.  Separately, in November 2014, Saratoga filed a Motion for Clarification and Remittitur in the 19^th District Court of East Baton Rouge Parish, Louisiana. Both the motion with the arbitrator and the Motion in the District Court seek to vacate the arbitrator’s award relating to the pipeline claim on multiple grounds.  In December 2014, the arbitrator agreed to hear arguments as to the authority and grounds for reconsidering the arbitration award and the arbitrator’s decision in that matter is pending.

Also, in November 2014, Saratoga filed a separate cause of action against Brian Albrecht in the 24^th District Court of Jefferson Parish, Louisiana.  The cause of action alleges breach of contract on the part of Mr. Albrecht and seeks damages in an amount equal to those awarded in the above arbitration proceeding.  Saratoga asserts that the Purchase and Sale Agreement under which Saratoga secured beneficial ownership of the pipeline that is subject of the arbitration proceeding and the claims of Harvest Operating was illusory in that, if the reasoning of the arbitration award were to stand, Saratoga would not have received the rights associated with beneficial ownership and control of the pipeline and that, by withholding from Saratoga the ordinary rights associated with ownership of the pipeline, Mr. Albrecht was in breach of the terms of the Purchase and Sale Agreement.

Each of the above described proceedings remains pending and the parties to each of the proceedings have submitted various motions regarding the same.

We may from time to time be a party to lawsuits incidental to our business. Except as noted above, as of December 31, 2014, we were not aware of any current, pending, or threatened litigation or proceedings that could have a material adverse effect on our results of operations, cash flows or financial condition.

Item 4.

Mine Safety Disclosures

Not applicable.

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PART II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is traded on the NYSE MKT (“NYSE”) under the symbol “SARA”.  The following table sets forth the range of high and low sale prices of our common stock for each quarter during the past two fiscal years.

At April 10, 2015, the closing price of our common stock on the NYSE MKT was $0.22.

As of April 10, 2015, there were approximately 1,479 record holders of our common stock.

We have not declared or paid any dividends on our common stock since our inception, and we do not anticipate declaring or paying any dividends on our common stock for the foreseeable future. We currently intend to retain any future earnings to finance future growth. Any future determination to pay dividends will be at the discretion of our board of directors and will depend on our financial condition, results of operations, capital requirements and other factors the board of directors considers relevant. In addition, our ability to declare and pay dividends is restricted by our governing statute, as well as the terms of our existing credit facilities.

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information as of December 31, 2014 with respect to the shares of our common stock that may be issued under our existing equity compensation plans.

______________________

(1)

Consists of 3,000,000 shares reserved for issuance under the Saratoga Resources, Inc. 2011 Omnibus Incentive Plan (the “2011 Plan”).

(2)

Consists of non-plan stand-alone stock option grants to directors, employees and consultants. The options are exercisable on terms generally described in “Note 11. Common Stock – Stock-Based Compensation” to our financial statements included herein.

Item 6.

Selected Financial Data

Not applicable.

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Item 7.

Management’s Discussion and Analysis of Financial Conditions and Results of Operations

Overview

We are an independent oil and natural gas company engaged in the production, development, acquisition and exploitation of crude oil and natural gas properties. As of December 31, 2014, our properties consisted of approximately 51,500 acres under lease, comprised of our principal producing properties covering approximately 31,700 acres gross/net in the transitional coastline and protected in-bay environments on parish and state leases in south Louisiana and approximately 19,800 acres gross/net under federal leases in the shallow Gulf of Mexico shelf.

Our state and parish leases span 11 fields which are characterized by over 30 years of development drilling and production history, including Grand Bay field which has over 70 years of production history and over 258 MMBoe produced to date, yet remains virtually unexplored at depths greater than 15,000 feet. Substantially all of our state and parish leases are held by production (“HBP”) without near-term lease expirations. Most of those properties offer multiple stacked reservoir objectives with substantial behind pipe potential.

Our shallow Gulf of Mexico shelf properties were acquired during 2013. At December 31, 2014, our shallow Gulf of Mexico shelf properties did not include any producing wells and we were engaged in efforts to seek partners to participate in development of such properties.  We continually seek to enhance our acreage position through leasing and evaluation of opportunistic acquisitions primarily within, but not limited to, the transition zone and in the shallow Gulf of Mexico.

As of December 31, 2014, our total proved reserves were10.2 MMBoe, consisting of 5.8 MMBbls of oil and 26.8 Bcf of natural gas, approximately 73% of which was attributable to state and parish properties. The PV-10 of our proved reserves at December 31, 2014 was $209.3 million, based on SEC pricing. The PV-10 of our proved reserves, based on NYMEX strip pricing, was $69.4 million. Additionally, we had probable reserves of 25.6 MMBoe, consisting of 10.3 MMBbls of oil and 92.0 Bcf of natural gas. Moreover, our reserve base includes significant undeveloped and exploratory drilling opportunities.  We operate over 99% of the wells that comprise our PV-10, enabling us to effectively exercise management control of our operating costs, capital expenditures and the timing and method of development of our properties.

During 2014, we produced 670.1 MBoe, of which approximately 76% was oil and all of which was attributable to our state and parish properties. As of December 31, 2014, our development opportunities included 61 proved behind pipe and shut-in opportunities in 44 wells in 6 fields, 36 proved undeveloped opportunities within 15 proposed wells in 5 fields.  An additional 61 formerly proved undeveloped opportunities within 21 proposed wells in 3 fields were reclassified as probable P90 reserves as required by the SEC five–year PUD rule.  Additionally, at December 31, 2014, we had 37 probable behind pipe and shut-in development opportunities. Additionally, at December 31, 2014, we had 41 probable undeveloped opportunities within 24 wells in 4 fields, 13 possible behind pipe and shut-in development opportunities and 86 possible undeveloped opportunities within 33 proposed wells in 5 fields.  During the year ended December 31, 2014, we successfully completed one development well, 6 recompletions and 9 workovers.

Recent Developments

The following significant events, among others, affected our operations and financial position during 2013 and 2014:

Commodity Price Declines

During the second half of 2014, accelerating in the fourth quarter and continuing into 2015, we have experienced a sharp decline in commodity prices, particularly crude oil pricing.  Global supply and demand conditions, driven by increasing domestic shale production as well as certain foreign sources coming back on-line together with expected softening of demand associated with projected weakness in foreign economies, has resulted in a decline in the price we realized from crude oil sales from an average of $98.35 per barrel in January 2014 to $58.26 per barrel in December 2014.

Drilling, Development and Infrastructure Activities

During 2014 and 2013, we invested $12.9 million and $31.4 million, respectively, in our drilling and development program and infrastructure projects, summarized as follows:

Development Drilling.  During 2014 and 2013, we drilled one and four development wells, respectively.

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The “Rocky” well, in Breton Sound 32 Field, was spud and completed in July 2013. The well targeted an elongated ridge, offsetting the SL 1227 #21 and #22 wells in the 5,800’ sand, which is the main producing reservoir in the Breton Sound 32 field. A seventy-degree pilot hole was drilled followed by a sidetrack with a 750’ lateral completion. This well was our first horizontal well.

The “Zeke” well, in Breton Sound 32 Field, was spud and completed in August 2013.  The well also targeted the same 5,800’ sand as the Rocky well but in a separate structure to the south-east and was completed as a high angle (82 degrees) directional. The Zeke well also established a previously unbooked, uphole recompletion opportunity in the overlying 5,750’ sand, which also produces within the field.

The MP47 SL 195QQ-25 “Roux Toux” well in Main Pass 47 Field, was spud and completed in February 2013.  The well reached total depth of 8,453 feet MD/8,000 feet TVD and was successfully completed as a dual completion in the 13 and 17 sands.

The SL 195QQ-209 “Buddy” well, in Grand Bay Field, was spud in December 2012 and completed in January 2013.  The well reached total depth of 6,820 feet MD/TVD and was successfully completed in the 3A sand.

The “Rocky 3” well, in Breton Sound 32 Field, was spud and completed in May 2014.  The well also targeted the 5,800’ sand with a 750’ lateral completion.

Recompletion and Workover Program.  During 2014, we carried out 9 recompletions and 14 workovers.  6 of the recompletions and 9 of the workovers were successful.  One workover was still in progress at year end.

During 2013, we carried out 22 recompletions and 10 workovers.  17 of the recompletions and 9 of the workovers were successful.

Infrastructure Program.  During 2014 and 2013, we invested $2.9 million and $5.6 million, respectively, in infrastructure improvements and additions to support existing production and anticipated increases in production.  2014 infrastructure investments were focused on construction of a new flow line to serve Breton Sound 32 and modifications to facilities in Main Pass 46, Main Pass 52, Grand Bay, Breton Sound 32 and Breton Sound 51.

Production Optimization Initiatives

During 2014, we undertook an exhaustive review of field operations in order to address ongoing run time issues that adversely impacted production rates across our fields and resulted in a marked decline in production during the first two months of 2014.  Substantial time was spent in the field evaluating personnel, facilities, gas lift availability 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, facilities upgrades and projects continuing through year end.  We continue to monitor the results of such changes and upgrades and potential future changes and upgrades to optimize production.

Prior to implementing the changes and upgrades in early March, run times had fallen to an estimated 54% on average during January and February 2014 from 75% during fiscal 2013.  Following the changes and upgrades, run times for the balance of the year generally exceeded 75% and average daily production rose to 2,038 barrels of oil equivalent per day (BOEPD) over the last nine months of 2014 from 1,330 BOEPD in the quarter ended March 31, 2014 which was down from 1,800 BOEPD during the fourth quarter of 2013.

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Operating Costs

While the production initiatives undertaken during the first half of 2014 resulted in marked growth in production during the balance of 2014, our lease operating expenses for the first nine months rose on a year-over-year basis due, largely, to increased contract labor costs and facilities maintenance and repair costs incurred as part of the production optimization initiative.  Beginning in the fourth quarter of 2014 and continuing into 2015, our focus has shifted to decreasing lease operating expenses as well as general and administrative expense. Cost reduction measures have focused on bringing contract employees in-house, eliminating redundant positions, managing marine transportation, optimizing our chemical program, lowering communications costs and replacing/modifying our compressors. With continued weakness in commodity prices, additional cost cutting measures have been implemented in early 2015, including a determination to downsize our Houston office, curtail expenditures on certain longer term projects and tighten discretionary spending.  Those cost cutting measures are targeted to reduced lease operating expenses and general and administrative expenses by $13.3 million (a 39% decrease), in the aggregate, during 2015 as compared to 2014.

Drilling and Development Plans.

We have an extensive inventory of drilling opportunities, including numerous proved behind pipe and proved undeveloped opportunities as well as a number of exploratory opportunities.  In light of the sharp drop in commodity prices in late 2014 and early 2015, our near term development plans are focused on recompletions, workovers and conversion of PDNP opportunities supported by cash on hand and cash flow.

Development operations with respect to our proved undeveloped properties are expected to be curtailed for the foreseeable future given the low commodity price environment and our limited financial resources at December 31, 2014.  If and when market conditions support such, and subject to our ability to support such efforts through internal resources or outside financing, we intend to resume our efforts to develop our inventory of proved undeveloped prospects.  Initial results from the Breton Sound 32 Block reservoir simulation project are encouraging and we expect to be able to book additional reserves once the results of that study are analyzed.

Our previous efforts to secure partners to support exploration and development of our deep prospects in Grand Bay and in the shallow Gulf of Mexico shelf have been temporarily halted in light of the decline in commodity prices.  If and when market conditions support such, we intend to resume our efforts to identify and secure partners for the development of these prospects.

We continually evaluate our holdings with a view to optimizing our drilling and development plans based on ongoing development efforts, new geological and operating data, identification or acquisition of new opportunities and other factors. Accordingly, our drilling and development plans are fluid and subject to continuous revision and may vary from the plans described herein.

Leasehold and Seismic Activity

Gulf of Mexico Shelf Acreage.  In 2013, we bid on and were awarded four leases, with seismic maps included, totaling 19,814 acres in the Central Gulf of Mexico Lease Sale 227.  The acreage is in the shallow Gulf of Mexico shelf in water depths of 13 to 77 feet.  Two of the leases are in the Vermilion area and two of the leases are in the Ship Shoal area.  Lease bonuses on the prospects totaled $880,000 and first year annual rentals total $138,698.  Additionally, we paid a prospect fee of $450,000 to a third party consultant.

Louisiana State Leases.  In September 2013, we acquired an additional 857.96 acres under two Louisiana state leases in Breton Sound 18, 19 and 32 fields.  The leasehold acreage is contiguous with our existing lease holdings in Breton Sound 18 and 32 fields, is close to existing facilities and pipeline infrastructure and in water depths of less than 20 feet.  The leases have a primary term of three years and are subject to a 21% royalty burden.  Lease bonuses on the acreage totaled $225,620.  Annual rentals on the leases total $94,755 during the primary term.

During the third quarter of 2013, our operating agreement covering 253 acres and a single well in Little Bay Field terminated when we determined to temporarily abandon operations, resulting in an impairment charge of $2.2 million.  In November 2013, we acquired a new three year lease covering 212 acres in Little Bay Field, including the acreage and associated well and reserves lost during the third quarter of 2013.  Lease bonuses on the acreage totaled $86,026.  Annual rentals on the lease total $37,171 and the lease bears a 25% royalty.

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Impairments and Reserve Reclassifications

During 2014, we reported an impairment charge in the amount of $107.8 million.  The impairment charge reflects the reclassification of certain reserves out of the proved undeveloped category and into the probable category due to application of the SEC’s “five year rule” – accounting for approximately $95.3 million, or 88.4% of the impairment charge – and the steep decline in commodity prices which resulted in the expected undiscounted future cash flows at a producing field level to be less than the unamortized capitalized cost of assets in our several of our fields.

As a result of the application of the SEC’s so-called “five year rule,” we reclassified 7,755 MBoe of reserves out of the proved undeveloped category and into the probable category.  The five year rule requires removal of reserves from presentation as proved reserves if not developed within five years of initially being booked in the proved undeveloped category.

Legal Proceedings

In August 2014, the arbitrator in our long-standing legal proceedings against Brian Albrecht, and the counterclaims against us asserted by Mr. Albrecht and Harvest Operating, issued an Award and Reasons ruling (1) in our favor, as relates to our royalty claim, and awarding to us $355,879, and (2) in favor of Harvest Operating, as relates to the pipeline use claim of Harvest Operating, and awarding to Harvest Operating $3,757,050. As a result of such award, we recorded an arbitration award expense and an accrued liability of $3.4 million.

We believe that the award based on the pipeline use claim is wholly unsupported by the facts or the law.  In November 2014, we filed a motion with the arbitrator to reconsider and clarify the arbitration award.  Separately, in November 2014, we filed a Motion for Clarification and Remittitur in the 19^th District Court of East Baton Rouge Parish, Louisiana. Both the motion with the arbitrator and the Motion in the District Court seek to vacate the arbitrator’s award relating to the pipeline claim on multiple grounds.  In December 2014, the arbitrator agreed to hear arguments as to the authority and grounds for reconsidering the arbitration award and the arbitrator’s decision in that matter is pending.

Also, in November 2014, we filed a separate cause of action against Brian Albrecht in the 24^th District Court of Jefferson Parish, Louisiana.  The cause of action alleges breach of contract on the part of Mr. Albrecht and seeks damages in an amount equal to those awarded in the above arbitration proceeding.  We have asserted that the Purchase and Sale Agreement under which we secured beneficial ownership of the pipeline that is subject of the arbitration proceeding and the claims of Harvest Operating was illusory in that, if the reasoning of the arbitration award were to stand, we would not have received the rights associated with beneficial ownership and control of the pipeline and that, by withholding the ordinary rights associated with ownership of the pipeline, Mr. Albrecht was in breach of the terms of the Purchase and Sale Agreement.

Sale of 10% Senior Secured Notes

On November 22, 2013, we, and our several wholly-owned subsidiaries (the “Guarantors”), completed the issuance and sale to two institutional accredited investors (the “First Lien Lenders”) of $54.6 million in aggregate principal amount of its 10.0% Senior Secured Notes due 2015 (the “First Lien Notes”).

The First Lien Notes were issued pursuant to Purchase Agreements (the “Purchase Agreement”), and under an Indenture (the “First Lien Indenture”), by and among the Company, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (the “First Lien Trustee”). The First Lien Notes are our senior secured obligations and are fully and unconditionally guaranteed (the “Guarantees”) on a senior secured basis by the Guarantors and will rank equally in right of payment with our, and the Guarantors’, existing and future senior indebtedness and senior in right of payment to Second Lien Notes (as defined below).

The purchase price for the First Lien Notes and Guarantees was 100% of their principal amount. We received net proceeds from the issuance and sale of the First Lien Notes of approximately $25.4 million, after commissions and estimated offering expenses, and the surrender for retirement by the First Lien Lenders of $27.3 million in face amount of 12½% Senior Secured Notes (the “Second Lien Notes”).

The First Lien Notes mature on December 31, 2015, and interest, accruing at 10% per annum, is payable on the First Lien Notes on March 31, June 30, September 30 and December 31 of each year, commencing December 31, 2013.

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We have the option to redeem all or a portion of the First Lien Notes at any time at 100% of the principal amount to be redeemed plus accrued and unpaid interest.  Upon the occurrence of a change of control, we are required to offer to purchase the First Lien Notes at a price equal to 101% of the aggregate principal amount of First Lien Notes repurchased plus accrued and unpaid interest. Further, upon the occurrence of certain asset sales, we are required to provide notice of the same and are required to offer to purchase a defined portion of the First Lien Notes at a price equal to 100% of the principal amount of First Lien Notes repurchased plus accrued and unpaid interest.

The First Lien Indenture restrict our ability and the ability of our restricted subsidiaries to: (i) transfer or sell assets; (ii) make loans or investments; (iii) pay dividends, redeem subordinated indebtedness or make other restricted payments; (iv) incur or guarantee additional indebtedness or issue disqualified capital stock; (v) create or incur certain liens; (vi) incur dividend or other payment restrictions affecting certain subsidiaries; (vii) consummate a merger, consolidation or sale of all or substantially all of our assets; (viii) enter into transactions with affiliates; and (ix) engage in business other than the oil and gas business. These covenants are subject to a number of important exceptions and qualifications.

The First Lien Indenture provides that each of the following is an Event of Default: (i) default for 30 days in the payment when due of interest on the First Lien Notes; (ii) default in payment when due at maturity, upon redemption or otherwise, of the principal of, or premium, if any, on the First Lien Notes; (iii) failure by us or any of our restricted subsidiaries to comply with certain covenants relating to merger, consolidation or sale of assets; (iv) failure by us or any of our restricted subsidiaries to comply for 60 days after notice with certain provisions under the First Lien Indenture; (v) default under any mortgage, indenture or similar instrument of indebtedness by us or any of our restricted subsidiaries, if the indebtedness aggregates $5 million or more, and that default: (a) is caused by a failure to pay principal of, or interest or premium, if any, on such indebtedness prior to the expiration of the grace period for such indebtedness or (b) results in the acceleration of such indebtedness prior to its stated maturity; (vi) failure by us or any of our restricted subsidiaries to pay final judgments aggregating in excess of $5 million, which judgments are not paid, discharged or stayed for a period of 60 days; (vii) any First Lien Note guarantee ceases to be in full force and effect, other than in accordance with the terms of the First Lien Indenture, or a guarantor of the First Lien Notes denies or disaffirms its obligations under its First Lien Note guarantee; (viii) any security document ceases to be in full force and effect in all material respects or ceases to give the collateral agent the rights, powers and privileges purported to be created therein with respect to any collateral having a fair market value in excess of $1 million or we or any of the Guarantors contest the effectiveness, validity or enforceability of any of the security documents; and (ix) certain events of bankruptcy or insolvency described in the Indenture with respect to our company or any of our significant subsidiaries. In the case of an Event of Default arising from certain events of bankruptcy or insolvency with respect to our company, certain restricted subsidiaries or certain groups of restricted subsidiaries, all outstanding First Lien Notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the Trustee or the holders of at least 25% in principal amount of the then outstanding First Lien Notes may declare all the First Lien Notes to be due and payable immediately.

In connection with the issuance and sale of the First Lien Notes, we, the First Lien Trustee and The Bank of New York Mellon Trust Company, N.A., in its capacity as trustee and collateral under the Second Lien Documents (as defined below)(the “Second Lien Trustee”) entered into an Intercreditor Agreement (the “Intercreditor Agreement”). Pursuant to the Intercreditor Agreement, parties agreed that the lien with respect to collateral securing the First Lien Indenture and related First Lien Notes and Guarantees (the “First Lien Obligations”) shall be senior in right, priority, operation, effect and all other respects to any lien with respect to collateral securing the obligations under that certain Indenture dated as of June 12, 2011, as supplemented or amended from time to time thereafter (the “Second Lien Indenture”), by and among our company, the Guarantors named therein and the Second Lien Trustee, and the related Second Lien Notes in the aggregate amount of $125.2 million (the “Second Lien Obligations”).

Forbearance Agreements

On January 30, 2015, we, along with our subsidiaries, Lobo Operating, Inc., Lobo Resources, Inc., Harvest Oil & Gas, LLC and The Harvest Group, LLC entered into a forbearance agreement (the “First Lien Forbearance Agreement”) with the holders of the First Lien Notes.  Also on January 30, 2015, we entered into a forbearance agreement (the “Second Lien Forbearance Agreement”) with the holders (the “Second Lien Lenders”) of seventy-five percent (75%) or more in principal amount of the Second Lien Notes.

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The First Lien Forbearance Agreement and the Second Lien Forbearance Agreement were entered into following (i) our failure to pay to the First Lien Lenders an interest installment in the amount of $1.3 million scheduled for payment on December 31, 2014, and constituting a default if not paid by January 30, 2015 (the “Anticipated First Lien Default”), and (ii) our failure to pay to the Second Lien Lenders an interest installment in the amount of $7.9 million scheduled for payment on January 1, 2015, and constituting a default if not paid by February 2, 2015 (the “Anticipated Second Lien Default,” and, together with the Anticipated First Lien Default, the “Specified Defaults”).

We received confirmation from the First Lien Lenders that they hold more than 75% of the principal amount of the outstanding Second Lien Notes and have each agreed, during the Forbearance Period (as defined below), not to provide any direction to the Second Lien Trustee or to take any steps to enforce any rights of the Second Lien Trustee or the holders of Second Lien Notes occasioned by our failure to make the January 1, 2015 interest payment.

Pursuant to the First Lien Forbearance Agreement, the First Lien Lenders agreed to forbear, until the earlier of March 16, 2015 or the occurrence of certain defaults defined in the First Lien Forbearance Agreement (the “Forbearance Period”), from exercising certain of their default-related rights and remedies with respect to the Specified Defaults in order to permit an opportunity to effectuate a restructuring/refinancing or implement operational improvements.

Under the terms of the First Lien Forbearance Agreement, among other things, we agreed to (i) pay, by February 2, 2015, the December 31, 2014 interest payment owing to the First Lien Lenders, with interest at the default rate, in the amount of $1,378,650; (ii) pay expenses incurred by the First Lien Lenders in connection with the Forbearance Agreement, including paying a retainer to counsel for the First Lien Lenders; (iii) retain, by March 2, 2015, a financial advisor acceptable to the First Lien Lenders on terms acceptable to the First Lien Lenders; (iv) deliver to the First Lien Lenders a 6-week operating budget in form and methodology acceptable to the First Lien Lenders and to abide by that budget within permitted variances; (v) deliver to the First Lien Lenders, not later than March 2, 2015, certain financial, operating and other information and, not later than March 15, 2015, a two year business plan and 2015 budget; and (vi) cause our officers, financial advisors, investment bankers and others to furnish information reasonably requested by the First Lien Lenders.

Any breach on our part of any covenant in the First Lien Forbearance Agreement, or the commencement of any bankruptcy, insolvency or creditor relief proceedings by or with respect to our company, will constitute an event of default under the First Lien Forbearance Agreement.

Pursuant to the Second Lien Forbearance Agreement, the Second Lien Lenders agreed to forbear, during the Forbearance Period, from exercising certain of their default-related rights and remedies with respect to the Specified Defaults in order to permit an opportunity to effectuate a restructuring/refinancing or implement operational improvements. The Second Lien Forbearance Agreement is substantially identical to the First Lien Forbearance Agreement except that the January 1, 2015 interest payment on the First Lien Notes is not required to be made.

On March 16, 2015, we entered into amendments to the First Lien Forbearance Agreement and the Second Lien Forbearance Agreement, extending the Forbearance Period to April 30, 2015.

Advisory Agreement

In March 2015, pursuant to the terms of the Forbearance Agreements, we entered into an engagement letter (the “Engagement Letter”) with Conway MacKenzie Management Services, LLC (“CMS”).  Pursuant to the Engagement Letter, we appointed principals of CMS to the Interim Chief Financial Officer and Strategic Alternatives Officer positions.  Those officers are engaged to assist us in connection with our efforts to restructure or repay the First Lien Notes and Second Lien Notes.  We will pay CMS a fee of $50,000 per month for services of the Interim Chief Financial Officer and pay hourly fees for services of other CMS personnel.

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Critical Accounting Policies

We prepare our consolidated financial statements in this report using accounting principles that are generally accepted in the United States (“GAAP”). GAAP represents a comprehensive set of accounting and disclosure rules and requirements. We must make judgments, estimates, and in certain circumstances, choices between acceptable GAAP alternatives as we apply these rules and requirements. The most critical estimate we make is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depreciation, depletion, and amortization of oil and gas properties and the estimate of the impairment of our oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the related standardized measure of discounted future net cash flows.

Estimated Oil and Gas Reserves

The evaluation of our oil and gas reserves is critical to management of our operations and ultimately our economic success. Decisions such as whether development of a property should proceed and what technical methods are available for development are based on an evaluation of reserves. These oil and gas reserve quantities are also used as the basis of calculating the unit-of-production rates for depreciation, evaluating impairment and estimating the life of our producing oil and gas properties in our asset retirement obligations. Our proved reserves are classified as either proved developed or proved undeveloped. Proved developed reserves are those reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include reserves expected to be recovered from new wells from undrilled proven reservoirs or from existing wells where a significant major expenditure is required for completion and production.  We also report probable reserves and possible reserves, each of which reflects a lower degree of certainty of realization than proved reserves.

Independent reserve engineers prepared the estimates of our oil and gas reserves presented in this report with respect to transition zone properties, and our internal technical team prepared the estimates of our oil and gas reserves presented in this report with respect to Gulf of Mexico properties, based on guidelines promulgated under GAAP and in accordance with the rules and regulations of the SEC. The evaluation of our reserves by the independent reserve engineers and by our internal technical team involves their rigorous examination of our technical evaluation and extrapolations of well information such as flow rates and reservoir pressure declines as well as other technical information and measurements. Reservoir engineers interpret these data to determine the nature of the reservoir and ultimately the quantity of proved, probable and possible oil and gas reserves attributable to a specific property. Our proved reserves in this report include only quantities that we expect to recover commercially using current prices, costs, existing regulatory practices and technology. While we are reasonably certain that the proved reserves will be produced, the timing and ultimate recovery can be effected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir, or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with significant changes in development strategy, oil and gas prices, or production equipment/facility capacity.

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows relies on these estimates of oil and gas reserves using commodity prices and costs. Commodity prices are based on the average prices as measured on the first day of each of the last twelve calendar months. In our 2014 year-end reserve report, we used an average oil price of $96.30 per Bbl, and a natural gas price of $4.47 per Mcf which includes adjustments by property for energy content, quality, transportation fees, and regional price differentials. While we believe that future operating costs can be reasonably estimated, future prices are difficult to estimate since the market prices are influenced by events beyond our control. Future global economic and political events will most likely result in significant fluctuations in future oil and gas prices.

Revenue Recognition

We recognize oil and gas revenue from interests in producing wells as the oil and gas is sold. Revenue from the purchase, transportation, and sale of natural gas is recognized upon completion of the sale and when transported volumes are delivered. We recognize revenue related to gas balancing agreements based on the sales method. Our net imbalance position at December 31, 2014 was immaterial.

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Derivative Instruments

We account for derivative activities by applying authoritative accounting and reporting guidance which requires that every derivative instrument be recorded on the balance sheet as either an asset or a liability measured at its fair value and that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Substantially all of the derivative instruments that we utilize are to manage the price risk attributable to our expected oil and gas production. We have elected not to designate price risk management activities as accounting hedges under the accounting guidance and, accordingly, account for them using the mark-to-market accounting method. Under this method, the changes in contract values are reported currently in earnings.

Oil and Gas Operations

Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting.

Oil and gas leasehold acquisition costs are capitalized and included in the balance sheet caption properties, plants and equipment. Leasehold impairment is recognized based on exploratory experience and management’s judgment. Upon achievement of all conditions necessary for the classification of reserves as proved, the associated leasehold costs are reclassified into proved properties.

Oil and gas exploration costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or “suspended,” on the balance sheet pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field, or while we seek government or co-venture approval of development plans or seek environmental permitting. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves.

Oil and gas development costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

Assets are grouped in accordance with the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.

When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas and crude oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

We record the fair value of legal obligations to retire and remove long-lived assets in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related properties, plants and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties, plants and equipment is depreciated over the useful life of the related asset.

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Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and do not have a future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a purchase business combination) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties, such as state reimbursement funds, are recorded as assets when their receipt is probable and estimable.

Results of Operations

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Oil and Gas Revenue

Oil and gas revenue for the year ended 2014 decreased by 23.8% to $52.3 million from $68.7 million in 2013.

The following table discloses the oil and gas sales revenues, net oil and natural gas production volumes, and average sales prices for the years ended December 31, 2014 and 2013:

Oil production was down 91.9 MBbl, or 15.2%, as compared to 2013.  The decrease was primarily due to steep declines in run times and production rates during the first quarter of 2014, elevated declines rates in certain high production wells, increased water-cut in selected wells, gas lift gas shortages, mechanical issues and flow line capacity constraints, all of which were partially offset by the addition of production from recompletions, workovers and new drills during 2014 and the second half of 2013.

Production optimization initiatives and infrastructure improvements undertaken throughout 2014 addressed the principal causes of decreased run times, gas lift gas shortages, mechanical issues and flow line capacity constraints, raising run time and production rates to approximately 80% and 1904 Boepd during the fourth quarter of 2014 from 54% and 1330 Boepd during first quarter of 2014.

Natural gas production was down 248.7 MMcf, or 20.7%, as compared to 2013. The decrease in gas production was principally related to natural decline and depletion of several wells and the recompletion of a previous gas producer uphole to an oil zone, partially offset by gas-targeted recompletions.

The decrease in realized hydrocarbon prices reflects the steep drop in global oil prices during the second half of 2014. We continued to realize a premium pricing on both our crude oil and natural gas production.

Oil and Gas Hedging

For 2014, we recorded a gain on oil and gas hedging of $1.6 million compared to a loss on oil and gas hedging of $1.7 million in 2013.

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Other Revenues

Other revenues during 2014 consist principally of production handling fees and an insurance settlement for a loss incurred in the prior year.  Other revenues during 2013 consisted principally of production handling fees and a reversal of an over accrual relating to the settlement of the Plaquemines Parish ad valorem tax litigation.

Operating Expenses

Operating expenses increased by 173.8% to $173.8 million for 2014 from $63.7 million in 2013.  The following table sets forth the components of operating expenses, in total and on a per Boe basis, for 2014 and 2013:

The changes in operating expenses were primarily attributable to the factors discussed below.

Lease Operating Expense

Lease operating expenses for 2014 increased 13.9% to $24.6 million from $21.7 million in 2013 and, on a per BOE basis increased 36.2% to $36.76 per BOE from $26.99 per BOE in 2013.

The increase in operating expenses during 2014 was primarily attributable to (i)  increased contract construction labor costs incurred in Grand Bay, Breton Sound, and Main Pass 25 Fields; (ii) one-time contract construction labor and building repair and maintenance expenses for living quarters in Grand Bay Field; (iii) increased contract pumping costs in Breton Sound and Main Pass 25/46 Fields for services provided to replace reduced field personnel as part of first quarter 2014 initiative to increase operational efficiencies; (iv) increased surface equipment repair and maintenance expense in Breton Sound 32 and Grand Bay Fields; (v) increased equipment rental expense for Breton Sound 32 and Grand Bay Fields; (vi) increased platform/flow lines repair and maintenance expenses in Main Pass 25/46 and Breton Sound 51 Fields; and (vii) increased well maintenance expense in Breton Sound 32 Field, largely due to a one time flow line well maintenance charge in March of 2014, in addition to some increases in Grand Bay and Main Pass 25/46 Fields.   An estimated $2.0 million of the increase in lease operating expense related to contract construction labor, equipment repairs and maintenance, and well maintenance charges that were associated with our production optimization initiatives.  We will seek to reduce our reliance on, and cost of, contract operating personnel as we seek to internally hire high-quality personnel for our field operations.  We expect those expenses will decrease and result in future lease operating expenses leveling off.  The increases in contract construction labor, contract pumping gaugers, repair and maintenance expenses were partially offset by decreases in slickline operations, payroll/payroll burden, and regulatory compliance expenses.

Workover Expense

Workover expense for 2014 increased 83.3% to $4.5 million from $2.5 million in 2013. The increase in workover expense was attributable to an increase in the number of workovers completed in 2014.

Exploration Expense

Exploration expense for 2014 decreased 21.5% to $0.7 million from $0.9 million in 2013.  The decrease in exploration expenses principally relates to the full field studies done on the Gulf of Mexico shelf acreage during 2013.

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Loss on plugging and abandonment

Loss on plugging and abandonment decreased to $0 in 2014 from $0.7 million in 2013.  The 2013 loss reflects plugging and abandonment costs in excess of estimated costs reflected in our asset retirement obligation liabilities.

Depreciation, Depletion and Amortization (DD&A)

Depreciation, depletion and amortization for 2014 increased 3.4% to $17.9 million from $17.3 million in 2013.  The increase in DD&A was attributable to a reduced proved reserve base which was partially offset by lower production levels and lower capital expenditures. DD&A is computed on the units-of-production method separately on each individual property and includes the accrual of future plugging and abandonment costs.

Impairment expense

Impairment expense for 2014 increased 4,845.9% to $107.8 million from $2.2 million in 2013.  Impairment expense during 2014 related primarily to the Grand Bay and Vermilion 16 fields and resulted primarily from the reclassification of 7,755 MBoe of reserves out of the proved undeveloped category and into the probable category under the application of the SEC’s so-called “five year rule”.  The five year rule requires the removal of reserves from presentation as proved reserves if not developed within five years of initially being booked into the proved undeveloped category.  Also contributing to the impairment expense was the steep decline in commodity prices which resulted in in lower expected future cash flows at a producing field level. Impairment expense during 2013 related to the loss of a lease, and associated reserves, at our Little Bay Field.

Accretion expense

Accretion expense for 2014 decreased 29.7% to $1.8 million from $2.6 million in 2013.  Accretion expense relates to our asset retirement obligations. The decrease in accretion expense was attributable to changes in the anticipated plugging dates and discount rates used in calculating the asset retirement obligation for certain fields.

Gain on revision of asset retirement obligations

Gain on revision of asset retirement obligations decreased to $0.1 in 2014 from $0.6 million in 2013.  The gains are due primarily to downward revisions in the asset retirement obligations relating to two properties which exceeded the carrying amount of the property.

General and Administrative Expense

General and administrative expense for 2014 increased 3.2% to $9.5 million from $9.3 million in 2013.  The increase in general and administrative expense was primarily attributable to increased consulting fees and legal and professional fees, partially offset by a decrease in non-cash stock compensation expense.

Severance Taxes

Severance taxes for 2014 decreased 49.8% to $3.6 million from $7.3 million in 2013. The decrease was primarily attributable to production declines and the horizontal well severance tax exemptions obtained for our Rocky, Zeke, and Rocky 3 wells and the deep well severance tax exemption obtained for our Mesa Verde well.  Some of these exemptions resulted in refunds of severance taxes paid in prior periods which totaled $0.5 million.

Arbitration Loss

As a result of the arbitration award rendered during 2014, we recorded an arbitration award expense of $3.4 million during 2014.

Other Income (Expense), Net

Net other expenses for 2014, consisting of net interest expense, increased 13.1% to $24.3 million from $21.4 million in 2014.  The increase in interest expense was attributable to our placement of $54.6 million in principal of the First Lien Notes in November 2013, partially offset by a simultaneous reduction of $27.3 million in principal of the Second Lien Notes.

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Income Tax Provision (Benefit)

For 2014, we recorded an income tax provision of $0.2 million compared to $8.6 million in 2013.  The 2013 income tax provision reflects recognition of a valuation allowance against deferred tax assets which primarily relate to our net operating loss carry-forwards.

Our effective tax rates for 2014 and 2013 were (0.1)% and (48.6)%, respectively.  Our effective tax rates were different than our federal statutory tax rate due to state income taxes associated with income from various locations in which we have operations. Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices, the timing, amount, and location of future production and future operating expenses and capital costs.

Financial Condition

Liquidity and Capital Resources

Our principal requirements for capital are to fund our day-to-day operations and exploration, development and acquisition activities and to satisfy our contractual obligations, primarily for the repayment of debt.

During 2013 and 2014 we funded operations out of operating cash flow and cash on hand, which funds have been supplemented by our receipt of funds from our issuance of $27.3 million of First Lien Notes for cash in November 2013. During 2013 and 2014, we did not have access to available capital under a revolving credit agreement and do not at this time have a revolving credit facility.

We incurred a loss from operations of $119 million for the year ended December 31, 2014 and had a working capital deficit of $186 million at December 31, 2014.  These conditions raise substantial doubt as to our ability to continue as a going concern.  These financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern.  To address these matters, we are seeking to restructure our debt or find alternative sources of financing.  There can be no assurance that we will be successful in our efforts.

We developed, and beginning in 2011 commenced, a layered, multi-faceted development and maintenance program designed to achieve short-, mid- and long-term objectives. Short-term objectives are focused on restoration of shut-in and curtailed production through investments in infrastructure and deferred maintenance and recompletions, workovers and thru-tubing plugbacks each designed to increase or restore production volumes from wells producing below capacity and an inventory of proved developed nonproducing opportunities. Mid-term, following or in conjunction with execution of short-term opportunities, our focus is on the development of an inventory of proved undeveloped opportunities within our inventory of proved undeveloped wells targeting normally pressured oil and gas.  Long-term, following or in conjunction with the execution of our short- and mid-term opportunities, our focus is on continuing development of our reserves and exploratory drilling of deep shelf opportunities.  During 2013 and 2014, while continuing to advance short-term objectives associated with continual investment in our infrastructure, we focused on our mid-term objectives through drilling proved undeveloped opportunities.

As a result of reduced production volumes early in 2014, and resulting operating losses and declines in cash flows, together with sharply lower commodity prices, our liquidity position deteriorated substantially during 2014. We have implemented cost cutting measures and curtailed development of our proved undeveloped opportunities in favor of building our cash position to, among other things, support our scheduled payments of interest on outstanding debt.  In January 2015, we entered into forbearance agreements with our lenders, paying only the interest on first lien indebtedness but not paying interest on second lien indebtedness.  We are presently working with our lenders and with prospective financing sources to add liquidity and/or refinance our debt.  Our cash on hand at December 31, 2014, together with operating cash flows, is expected to be adequate to support basic operations and maintenance but, absent increased commodity prices and/or production, is not expected to be adequate to support development activities or debt service obligations over the next twelve months. Further, should we be unable to have the recent arbitration award reversed and be required to pay such award, our existing cash reserves would be materially reduced.  We are presently evaluating options for bringing in additional financing to support our liquidity needs and planned development program. We do not, however, presently have any commitments to provide financing and there is no assurance that any additional financing will be provided on acceptable terms or at all. Should we be unable to pay our scheduled interest payments or to reach acceptable accommodations with our lenders regarding such payments, we may be subject to legal actions instituted by our lenders which may include foreclosure of liens and possible loss of assets.

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Cash, Cash Flows and Working Capital

We had a cash balance of $10.9 million and negative working capital of $185.7 million at December 31, 2014 as compared to a cash balance of $32.5 million and working capital of $20.4 million at December 31, 2013.   The change in cash on hand and working capital is primarily attributable to the operating losses during 2014 and the reclassification of our First Lien Notes and Second Lien Notes from long-term to short-term.

Operations used $5.1 million during 2014 as compared to providing $7.6 million during 2013. The change in operating cash flows during 2014 was principally attributable to reduced profitability resulting from lower production volumes, lower commodity prices, increased operating costs, and changes in our operating assets and liabilities.

Investing activities used cash flows of $14.7 million during 2014 as compared to $31.0 million during 2013.  The decrease in cash used in investing activities during 2014 was primarily attributable to a reduction in development drilling during 2014.

Financing activities used $1.8 million during 2014 as compared to providing $23.7 million during 2013.  Cash flows used in financing activities during 2014 related to repayments of short-term notes payable. Cash flows provided by financing activities during the 2013 reflect the receipt of $25.3 million of net proceeds from our November 2013 sale of First Lien Notes, partially offset by repayments of short term notes.

Debt

At December 31, 2014, we had $178.8 million of indebtedness outstanding, consisting of $54.6 million in face amount of 10% First Lien Notes, less $0.2 million of debt discount, and $125.2 million in face amount of 12½% Senior Secured Notes due 2016 less $0.8 million of debt discount.

We had no letters of credit outstanding at December 31, 2014 that were not fully collateralized by cash.

10% First Lien Notes.  In November 2013, we issued $54.6 million in aggregate principal amount of our 10.0% Senior Secured Notes due 2015 (the “First Lien Notes”).

The 10% First Lien Notes are our senior secured obligations and are fully and unconditionally guaranteed on a senior secured basis by the Guarantors and will rank equally in right of payment with our, and the Guarantors’, existing and future senior indebtedness and senior in right of payment to 12½% Second Lien Notes.

The 10% First Lien Notes mature on December 31, 2015, and interest, accruing at 10% per annum, is payable on the notes on March 31, June 30, September 30 and December 31 of each year, commencing December 31, 2013.

We have the option to redeem all or a portion of the 10% First Lien Notes at any time at 100% of the principal amount to be redeemed plus accrued and unpaid interest.  Upon the occurrence of a change of control, we are required to offer to purchase the 10% First Lien Notes at a price equal to 101% of the aggregate principal amount of 10% First Lien Notes repurchased plus accrued and unpaid interest. Further, upon the occurrence of certain asset sales, we are required to provide notice of the same and are required to offer to purchase a defined portion of the 10% First Lien Notes at a price equal to 100% of the principal amount of 10% First Lien Notes repurchased plus accrued and unpaid interest.

In connection with the issuance and sale of the 10% First Lien Notes, we, the First Lien Trustee and Second Lien Trustee entered into an Intercreditor Agreement. Pursuant to the Intercreditor Agreement, the parties agreed that the lien with respect to collateral securing the First Lien Indenture and related First Lien Obligations shall be senior in right, priority, operation, effect and all other respects to any lien with respect to collateral securing the obligations under Second Lien Indenture, by and among our company, the Guarantors named therein and the Second Lien Trustee, and the related 12½% Second Lien Notes.

12½% Second Lien Notes.  In July 2011, we issued $127.5 million of our 12½% Second Lien Notes and retired all obligations owing under our prior credit facilities and all outstanding letter of credit obligations.  In December 2012, we issued an additional $25.0 million of our 12½% Second Lien Notes.  In November 2013, we retired $27.3 million in face amount of our 12½% Second Lien Notes pursuant to the issuance of a like amount of 10% First Lien Notes described above.

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The 12½% Second Lien Notes are our senior secured obligations and are fully and unconditionally guaranteed on a senior secured basis by the Guarantors and will rank equally in right of payment with our and the Guarantors’ existing and future senior indebtedness, subject, however, to the Intercreditor Agreement pursuant to which the 10% First Lien Notes are senior in right, priority, operation and effect to the lien securing the 12½% Second Lien Notes. The 12½% Second Lien Notes mature on July 1, 2016, and interest is payable on the notes on January 1 and July 1 of each year.  We have the option to redeem all or a portion of the 12½% Second Lien Notes at any time on or after January 1, 2014 at the redemption prices specified in the Second Lien Indenture pursuant to which the 12½% Second Lien Notes were issued plus accrued and unpaid interest.

In January 2015, we entered into forbearance agreements with respect to both the First Lien Notes and the Second Lien Notes and were in default under those notes, including being default on the payment of interest owing as of January 1, 2015 with respect to the Second Lien Notes in the amount of $7.8 million.

In March 2015, we entered into amendments to the forbearance agreements which extended the forbearance period to April 30, 2015.

Capital Expenditures

Our capital spending for 2014 was $17.4 million relating primarily to development of our oil and gas properties, including drilling one development well ($5.7 million), 9 recompletions ($4.2 million), 14 workovers ($4.5 million), investments in multiple infrastructure projects ($2.9 million) and other leasehold costs ($0.1 million). Capital expenditures were down from $33.9 million during 2013.

As noted, we have the operational flexibility to react quickly with our capital expenditures to changes in our cash flows from operations. Actual levels of capital expenditures in any year may vary significantly due to many factors, including the extent to which properties are acquired, drilling results, oil and gas prices, industry conditions and the prices and availability of goods and services.

Contractual Obligations

The following table details our long-term debt and contractual obligations as of December 31, 2014:

_____________________

⁽¹⁾

Debt consists of amounts owing under our 10% First Lien Notes and 12½% Second Lien Notes and related unpaid interest. Debt shown as due in 2015 includes $127.5 million in principal amount of 12½% Second Lien Notes with a stated maturity date of July 1, 2016, which notes are subject to an ongoing forbearance agreement and, as such, are shown as due in 2015.

Risk Management Activities – Commodity Derivative Instruments

During the third quarter of 2012, we reinstituted a hedging program and have since utilized various derivative instruments to manage our risk associated with commodity price movements. We periodically enter into price-risk management transactions (e.g., swaps, and floors) for a portion of our oil and natural gas production.  In certain cases, this allows us to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations.  The commodity derivative instruments apply to only a portion of our production, and provide only partial price protection against declines in oil and natural gas prices, and partially limit our potential gains from future increases in prices.  None of these instruments have been used for trading purposes. During 2014, we did not record any significant unrealized gain on commodity derivatives in current earnings or accumulated other comprehensive income (loss).

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements or guarantees of third party obligations at December 31, 2014.

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Inflation

We believe that inflation has not had a significant impact on our operations since inception.

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

Our major market-risk exposure is the commodity pricing applicable to our oil and natural gas production.  Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas.  Prices have fluctuated significantly during the last five years and such volatility is expected to continue, and the range of such price movement is not predictable with any degree of certainty. In the normal course of business we periodically enter into commodity derivative transactions, including fixed price and ratio swaps to mitigate exposure to commodity price movements, but not for trading or speculative purposes.

As of December 31, 2014, we had the following crude oil hedge contracts outstanding:

We are exposed to market risk on derivative instruments to the extent of changes in market prices of crude oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity.  Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts.  The change in the fair value of our commodity derivative contracts that are effective are recorded to Accumulated Other Comprehensive Income (Loss) in Stockholders’ Equity in the Consolidated Balance Sheet.  The ineffective portion of the change in fair market value of derivatives is recorded currently in earnings as a component of Oil and Gas Hedging in the Consolidated Statements of Operations.  We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities.  For 2014, we did not record any unrealized gain or loss on commodity derivatives in accumulated other comprehensive income (loss).

Koch Supply & Trading, LP is the counterparty to our present covered call option. We are exposed to credit losses in the event of nonperformance by the counterparty on our commodity derivatives positions.  However, we do not anticipate nonperformance by the counterparty over the term of the commodity derivatives positions.

Interest Rate Risk

We consider our interest rate risk exposure to be minimal as a result of fixing interest rates on our existing debt. In the event that we put in place a new revolving credit facility, we anticipate that borrowings under such a facility will bear interest at a floating rate in which case we would be exposed to risk associated with such fluctuation.

Item 8.

Financial Statements and Supplementary Data

Our financial statements appear immediately after the signature page of this report.  See “Index to Financial Statements” on page 68 of this report.

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

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Item 9A.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation as of December 31, 2014 of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2014.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as that term is defined in Exchange Act Rule 13a-15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes in accordance with generally accepted accounting principles (“GAAP”). Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations.  Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.  In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2014, as required by Section 404 of the Sarbanes-Oxley Act of 2002, our management conducted an assessment, including testing, based on the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”).  A material weakness is a control deficiency, or a combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of our annual or interim financial statements will not be prevented or detected.  As a result of our management’s assessment it was determined that a material weakness existed in the system of Internal Controls over Financial Reporting relating to the calculation of asset retirement obligation (“ARO”) and that our internal controls over financial reporting were not effective at December 31, 2014. In order to remediate the material weakness, management will begin utilizing specialized software designed specifically to calculate ARO. This software is in the process of being implemented and used for the calculation of the Asset Retirement Obligation and is expected to be in place during 2015.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit smaller reporting companies to provide only management’s report in this annual report.

Changes in Internal Control over Financial Reporting

No change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) occurred during the fourth quarter of fiscal 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.

Other Information

Not applicable

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PART III

Item 10.

Directors, Executive Officers and Corporate Governance

Executive Officers and Directors

Our current executive officers and Directors, and their ages and positions, are as follows:

The following is a biographical summary of the business experience of our executive officers and Directors:

Thomas F. Cooke co-founded our company in 1990 and has served as our Chief Executive Officer and Chairman since October 2007.  Mr. Cooke served as our President, Chief Executive Officer and Chairman from 1996 to 2007.  In addition, Mr. Cooke has been self-employed as an independent oil and gas producer and investor for more than 30 years.

Andrew C. Clifford has served as our President and a Director since October 2007. He is a petroleum geologist/geophysicist with over 30 years of experience.  Mr. Clifford’s experience includes providing professional geological services on prospects throughout the United States and around the world as an independent consultant, as Vice President of Exploration for BHP Petroleum and as a Senior Geophysicist for BHP Petroleum, Kuwait Foreign Petroleum and Esso Exploration.  Prior to joining the company, Mr. Clifford was a co-founder and Executive Vice President of Aurora Gas, LLC, an independent gas developer and producer with gas production operations in Cook Inlet, Alaska.  Mr. Clifford holds a B.Sc, with honors, in Geology with Geophysics from London University and is a frequent speaker and published author on a variety of energy industry topics.

Randal McDonald, Jr. has served as our Vice President – Finance and Accounting since January 2015 and previously served as our Controller since November 2011. Previously, from 2007 to 2011, Mr. McDonald served as Controller of Baseline Oil & Gas Corp., an independent oil and gas company.  From 1998 until 2007, Mr. McDonald served as Chief Financial Officer and a Director of VTEX Energy, Inc., a publicly traded independent oil and gas company.  Mr. McDonald holds a B.B.A. degree in Accounting from the University of Texas at Austin and is a licensed Certified Public Accountant.

John W. Rhea, IV has served as a Director since 2011.  Since 2009, Mr. Rhea has been the owner and principal of J.W. Rhea & Associates, a petroleum exploration consulting firm.  Mr. Rhea holds a B.S.M.E. in Engineering from the University of Texas.

Rex H. White, Jr. has served as a Director since 2006.  Mr. White is the owner and principal of Rex H. White, Jr., Attorney at Law, a Board Certified Oil, Gas and Mineral Law attorney.  Previously, Mr. White worked as a petroleum geologist/geophysicist for approximately ten years.  Mr. White holds a B.S. in Geology, an M.A. in Geology with a minor in Petroleum Engineering and an L.L.B. all from the University of Texas.

Kevin M. Smith has served as a Director since 1997.  Since 1984, Mr. Smith has been the owner and principal of Kevin M. Smith, Inc., a geophysical consulting firm.  Mr. Smith holds a B.S. in Geology and Geophysics from the University of Houston.

There are no family relationships among the executive officers and directors.  Except as otherwise provided in employment agreements, each of the executive officers serves at the discretion of the Board.

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Involvement in Certain Legal Proceedings

Messrs. Cooke, Clifford, Smith and White were each directors of our company, and Messrs. Cooke and Clifford were officers of our company, at the time of our filing for protection under Chapter 11 of the U.S. Bankruptcy Code in March 2009.  We exited bankruptcy with our assets and equity intact in May 2010.

Mr. Rhea served as a Director, and in various executive positions including Chief Executive Officer, Chief Operating Officer and President, of Latitude Solutions, Inc. from July 2012 to November 2012. Latitude Solutions filed for protection under Chapter 7 of the U.S. Bankruptcy Code in November 2012.

Board Committees

Our board has two standing committees: an audit committee and a compensation committee.  The composition and other information relating to the functioning of those committees is summarized as follows:

Audit Committee

The audit committee is composed of three directors, Mr. Rhea, Chairman, and Messrs. White and Smith, each of whom meets the independence and financial literacy requirements as defined by applicable NYSE MKT and SEC rules. The audit committee assists the board in its general oversight of our financial reporting, internal controls, legal compliance, ethics programs and audit functions, and is directly responsible for the appointment, evaluation, retention and compensation of the registered public accounting firm. The board has determined that Mr. Rhea qualifies as an “audit committee financial expert” in accordance with the applicable rules and regulations of the SEC.

Compensation Committee

The compensation committee is composed of three directors, Mr. White, Chairman and Messrs. Rhea and Smith, each of whom is a non-employee independent director as defined by applicable NYSE MKT rules. The committee is responsible for establishing and administering the policies that govern both annual compensation and equity ownership. It reviews and approves salaries, bonus and incentive compensation, perquisites, equity compensation, and all other forms of compensation for our executive officers, including our chief executive officer. The compensation committee is also responsible for reviewing and administering our incentive compensation plans, equity incentive programs and other benefit plans. Pursuant to authority granted under our 2011 Omnibus Incentive Plan, the committee has delegated to Messrs. Cooke and Clifford the authority to make awards to employees other than those subject to Section 16 of the Securities Exchange Act of 1934.  The committee may from time to time engage the services of an independent executive compensation consultant to advise the committee on matters related to executive compensation. The committee periodically reviews and makes recommendations to the board with respect to director compensation.

Compensation Committee Interlocks and Insider Participation

The current members of our compensation committee are Messrs. White, Rhea and Smith. In 2014, none of our executive officers served as a director or member of the compensation committee of another entity, where an executive officer of the entity served as one of our directors or on our compensation committee.

Code of Ethics

The Board of Directors has adopted a separate Code of Business Ethics for the CEO and Senior Financial Officers. This Code of Ethics supplements our general Code of Business Ethics and is intended to promote honest and ethical conduct, full and accurate reporting, and compliance with laws as well as other matters.

The Code of Business Ethics for the CEO and Senior Financial Officers was filed as an exhibit to the Annual Report on Form 10-KSB for the year ended December 31, 2005 and is available for review at the our web site at www.saratogaresources.net.

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Compliance with Section 16(a) of Exchange Act

Under the securities laws of the United States, our directors, executive officers, and any person holding more than ten percent of our common stock are required to report their initial ownership of common stock and any subsequent changes in that ownership to the Securities and Exchange Commission.  Specific due dates for these reports have been established and we are required to disclose any failure to file by these dates during fiscal year 2014.  To our knowledge, all of the filing requirements were satisfied on a timely basis in fiscal year 2014. In making these disclosures, we have relied solely on copies of reports provided to us.

Item 11.

Executive Compensation

Summary Executive Compensation Table

The table below summarizes the total compensation paid to or earned by our named executive officers for each of the two years ended December 31, 2014.

(1)

The amounts reported in the “Option Awards” column reflect the grant date fair value of the options granted to the named executive officers in the year reflected, determined using the Black-Scholes option model. For information relating to the assumptions made by us in valuing the option awards made to our named executive officers in fiscal year 2014, refer to Note 11 of our financial statements for the year ended December 31, 2014.

(2)

All other compensation consists of:

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Employment Agreements

In June 2013, our board of directors approved new employment agreements for our two principal officers, Thomas Cooke and Andy Clifford.  Pursuant to their employment agreements, (i) the annual base salary of Messrs. Cooke and Clifford was increased from its then current level of $305,000 by 4%, to $317,200, on July 1, 2013 and increases by 4% on July 1 of each succeeding year; (ii) the automobile allowance of Messrs. Cooke and Clifford was modified to either provide a company vehicle or pay a monthly automobile allowance, which allowance remains $700 per month for Mr. Clifford and was increased to $950 per month for Mr. Cooke; additionally, beyond repair and maintenance costs previously paid by the company, the automobile allowance has been revised to cover all costs of operating a vehicle; (iii) the expense reimbursement provisions were modified to clarify that the company will pay all incremental costs associated with maintenance of home offices by Messrs. Cooke and Clifford, including costs of internet service, telephone and facsimile service and, with respect to Mr. Clifford, a home workstation; (iv) travel pay in the amount of $200 per day was added for each overnight stay or out-of-town travel of twenty-four hours exclusively for business purposes; (v) Messrs. Cooke and Clifford each received options to purchase 250,000 shares of common stock exercisable at $3.00 per share for a term of five years and vesting on a quarterly basis over eight quarters; (vi) in the event of termination of employment due to death or disability, we will continue to pay base salary to the executive or his estate for a period of twelve months; and (vii) in the event of termination of employment by the company without cause or by the executive for “good reason”, we will pay a lump sum to the executive in an amount equal to two times the base salary and bonus paid during the twelve months immediately preceding termination and shall continue to provide health insurance for a period of twenty-four months.

Outstanding Equity Awards at December 31, 2014

The following table includes certain information with respect to unexercised options held by named executive officers at December 31, 2014:

(1)

The stock options vest and become exercisable ratably over eight quarters from the grant date.  The stock options will become immediately exercisable in their entirety in the event of certain changes in control.

(2)

The stock options become exercisable in 1/3 increments six months from the grant date and on the first and second anniversaries of the grant date.

Director Compensation

We use a combination of cash and equity-based incentive compensation to attract and retain qualified candidates to serve on our board. In setting director compensation, we consider the significant amount of time directors dedicate in fulfilling their duties as directors as well as the skill-level required by the company to be an effective member of our board. The form and amount of director compensation is reviewed by our compensation committee, which makes recommendations to the full board.

Each non-employee director receives an annual fee of $10,000 and committee chairs receive an annual fee of $6,000 for the audit committee and $4,000 for all other committees, each of which fees is payable in two semi-annual installments.  Each non-employee director is reimbursed for reasonable out-of-pocket expenses incurred in attending such meetings.   Additionally, upon initial appoint or election as a director and annually upon reelection as a director, non-employee directors are granted stock options to purchase 35,000 shares of our common stock at the then fair market value.  Under our present director compensation program, option grants expire on the seventh anniversary of the grant date and vest 50% on the date of grant and 50% on the first anniversary of the date of grant.

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In January 2015, a special committee of independent directors was formed to consider strategic alternatives in connection with our entry into Forbearance Agreements with our lenders.  Members of the special committee, consisting of Mr. Rhea, as chairman, and Messrs. White and Smith, are paid a monthly fee for service on the committee in the amount of $4,000 for the chairman and $2,000 for other members.

The table below summarizes the total compensation paid to or earned by our non-management directors during 2014. The amounts included in the “Stock Awards” and “Option Awards” columns reflect the aggregate grant date fair value, and do not necessarily equate to the income that will ultimately be realized by the director for these awards.