Edgar Filing: SARATOGA RESOURCES INC /TX

SARATOGA RESOURCES, INC.

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2009

TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________ to _____________

Commission File No. 1-32955

SARATOGA RESOURCES, INC.

(Exact name of registrant specified in its charter)


Texas		76-0314489
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

7500 San Felipe, Suite 675, Houston, Texas 77063

(Address of principal executive offices)(Zip code)

Issuer's telephone number, including area code:

(713) 458-1560

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which each is registered
None		None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, $0.001 par value

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes o No ý

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “accelerated filer,” “large accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer o Accelerated filer o Non-accelerated filer o Smaller reporting company ý

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant on June 30, 2009, based on the closing sales price of the registrant’s common stock on that date, was approximately $2,281,688. Shares of common stock held by each current executive officer and director and by each person known by the registrant to own 5% or more of the outstanding common stock have been excluded from this computation in that such persons may be deemed to be affiliates.

The number of shares of the registrant’s common stock, $0.001 par value, outstanding as of March 30, 2010 was 16,690,292.

DOCUMENTS INCORPORATED BY REFERENCE

None.

TABLE OF CONTENTS


		Page
PART 1

Item 1.	Business	4
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	26
Item 2.	Properties	26
Item 3.	Legal Proceedings	27
Item 4.	(Removed and Reserved)	27

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Item 6.	Selected Financial Data	28
Item 7.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	28
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 8.	Financial Statements and Supplementary Data	45
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	45
Item 9A(T).	Controls and Procedures	45
Item 9B	Other Information	46

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	47
Item 11.	Executive Compensation	51
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	53
Item 13.	Certain Relationships and Related Transactions, and Director Independence	53
Item 14.	Principal Accountant Fees and Services	54

PART IV

Item 15.	Exhibits and Financial Statement Schedules	55

SIGNATURES		57

FORWARD-LOOKING STATEMENTS

This annual report on Form 10-K contains forward-looking statements within the meaning of the federal securities laws. These forwarding-looking statements include without limitation statements regarding our expectations and beliefs about the market and industry, our goals, plans, and expectations regarding our properties and drilling activities and results, our intentions and strategies regarding future acquisitions and sales of properties, our intentions and strategies regarding the formation of strategic relationships, our beliefs regarding the future success of our properties, our expectations and beliefs regarding competition, competitors, the basis of competition and our ability to compete, our beliefs and expectations regarding our ability to hire and retain personnel, our beliefs regarding period to period results of operations, our expectations regarding revenues, our expectations regarding future growth and financial performance, our beliefs and expectations regarding the adequacy of our facilities, and our beliefs and expectations regarding our financial position, ability to finance operations and growth and the amount of financing necessary to support operations. These statements are subject to risks and uncertainties that could cause actual results and events to differ materially. We undertake no obligation to update forward-looking statements to reflect events or circumstances occurring after the date of this annual report on Form 10-K.

As used in this annual report on Form 10-K, unless the context otherwise requires, the terms “we,” “us,” “the Company,” “Saratoga” and “Saratoga Resources” refer to Saratoga Resources, Inc., a Texas corporation, and its subsidiaries.

PART I

Item 1.

Business

General

Saratoga Resources, Inc. is an independent oil and natural gas company engaged in the production, development, acquisition and exploitation of natural gas and crude oil properties. Our principal properties were acquired in July 2008 and cover an estimated 37,000 gross acres (33,750 net), substantially all of which are held by production without near-term lease expirations, across 11 fields in the state waters of Louisiana. See “Harvest Acquisition.” Prior to the July 2008 acquisition of our Louisiana properties, our operations were focused on production, development, acquisition and exploitation of various mineral interests in the State of Texas.

We have operated as debtors-in-possession under Chapter 11 of the U.S. Bankruptcy Code since March 31, 2009. See “Chapter 11 Reorganization.”

Our total proved reserves as of December 31, 2009 were 107.7 Bcfe, consisting of 62.2 Bcf of natural gas and 7.6 MMBls of oil. The PV-10 of our proved reserves at year-end was $224.0 million before future income taxes, or $145.6 million after future income taxes. Additionally, at year-end we had probable reserves of 68.2 Bcfe, consisting of 45.3 Bcf of natural gas and 3.8 MMBls of oil.

During 2009, we added 37.4 Bcfe through purchases, extensions, discoveries and revisions and produced 5.9 Bcfe. Our average daily net production for December 2009 was 14.4 MMcfe/d, of which 66.7% was oil. We have 59 proved behind pipe and shut-in development opportunities in 9 fields and 77 proved undeveloped opportunities in 3 fields. We also have 57 probable behind pipe and shut-in development opportunities, 36 probable undeveloped opportunities, 14 possible behind-pipe opportunities and 52 possible undeveloped opportunities.

Our principal and administrative offices are located at 7500 San Felipe, Suite 675, Houston, Texas. Our telephone number is (713) 458-1560.

Harvest Acquisition

In July 2008, we acquired (the “Harvest Acquisition”) all of the membership interest in Harvest Oil & Gas, LLC (“Harvest Oil”) and The Harvest Group, LLC (“Harvest Group” and, together with Harvest Oil, the “Harvest Companies”).

As consideration for the membership interests in the Harvest Companies, we paid to the former members of the Harvest Companies a combined purchase price of $105,683,000 in cash and issued 4.9 million shares of our common stock. The cash portion of the purchase price included $33,650,818 and $30,000,000 paid by the Harvest Companies to pay a note payable to Macquarie Bank Limited (“Macquarie”) and to obtain a release of a net profits interest and an overriding royalty interest in the properties of the Harvest Companies held by Macquarie and its affiliates, respectively, which amounts we paid directly to Macquarie on behalf of the Harvest Companies at closing. Of the 4.9 million shares of common stock issued in the acquisitions, 3.3 million shares were issued directly to Macquarie Americas Corp., an affiliate of Macquarie, pursuant to an agreement between Macquarie and the members of the Harvest Companies relating to the release of the net profits interest and overriding royalty interest held by Macquarie.

In conjunction with the Harvest Acquisition, and to finance the acquisition and post-acquisition operations, in July 2008, we entered into a Credit Agreement (the “Wayzata Credit Agreement”) with Wayzata Investment Partners, LLC (“Wayzata”) and a separate Credit Agreement (the “Revolving Credit Agreement”) with Macquarie. We borrowed $97,500,000 under the Wayzata Credit Agreement and approximately $12,528,878 under the Revolving Credit Agreement to pay the purchase price of the Harvest Acquisition and associated costs.

The Harvest Companies were independent oil and natural gas companies engaged in the production, development, and exploitation of natural gas and crude oil properties, together covering an estimated 33,000 gross acres (30,000 net) across 11 fields in the state waters of Louisiana.

We retained the key management and operational team members of the Harvest Companies and, following the Harvest Acquisition, shifted the focus of our operations to the continued development and operations of the various holdings of the Harvest Companies.

Chapter 11 Reorganization

Beginning late in the third quarter of 2008, accelerating during the fourth quarter of 2008, and continuing into the first quarter of 2009, our operations were materially adversely affected by a sharp drop in the projected demand for, and price of, oil and natural gas that accompanied the severe disruptions in credit and financial markets that resulted in economic contraction in the U.S. and globally. While we entered into hedging transactions to reduce our exposure to commodity price risks, we were still subject to risks associated with declines in the price of oil and natural gas relating to unhedged production.

On July 14, 2008, the day of closing for the Harvest Acquisitions, crude oil prices closed at $145.66 per barrel, while the Henry Hub spot price for natural gas averaged $11.45 per thousand cubic feet (Mcf). Oil had remained above $100 per barrel for sixteen consecutive weeks at that time. Equivalent oil and natural gas prices in March 2009 were 63% and 65% respectively lower than they were when we closed the Harvest Acquisitions and entered into the Credit Agreements with Wayzata and Macquarie.

Wayzata issued a notice of default, dated February 26, 2009, wherein it alleged nine non-monetary breaches of the Wayzata Credit Agreement, or events of default. Wayzata, in its notice of default, did not exercise any of its rights under the Wayzata Credit Agreement, but expressly reserved the right to do so. We disputed Wayzata’s notice of default as premature, based on incomplete data and failure to take into account various developments and circumstances.

Macquarie also issued notice of default dated February 26, 2009, which was expressly based on Wayzata’s Notice of Default. The Macquarie notice of default was triggered by cross default provisions in the Revolving Credit Agreement defining an event of default as an event or condition occurring which permits the holder of any material debt to accelerate that obligation. Macquarie stated in its notice of default that it was not initiating any action to exercise its rights and remedies available, though it’s right to do so were expressly reserved. As a result of the Macquarie notice of default, Macquarie rejected our requests to access additional credit available under the Revolving Credit Agreement, which restriction of credit potentially impaired our ability to continue our development program. We disputed the Macquarie notice of default.

Following the receipt of the referenced notices of default from Wayzata and Macquarie, we entered into discussions with Wayzata seeking an amicable resolution and forbearance in order to cure the alleged covenant defaults and to access available credit under our Revolving Credit Agreement to continue pursuit of our ongoing drilling, workover and recompletion program. Despite management’s efforts, management and our board of directors determined that a bankruptcy court reorganization would offer the best means of addressing our existing debt structure and realization of the long-term anticipated benefits of our drilling, workover and recompletion program. To that end, on March 31, 2009 (the “Petition Date”), we, and our principal operating subsidiaries, filed voluntary Chapter 11 petitions in the U.S. Bankruptcy Court for the Western District of Louisiana.

As a result of the Chapter 11 filing, we continued to operate our business and manage our properties as debtors in possession, although our development activities were substantially curtailed due to limited access to financing, and engaged in negotiations and other efforts to resolve issues with our lenders, in particular we sought to restructure the Wayzata Credit Agreement. On December 2, 2009, the Bankruptcy Court entered an order confirming our Second Amended Plan of Reorganization under Chapter 11 of the Bankruptcy Code, as revised and filed with the Bankruptcy Court on November 25, 2009 (the “Second Amended Plan”). Effectiveness of the Second Amended Plan was subject to execution of definitive agreements to refinance our existing debt facilities with Macquarie and Wayzata. After failure to reach agreement with respect to the revised loan documents, the Confirmation Order was withdrawn. On February 11, 2010 we filed our Third Amended Plan of Reorganization (the “Third Amended Plan”). On March 30, 2010, following negotiations with Wayzata which resulted in an agreement in principal as to amended terms of both the Wayzata Credit Agreement (the “Amended Wayzata Credit Agreement”) and the Revolving Credit Agreement (the “Amended Revolving Credit Agreement, we filed a modified Third Amended Plan (the “Modified Third Amended Plan”).

Under the Modified Third Amended Plan, on the effective date (the “Effective Date”) thereof, (1) the claim arising under the Revolving Credit Agreement would be allowed in the amount of $23.5 million (subject to adjustment for accrued interest if the Effective Date is after May 15, 2010), of which $5.5 million would be paid on the Effective Date, the applicable interest rate under the Amended Revolving Credit Agreement would be revised to a base rate plus 2%, the maturity date under the Amended Revolving Credit Agreement would be revised to April 30, 2012, liens arising under the Revolving Credit Agreement would remain in place substantially in their current form and the remaining indebtedness owed would be payable monthly on an interest only basis and on terms substantially identical to those included in the Revolving Credit Agreement, as amended by the Modified Third Amended Plan and reflected in the Amended Revolving Credit Agreement, (2) the claim arising under the Wayzata Credit Agreement would be allowed in the amount of $127.5 million (subject to adjustment for accrued interest if the Effective Date is after May 15, 2010), the interest rate under the Amended Wayzata Credit Agreement would be revised to 11.25%, the maturity date under the Amended Wayzata Credit Agreement would be revised to April 30, 2012, liens arising under the Wayzata Credit Agreement would remain in place substantially in their current form and the indebtedness owed would be payable monthly on an interest only basis and on the terms set out in the Amended Wayzata Credit Agreement, (3) oil lien claim creditors and other secured creditors would be paid 100% of their claims, including costs and accrued interest, with 80% being paid in cash on the Effective Date and 20% being payable in four equal quarterly installments, subject to certain prepayment requirements should we secure financing during the twelve months following the Effective Date, (4) unsecured creditors would be paid 100% of their claims, with 75% being paid in cash on the Effective Date and 25%, plus costs and accrued interest, being payable in four equal quarterly installments, subject to certain prepayment requirements should we secure financing during the twelve months following the Effective Date, (5) state lessor audit royalty claims in the amount of $1,709,656 would be paid 100% in twenty-four equal monthly installments of $71,235.68, and (6) amounts payable to our principal officers, Thomas Cooke and Andy Clifford, pursuant to existing promissory notes, would be payable 100% forty months following the Effective Date, with compound accrued interest and subject to prior satisfaction in full of all allowed claims. The Modified Third Amended Plan also provides for the issuance of (1) a warrant in favor of Wayzata to purchase up to 2,000,000 shares of our common stock exercisable at $0.01 per share, which warrant will vest and become exercisable 111,111 shares on the Effective Date and 111,111 shares per month over the following seventeen months unless all amounts payable under the Amended Wayzata Credit Agreement paid in full, in which case any unvested portion of the warrant on the date of repayment in full will be forfeited, and (2) 483,310 shares of common stock to be issued pro rata among the oil lien claim creditors, other secured creditors and unsecured creditors. The Modified Third Amended Plan provides that all outstanding common stock and warrants would remain outstanding and retain identical rights following the Effective Date, provided, however, that the current equity holders would not be entitled to receive any dividends or distributions in respect of their equity holdings unless and until the holders of all allowed claims have been paid in full in cash in accordance with the Modified Third Amended Plan. Effectiveness of the Modified Third Amended Plan is subject, among other things, to confirmation of the plan by the Bankruptcy Court and execution of the Amended Revolving Credit Agreement and the Amended Wayzata Credit Agreement. There can be no assurance that the Modified Third Amended Plan will ultimately be confirmed and the terms thereof carried out.

In February 2010, Wayzata disclosed that it had acquired all rights of Macquarie under the Revolving Credit Agreement, including the debt thereunder owed by Saratoga, and had unwound all of Saratoga’s commodity hedges.

Confirmation hearings with respect to the Modified Third Amended Plan are scheduled for the week of April 19, 2010.

Our Strategy

During 2009, subject to financing and other constraints during the Company’s bankruptcy, we continued to pursue our strategy of using our competitive strengths to increase our reserves, production and cash flow and, subject to our emergence from bankruptcy, in 2010 we intend to continue our pursuit of that strategy. The following are key elements of our strategy:

Grow Through Exploitation, Development and Exploration of Our Properties. We intend to focus our development and exploration efforts on our Louisiana properties. We believe that our extensive held by production acreage position will allow us to grow organically through lower-risk development drilling. We have attractive opportunities to expand our reserve base through field extensions, delineating deeper formations within existing fields and exploratory drilling. Most of our locations also offer multiple stacked reservoir objectives with substantial behind pipe potential.

Actively Manage the Risks and Rewards of Our Drilling Program. We operate over 89% of the wells that comprise our proved reserves as of December 31, 2009, and we own net revenue interests in our properties that average approximately 72% 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 marketing of production. In addition, our high level of net revenue interests enhances our returns from each successful well we drill by giving us a higher percentage of cash flow generated. We believe our high level of net revenue interests provides us with a unique opportunity to retain a substantial economic interest in higher risk wells 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. We either own or have licensed 3-D seismic data covering over 120 square miles in the Grand Bay and other fields and intend to seek more seismic data in the future. 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.

Pursue Opportunistic Acquisitions. We continually review opportunities to acquire producing properties, leasehold acreage and drilling prospects. We believe our relationship with Macquarie, which introduced us to the Harvest Companies, will provide us with “first look” opportunities relating to potential future acquisitions. When identifying acquisition candidates, we focus primarily on underdeveloped assets with significant growth potential. We seek acquisitions that will allow us to enhance and exploit properties without assuming significant geologic, exploration or integration risk.

Properties

The following table describes our properties and production profile at December 31, 2009.


Property	Natural Gas Equivalent (Bcfe)	% Gas	PV-10⁽¹⁾ (dollars in (thousands)		Net Acreage (estimated)	Net Revenue Interest %	Net Producing Wells	Daily Net Production (Mcfe/d)⁽²⁾	Reserve Life Index⁽³⁾ (Years)
Grand Bay	33	29%	$	67,474	17,609	19-79%	51	4,569	20
Vermilion 16	45	96%		112,409	4,095	75-83%	2	159	*
Other	30	32%		44,096	11,082	31-80%	33	9,634	8
All Properties	108	58%	$	223,979	32,527		86	14,362	21

* Not meaningful

(1)

Based on unweighted average prices as of the first of each month during 2009 of $61.18 per Bbl and $3.87 per MMBtu and before future income taxes.

(2)

Average net production for December 2009.

(3)

Calculated by dividing total net proved reserves by current net production for December 2009.

Grand Bay Field. The Grand Bay Field is located in Plaquemines Parish, Louisiana, approximately 70 miles southeast of New Orleans, Louisiana. It is situated in a shallow open water and marsh environment on the east side of the Mississippi River. Gulf Oil discovered the field in 1938. Harvest Oil and Gas acquired the field in April 2005. A farmout was granted to Clayton Williams Energy, Inc. prior to the acquisition of the field by Harvest Oil, covering approximately 2,000 gross acres in the north-west portion of the field. Saratoga’s ownership in Grand Bay ranges from 25% to 100% working interest and 19% to 79% net revenue interest. We are the operator of all of the Grand Bay Field property not subject to the Clayton Williams Energy, Inc. farmout.

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.

Production has been from over 50 different sands between approximately 1,600 and 13,500 feet, subsea. We are evaluating shallow Pliocene gas potential as well as deeper oil and gas potential in the Tex W, Big Hum, Cris I and Lower Tertiary levels below 13,500 feet. Collarini Engineering began a full field study of the Grand Bay Field in October 2008 and this study is due to be completed by May 2010. Our leases in the Grand Bay Field, which are all held by production, cover an estimated 17,609 gross and net acres. We own a license to 90 square miles of high quality, proprietary 3D seismic data, originally acquired by Greenhill in 1994 and reprocessed by Saratoga in 2008. We are using this dataset to better locate proposed development wells as well as delineating shallow gas exploration 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 gas. We entered into a production tie-in agreement with Apache in late 2008 that improves field efficiencies and we continue to look for ways to decrease operating costs in all fields.

Vermilion 16 Field. The Vermilion 16 Field is located in state waters offshore Vermilion Parish, Louisiana, approximately 40 miles south of Lafayette, Louisiana. It is situated in approximately 12 feet of water, 0.5 miles offshore in the Gulf of Mexico. Saratoga is operator with a 60% to 100% working interest with a net revenue interest ranging from 75% to 83%.

The field is a four-way rollover anticline on the downthrown side of a down-to-the-south fault. There are multiple stacked reservoirs within the field. Pulsed neutron logging has been carried out to identify unswept hydrocarbons within existing wellbores. There are five wellbores associated with this field and a number of proved undeveloped drilling locations within the field. Nutech Energy Alliance began a full field study of the Vermillion 16 Field in October 2008 and this study was completed in December 2009. We licensed 25 square miles of 3D seismic data in 2008 and will use this data to better locate proposed development wells.

Facilities include a central facility and there are five wellbores associated with the field. Production from McMoRan Oil and Gas, LLC’s King Kong wells, located 1.2 miles to the southwest of our platform in adjoining SL 17159, is processed at the Vermilion 16 platform, for which we receive revenues. The existing seven state leases cover an estimated 4,095 gross acres (4,095 net) and are all held by production.

Other Fields. We hold interests in twelve other fields, all in Louisiana state waters, with working interests ranging from 40% to 100%. The net revenue interest ranges from 31% to 80%, except for Breton Sound 31 Field, where we have a 36% net profits interest, and Main Pass 47 Field, where we have a 7.5% overriding royalty interest in one producing well. The leases, which are mostly held by production, cover an estimated 11,921 gross acres (10,822 net).

Among the other fields in which we hold interests are the Main Pass and Breton Sound fields, which are a series of stratigraphic trap-type fields in the Middle Miocene trend that were discovered with 3D seismic technology. The reservoir drive mechanisms are water drive and combination water drive/pressure depletion.

We also hold leasehold interests and a single operating well in Dawson County. Texas. We do not presently intend to conduct any further drilling or exploration operations on our Dawson County property.

Field Infrastructure

We own certain infrastructure assets serving our properties including approximately 85 miles of pipelines connecting several of the fields as well as outlying wellheads. There are six platform facilities plus 96 active producing wellbores associated with these fields, including ten salt water disposal wells. In addition to serving our wells and improving field economics, we generate revenues from providing access to our infrastructure assets to third parties. Facilities at Grand Bay include four tank batteries, a compressor station, various flowlines and a bunk house. We receive third-party processing and production handling revenues from Clayton Williams Energy, Inc., McMoRan Oil and Gas, LLC, Martin-Marks Minerals, LLC and Harvest Operating, LLC.

Natural Gas and Oil Reserves

Reserve Estimates

The following table sets forth, as of December 31, 2009, our estimated net oil and natural gas reserves categorized as proved developed, proved undeveloped, total proved, probable developed, probable undeveloped, possible developed and possible undeveloped, all of which are located in the United States.


	Reserves
Reserve category	Oil	Natural Gas	Total ⁽¹⁾
	(MBbls)	(MMcf)	(MMcfe)
Proved
Developed	2,985	9,387	27,297
Undeveloped	4,593	52,860	80,418
Total Proved	7,578	62,247	107,715

Probable⁽²⁾
Developed	765	5,077	9,667
Undeveloped	3,307	40,260	60,102
Possible⁽²⁾	13,366	101,112	181,308

(1)

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

(2)

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

Revisions to SEC Oil and Gas Reserve Reporting Requirements.

Effective December 31, 2008, the SEC effected revisions designed to modernize the oil and gas company reserves reporting requirements. Among other things, the revised reporting requirements include:

Commodity Prices – Economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless contractual arrangements designate the price to be used.

Disclosure of Unproved Reserves – Probable and possible reserves may be disclosed separately on a voluntary basis.

Proved Undeveloped Reserves – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years.

Reserves Estimation Based on New Technologies – Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

Reserve Personnel and Estimation Process Disclosure – Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process and internal controls used to assure the objectivity of the reserve estimates.

Disclosure by Geographic Area – Reserves in foreign countries or continents must be presented separately if they represent more than 15% of total proved reserves.

Reserve Estimation Process, Controls and Technologies

The reserve estimates set forth above were prepared by Collarini Associates. Collarini Associates also estimated the PV-10 value of our proved reserves, as of December 31, 2009, at $224.0 million. 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. 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 Securities and Exchange Commission (“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. Also, in computing and reporting PV-10 value, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

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. The estimated present value of proved reserves does not include indirect expenses such as general and administrative expenses, debt service and future income tax expense or depletion, depreciation, and amortization.

In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the present value of proved reserves set forth herein are made using average oil and natural gas sales prices as of the first day of each month over the twelve months ended December 31, 2009 which prices are held constant throughout the life of the properties. Estimated quantities of proved reserves and their present value are affected by changes in oil and natural gas prices. The prices utilized for the purpose of estimating our proved reserves and the present value of proved reserves as of December 31, 2009 were a WTI Cushing spot price of $61.18 per Bbl and a Henry Hub spot natural gas price of $3.87 per MMBtu, adjusted by property for energy content, quality, transportation fees, and regional price differentials. Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 2.2 Bcfe.

Collarini Associates is an independent New Orleans-based professional engineering firm specializing in technical and financial evaluation of oil and gas assets. Collarini Associates’ report was prepared under the direction of Mitch Reece, President and Engineering Manager of Collarini Associates. 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 new rules expanded the technologies that a company can use to establish reserves. The SEC now 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 has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Collarini 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.

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.

Proved Undeveloped Reserves

As of December 31, 2009, our proved undeveloped reserves (“PUDs”) totaled 7.6 MMBbls of oil and 62.2 Bcf of natural gas, for a total of 107.7 Bcfe compared to 4.5 MMBbls of oil and 49.6 Bcf of natural gas, for a total of 76.6 Bcfe as of December 31, 2008.

PUD Locations.

All of our PUDs at December 31, 2009 were associated with our Louisiana properties.

Changes in PUDs.

During 2009, our PUDs increased by 36.4 Bcfe as compared to year-end 2008. The increase in our PUDs was attributable to our evaluation of previously unevaluated properties as a result of our ongoing full field evaluations in our Grand Bay and Vermilion 16 fields.

Our development of PUDs during 2009 was limited due to our operation as debtor-in-possession during the pendency of our bankruptcy which limited our access to financing to support development activities.

Development Costs.

Costs incurred relating to the development of PUDs were approximately $0 million in 2009 and $8.6 million in 2008.

Estimated future development costs relating to the development of PUDs are projected to be approximately $450,000 in 2010.

Drilling Plans.

All PUD locations are scheduled to be drilled or otherwise converted to proved developed reserves before the end of 2014. None of our PUD 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, 2009.


	2007⁽²⁾		2008⁽²⁾		2009
Net Production:
Oil (bbl)		616,000		571,975		626,900
Natural gas (Mcf)		3,083,000		1,612,470		2,114,600
Combined volumes (Mcfe)		6,779,000		5,044,000		5,876,000
Daily combined volumes (Mcfe/d)		18,573		13,781		16,099
Average sales price per MMcfe	$	8.47	$	13.66	$	9.83
Average production cost per Mcfe⁽¹⁾	$	3.71	$	5.56	$	4.03

__________________

(1)

Average production cost per Mcfe excludes ad valorem and severance taxes.

(2)

Pro forma 2007 information and pro forma 2008 information prior to July 14, 2008, the date of the Harvest Acquisitions, reflects the combined operations of the Harvest Companies. Information with respect to the Company prior to Harvest Acquisitions is not material and has been omitted.

Drilling Activity

Historical

The following tables sets forth, for the three years ended December 31, 2009, the number of gross and net productive and dry exploratory and developmental wells completed, regardless of when drilling was initiated (all wells are located in the United States). 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.


	Year Ended December 31, 2009		Year Ended December 31, 2008⁽¹⁾
	Gross	Net	Gross	Net
Development
Productive	1	1	-	-
Dry	-	-	-	-
Exploratory
Productive	-	-	-	-
Dry	-	-	-	-

Total
Productive	1	1	-	-
Dry	-	-	-	-

___________________

(1)

2007 information and 2008 information prior to July 14, 2008, the date of the Harvest Acquisitions, reflects the operations of the Harvest Companies.

In addition to the wells completed, as reflected in the above table, during 2008 we recompleted three wells and performed a workover on one well and, during 2009, we recompleted five wells.

Drilling activities during 2009 were substantially curtailed by our inability to draw on our revolving credit facility during our operation as debtors-in-possession.

Present Activities

At December 31, 2009, no wells were being drilled and no other material development or maintenance operations were ongoing.

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.

Delivery Commitments

At December 31, 2009, we had no commitments to provide fixed and determinable quantities of oil and gas under contracts or agreements.

Hedging Activities

We have an active commodity hedging program to mitigate the risks of the volatile prices of natural gas and oil. Under the terms of our existing credit facilities, we are required to hedge not less than 60% or more than 80% of our oil and natural gas production on a forward 12-month basis using a combination of swaps, cashless collars and other financial derivative instruments with counterparties that we believe are creditworthy. In February 2010, Wayzata, acting under our credit agreements, unwound all of our existing hedges notwithstanding the requirement of our credit agreements to maintain hedges. If the Modified Third Amended Plan of Reorganization becomes effective, the Amended Revolving Credit Agreement limits our hedging to not more than 60% of production unless Wayzata consents otherwise. For additional information on our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

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, 2009:


	Gross	Net
Oil wells	105	72
Gas wells	19	13
Total	124	85

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, 2009 included 32 wells with multiple completions.

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, 2009, all of which is located in the United States in the state waters of Louisiana:


Developed Acreage		Undeveloped Acreage		Total Acreage
Gross	Net	Gross	Net	Gross	Net
32,541	31,443	1,084	1,084	33,625	32,527

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. The following table sets forth, as of December 31, 2009, the expiration periods of the gross and net acres that are subject to leases summarized in the above table of undeveloped acreage.


	Undeveloped Acres Expiring
Twelve Months Ending:	Gross	Net
December 31, 2010	-	-
December 31, 2011	-	-
December 31, 2012	1,084	1,084
December 31, 2013	-	-
December 31, 2014 and later	-	-
Total	1,084	1,084

Marketing and Customers

Effective April 1, 2010, we have entered into a Natural Gas, Crude and Processing Marketing/Administration Agency Agreement pursuant to which Transparent Energy Services, Inc. will market substantially all of our oil and natural gas production. During 2009, and through March 31, 2010, substantially all of our oil and natural gas production was marketed by Professional Oil and Gas Marketing, LLC.

Sales of oil and gas production to BP, Shell and Chevron accounted for 14%, 38% and 39%, respectively of our consolidated revenues (before the effects of hedging) in 2009. We believe that the loss of BP, Shell or Chevron would not have a material adverse effect on us because alternative purchasers are readily available.

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, 2009, we had 29 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 good. From time to time, we utilize the services of independent contractors to perform various field and other services.

Regulatory Matters

Regulation of Oil and Gas Production, Sales and Transportation

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.

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.

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

We routinely obtain permits for our facilities and operations in accordance with these 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 these 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 it 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.

Climate Change Legislation and Greenhouse Gas Regulation

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” or “GHGs” pursuant to the United Nations Framework Convention on Climate Change, and the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are considered “greenhouse gases” regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of greenhouse gases. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for our products. Additionally, the United States Supreme Court has ruled, in Massachusetts, et al. v. EPA, that the EPA abused its discretion under the Clean Air Act by refusing to regulate carbon dioxide emissions from mobile sources. As a result of the Supreme Court decision and the change in presidential administrations, on December 7, 2009, the EPA issued a finding that serves as the foundation under the Clean Air Act to issue other rules that would result in federal greenhouse gas regulations and emissions limits under the Clean Air Act, even without Congressional action. As part of this array of new regulations, on September 22, 2009, the EPA also issued a GHG monitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to the EPA. The emissions will be published on a register to be made available on the Internet. These regulations may apply to our operations. The EPA has proposed two other rules that would regulate GHGs, one of which would regulate GHGs from stationary sources, and may affect sources in the oil and natural gas exploration and production industry and the pipeline industry. The EPA’s finding, the greenhouse gas reporting rule, and the proposed rules to regulate the emissions of greenhouse gases would result in federal regulation of carbon dioxide emissions and other greenhouse gases, and may affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to our industry.

On June 26, 2009, the United States House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. On November 5, 2009 the Senate Committee on Environment and Public Works approved the “Clean Energy Jobs and American Power Act of 2009,” authored by John Kerry and Barbara Boxer, that is similar in many ways to ACESA. One of the purposes of these bills is to control and reduce emissions of greenhouse gases in the United States. These bills would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% to 20% (from 2005 levels) by 2020, and by over 80% by 2050. Under these bills, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet the overall emission reduction goals of the bills. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of these bills would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. President Obama has indicated that he is in support of the adoption of legislation such as the two bills discussed above, and the White House is expending significant efforts to push for the legislation.

Two recent court decisions, one before the United States Second Circuit Court of Appeals and one before the United States Fifth Circuit Court of Appeals (The Fifth Circuit) have allowed cases to proceed. In the first case, Connecticut v. American Electric Power, the Second Circuit ruled that several states and other plaintiffs could continue a suit to impose GHG reductions on several utility defendants, concluding that a political question and standing objections of the defendants did not prohibit the suit from going forward. The Fifth Circuit, in Comer v. Murphy Oil, ruled that plaintiffs could similarly pursue a damage suit and the political question did not prohibit the suit. This case involves claims by plaintiffs who suffered damages from Hurricane Katrina that are seeking to recover damages from certain GHG emitters asserting their emissions contributed to their increased damages. In another case filed in the Texas District Court in Austin on October 6, 2009, a citizens group sued the Texas Commission on Environmental Quality (TCEQ) asserting that the agency was required to regulate carbon dioxide emissions from parties applying for permits under the Texas Clean Air Act. The result of this lawsuit could impose additional regulations on oil and gas operations in Texas, if the Texas courts require the TCEQ to regulate carbon dioxide and perhaps other GHGs such as methane. We may be subject to the EPA GHG monitoring and reporting rule, and potentially new EPA permitting rules if adopted to apply GHG permitting obligations and emissions limitations under the federal Clean Air Act. Even if no federal greenhouse gas regulations are enacted, or if the EPA issues regulations, more than one-third of the states have begun taking action on their own to control and/or reduce emissions of greenhouse gases. Several multi-state programs have been developed or are in the process of being developed: the Regional Greenhouse Gas Initiative involving 10 Northeastern states, the Western Climate Initiative involving seven western states, and the Midwestern Greenhouse Gas Reduction Accord involving seven states. The latter two programs have several other states acting as observers and they may join one of the programs at a later date. Any of the climate change regulatory and legislative initiatives described above could have a material adverse effect on our business, financial condition, and results of operations.

Web Site Access to Reports

Our Web site address is www.saratogaresources.net. 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.

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.

Our pending bankruptcy raise questions as to our ability to continue as a going concern and may limit our ability to borrow additional funds or capitalize on acquisition or other business opportunities and preserve the value of our equity.

On March 31, 2009, we, and our principal subsidiaries, filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Our bankruptcy filing was made after unsuccessful efforts to resolve certain alleged financial covenant defaults asserted by our second lien secured creditor and in the wake of Hurricanes Ike and Gustav and sharp declines in the price of oil and natural gas which, together, resulted in our revenues and net income being below that originally projected at the time of our acquisition of the Harvest Companies.

At December 31, 2009, and as of this filing, we continued to operate as debtors-in-possession in the Chapter 11 case. While we currently have pending our Modified Third Amended Plan of Reorganization that provides, among other things, for the preservation of our existing equity and a payment of certain amounts presently owing to creditors, there is no assurance that our plan of reorganization will ultimately be confirmed and become effective, nor is there any assurance that the ultimate terms of our exit from bankruptcy will preserve the rights of our existing equity holders in whole or at all. Accordingly, our equity holders continue to be subject to a risk that we will not be able to successfully emerge from bankruptcy or that rights of the equity holders will be diminished substantially or eliminated entirely.

Our leverage and debt service obligations may adversely affect our cash flow and our ability to find and develop reserves.

We incurred substantial indebtedness in acquiring our properties. At December 31, 2009, our indebtedness under our revolving credit facility and term loan totaled $131.3 million, including $117.7 million of principal and accrued interest owing under our term loan with Wayzata which bears interest at 20% per annum and $13.6 million owing under our Revolving Credit Agreement.

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, along with our operation under the oversight of the bankruptcy court, could have important consequences. For example, they could:

•

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

•

result in higher interest expense in the event of increases in interest rates since some of our debt is at 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;

•

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

•

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

Further, while the Modified Third Amended Plan of Reorganization reflects our agreement in principal with Wayzata regarding the restructuring of the existing Revolving Credit Agreement and Wayzata Credit Agreement, the restructured debt facilities provided for thereunder each mature April 30, 2012. Accordingly, even if we are successful in our efforts to reorganize under Chapter 11 and preserve the interests of our equity holders, as contemplated by the Modified Third Amended Plan of Reorganization, we believe that we will be effectively required to seek alternative financing to support our drilling program and operations and to take out the indebtedness owed to Wayzata on or prior to the maturity date thereof.

If we are unable to obtain financing on satisfactory terms, we may be unable to support our existing operations and development program during the pendency of the Chapter 11 case or following exit from bankruptcy. Further, if we are unable to successfully restructure or refinance our debt in the Chapter 11 case, we may be required to liquidate some or all of our properties. In either of such events, we and our shareholders could suffer substantial impairment in the value of our holdings, including the potential complete loss of such holdings. There is no assurance that we will be able to secure financing on acceptable terms, or at all, that we will be able to restructure or refinance our existing debt on acceptable terms, or at all, or that we will be able to successfully operate during the pendency of the Chapter 11 case or following the Chapter 11 case, any of which could result in a total loss to our company and our shareholders.

Because we have a limited history operating our existing properties, you may not be able to evaluate our current and future business prospects accurately.

We acquired our principal properties in July 2008 and, since March 31, 2009, have operated on a curtailed basis as debtors-in-possession. Accordingly, we have a limited operating and financial history upon which you can base an evaluation of our current and future business. The results of exploration, development, production and operation of our properties may differ from that of prior owners.

We may not be able to generate sufficient cash flow to meet our debt service and other obligations due to events beyond our control.

Our ability to generate cash flow from operations and to make scheduled payments on our indebtedness will depend on our future financial performance. Our future performance will be affected by a range of economic, competitive, legislative, operating and other business factors, many of which we cannot control, such as general economic and financial conditions in our industry or the economy at large. Those factors, particularly the sharp decline in the global economy and the accompanying drop in oil and natural gas prices, resulted in certain alleged covenant defaults under our credit facilities with Macquarie and Wayzata and the eventual action on our part to seek protection under Chapter 11.

Even if we are successful in emerging from bankruptcy, we will remain subject to the same risks as lead to our prior alleged covenant defaults and bankruptcy. A significant reduction in operating cash flow resulting from changes in economic conditions, increased competition, or other events could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations and prospects and our ability to service our debt and other obligations. If we are unable to service our indebtedness, we will be forced to adopt an alternative strategy that may include actions such as reducing or delaying acquisitions and capital expenditures, selling assets, restructuring or further refinancing our indebtedness or seeking equity capital. We cannot assure you that any of these alternative strategies could be effected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments on our indebtedness. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Saratoga Resources, Inc.—Liquidity and Capital Resources.”

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

Pursuant to our business plan, we expect to make substantial capital expenditures for the acquisition, development, production, exploration and abandonment of oil and gas properties. Our capital requirements will depend on numerous factors, and we cannot accurately predict the timing and amount of our capital requirements. We intend to primarily finance our capital expenditures through cash flow from operations, cash on hand and available credit under our revolving credit agreement. However, if our capital requirements vary materially from those reflected in our projections, we may require additional financing. A decrease in expected revenues or adverse change in market conditions could make obtaining this financing economically unattractive or impossible. 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. As a result, we may lack the capital necessary to complete potential acquisitions or to capitalize on other business opportunities.

We have been, and may continue to be, adversely affected by general economic conditions

The disruption experienced in U.S. and global credit markets during second half of 2008 and subsequent global economic downturn has resulted in projected decreases in demand for oil and natural gas, resulting in a sharp drop in energy prices, and has affected the availability and cost of capital. Prolonged negative changes in domestic and global economic conditions or disruptions of the financial and credit markets may have a material adverse effect on our results of operations, financial condition and liquidity. At this time, it is unclear whether and to what extent the actions taken by the U.S. government to date and other measures being implemented or contemplated, will mitigate the effects of the crisis. From an operating standpoint, the current crisis has resulted in a steep decline in the price we receive for oil and natural gas and reduced revenues and profitability. Our reduced profitability arising from the global economic disruption was a principal factor, along with the effects of hurricanes, in the alleged non-compliance with various financial covenants in our existing debt facilities and our 2009 filing for protection under the Chapter 11. While commodity prices have recovered a portion of the decline experience in late 2008 and early 2009, should the U.S. and global economies experience further weakness, our financial position may deteriorate along with our ability to operate profitably and our ability to obtain financing to support operations and the cost and terms of same, is unclear.

Risks Associated with Acquisitions and Our Risk Management Program

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

We acquired our principal properties in July 2008 and our business plan includes pursuit of additional acquisitions of oil and natural gas properties in the future. Integration of the operations of the properties we acquire with our existing business will be 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:

•

operating a larger organization;

•

coordinating potentially geographically disparate organizations, systems and facilities;

•

integrating corporate, technological and administrative functions;

•

diverting management’s attention from other business concerns;

•

an increase in our indebtedness; and

•

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.

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

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

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 acquisitions.

Compared to some other participants in the oil and gas industry, we are a relatively small company with modest resources. Therefore, there is the possibility that we may 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. 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. If we fail to 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.

Following the acquisition by Wayzata of all rights under our Revolving Credit Agreement, in February 2010, all of our existing hedges were unwound resulting in our current position of being totally unhedged and, therefore, subject to commodity price risk. Assuming the Modified Third Amended Plan of Reorganization becomes effective, the Amended Revolving Credit Agreement that will also become effective limits our hedging, without consent of Wayzata, to 60% of production.

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.

Risks Related to the Oil and Gas Business

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

Our future revenues, profitability and cash flow will depend substantially upon the prices and demand for oil and natural gas. The markets for these commodities are volatile and even relatively modest drops in prices can affect our financial results and impede our growth. 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:

•

domestic and foreign supplies of oil and natural gas;

•

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

•

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

•

level of consumer product demand;

•

level of global oil and natural gas exploration and productivity;

•

domestic and foreign governmental regulations;

•

level of global oil and natural gas inventories;

•

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;

•

weather conditions;

•

technological advances affecting oil and natural gas consumption;

•

overall U.S. and global economic conditions; and

•

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 substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.

To attempt to reduce our price risk, we have periodically entered into hedging transactions with respect to a portion of our expected future production and intend to enter into such transactions in the future. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices or that counterparties to hedging transactions will be able to meet their requirements in those hedging transactions. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition and results of operations.

Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in the reserve estimates or underlying assumptions of our properties will materially affect the quantities and present value of those 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 herein. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses 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.

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

Our future crude oil and natural gas production will depend on our success in finding or acquiring additional reserves. If we are unable to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. 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 oil and gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to acquire additional reserves.

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 we. 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. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

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 typically fluctuates based on demand for those services. While we have historically had excellent relationships with oil field service companies, our Chapter 11 filing may strain our relationships with certain oil field service companies and 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.

The geographic concentration of our properties subjects us to an increased risk of loss of revenue or curtailment of production from factors affecting the Louisiana Gulf Coast specifically.

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

•

severe weather;

•

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

•

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

•

changes in the regulatory environment.

For example, the oil and gas properties that we acquired in July 2008 were damaged by Hurricanes Katrina, Rita, Gustav and Ike, which required the prior owners of the properties, in the case of Hurricanes Katrina and Rita, and us, in the case of Hurricanes Gustav and Ike, to spend a considerable amount of time and capital on inspections, repairs, debris removal, and the drilling of replacement wells. Although we maintain insurance coverage to cover a portion of these types of risks, there may be potential risks associated with our operations not covered by insurance. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss.

Because all or a number of the properties could experience any 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.

Drilling for natural gas and oil is a speculative activity any involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

We engage in exploration and development drilling activities. Any such 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 Gulf of Mexico), cost overruns, equipment shortages and mechanical difficulties. Therefore, the successful drilling of a gas or oil 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 inherent operating risks, including:

•

fires;

•

explosions;

•

blow-outs and surface cratering;

•

uncontrollable flows of gas, oil and formation water;

•

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

•

pipe, cement, subsea well or pipeline failures;

•

casing collapses;

•

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

•

abnormally pressured formations; and

•

environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges 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:

•

injury or loss of life;

•

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

•

pollution and other environmental damage;

•

clean-up responsibilities;

•

regulatory investigations and penalties;

•

suspension of our operations; and

•

repairs to resume operations.

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.

The properties we acquire may not produce as expected, may be in an unexpected condition and we may be subject to increased costs and liabilities, including environmental liabilities. Although we will review properties prior to acquisition in a manner consistent with industry practices, such reviews are not capable of identifying all potential conditions. Generally, it is not feasible to review in depth every individual property involved in each acquisition. We focus our review efforts on the higher-value properties or properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit a buyer to become sufficiently familiar with the properties to fully assess their condition, any deficiencies, and development potential. Inspections may not be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

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

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, the availability of a ready market depends on the proximity of and our ability to tie into existing production platforms that we own or operate or that are owned and operated by others and, where facilities are owned and operated by others, 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. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and gas and realization of revenues.

We may not be the operator on all of our future properties and therefore may not be 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 all of our properties. However, it is possible that we will not serve as operator of all of the properties we may acquire in the future. 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:

•

the timing and amount of capital expenditures;

•

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

•

the operator’s expertise and financial resources;

•

approval of other participants in drilling wells;

•

selection of technology; and

•

the rate of production of the reserves.

Our insurance may not protect us against all business and operating risks.

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. As a result of 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. As a result, we procure other desirable insurance on commercially reasonable terms, if possible. Although we will maintain insurance at levels we believe is appropriate and consistent with industry practice, we will not be 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. As a result of a number of recent catastrophic events like the terrorist attacks on September 11, 2001 and Hurricanes Ivan, Katrina and Rita, 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 extensive damage from Hurricanes Ivan, Katrina and Rita. As a result, insurance costs 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 as it was in 2005, insurance underwriters may no longer insure Gulf of Mexico assets against weather-related damage. A number of industry participants have previously maintained business interruption insurance. This insurance may not be economically available in the future, which could adversely impact business prospects in the Gulf of Mexico 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 customer, 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.

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

Crude oil and natural gas exploration and production operations in the United States and the Gulf of Mexico are subject to extensive federal, state and local laws and regulations. Companies operating in the Gulf of Mexico are subject to laws and regulations addressing, among others, land use and lease permit restrictions, bonding and other financial assurance related to drilling and production activities, spacing of wells, unitization and pooling of properties, environmental and safety matters, plugging and abandonment of wells and associated infrastructure after production has ceased, operational reporting and taxation. Failure to comply with such laws and regulations can subject us to governmental sanctions, such as fines and penalties, as well as potential liability for personal injuries and property and natural resources damages. We may be required to make significant expenditures to comply with the requirements of these laws and regulations, and future laws or regulations, or any adverse change in the interpretation of existing laws and regulations, could increase such compliance costs. Regulatory requirements and restrictions could also delay or curtail our operations and could have a significant impact on our financial condition or results of operations.

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.

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 you 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.

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.

Under certain environmental laws that impose strict, joint and several liability, we may be required to remediate our contaminated properties regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were or were not in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations. Moreover, new or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. Therefore, the costs to comply with environmental, health or safety laws or regulations or the liabilities incurred in connection with them could significantly and adversely affect our business, financial condition or results of operations. In addition, many countries as well as several states and regions of the U.S. have agreed to regulate emissions of “greenhouse gases.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning of natural gas and oil, are greenhouse gases. Regulation of greenhouse gases could adversely impact some of our operations and demand for some of our services or products in the future. See “Business — Regulatory Matters.”

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Legislation has been proposed in Congress to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process may be adversely impacting drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process are impairing groundwater or causing other damage. These bills, if adopted, could establish an additional level of regulation at the federal or state level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Certain states have adopted or are considering similar disclosure legislation.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC's expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Other Risks

We depend on key personnel, the loss of any of whom could materially adversely affect future operations.

Our success will depend to a large extent upon the efforts and abilities of our executive officers and key operations personnel. The loss of the services of one or more of these key employees could have a material adverse effect on us. Our business will also be dependent upon our ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause us to incur greater costs, or prevent us from pursuing our exploitation strategy as quickly as we would otherwise wish to do.

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 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.

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 substantial expenditures and may create a risk of expensive delays or loss of value if a project is unable to function as planned due to changing requirements or local opposition.

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

We may from time to time be a party to lawsuits incidental to our business. As of December 31, 2009, 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.

As of December 31, 2009, we continued to operate as debtors-in-possession under the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Western District of Louisiana, Lafayette Division. See “Item 1. Business – Chapter 11 Reorganization.”

Item 4.

(Removed and Reserved)

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 OTC Bulletin Board under the symbol “SROEQ.OB.” Prior to our March 31, 2009 filing for protection under Chapter 11, our common stock traded under the symbol “SROE.OB.” 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.


		High		Low
Calendar Year 2009	Fourth Quarter	$	3.75	$	0.51
	Third Quarter		2.01		0.21
	Second Quarter		0.60		0.10
	First Quarter		2.25		0.30

Calendar Year 2008	Fourth Quarter	$	3.75	$	1.50
	Third Quarter		4.00		0.75
	Second Quarter		0.95		0.17
	First Quarter		4.00		0.25

At March 26, 2010, the closing price of our common stock on the OTC Bulletin Board was $1.30.

As of March 30, 2010, there were approximately 1,342 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. Pursuant to our Modified Third Amended Plan of Reorganization, if ultimately adopted, we will be further subject to the requirement, as imposed pursuant to our plan of reorganization, that no dividends or distributions be made with respect to our equity holdings unless and until the holders of all allowed claims have been paid in full in cash in accordance with the plan. 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, 2009 with respect to the shares of our common stock that may be issued under our existing equity compensation plans.


Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)		Weighted-average exercise price of outstanding options, warrants and rights (b)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities effected in column (a))
Equity compensation plans approved by security holders ⁽¹⁾	―		―	3,000,000
Equity compensation plans not approved by security holders ⁽²⁾	75,000	⁽³⁾	0.36	1,430,000
Total	75,000		0.36	4,430,000

(1)

Consists of 3,000,000 shares reserved for issuance under the Saratoga Resources, Inc. 2008 Long-Term Incentive Plan (the “2008 Plan”)

(2)

Consists of 1,430,000 shares reserved for issuance under the Saratoga Resources, Inc. 2006 Employee and Consultant Stock Plan (the “2006 Plan”).

(3)

Consists of non-plan stand alone stock option grants to directors.

2006 Employee and Consultant Stock Plan. The 2006 Employee and Consultant Stock Plan was adopted by our board of directors in January 2006 as an equity-based plan to provide incentives to, and to attract, motivate and retain employees and consultants.

The 2006 Plan is administered by the Compensation Committee of our board of directors and enables the committee to make stock grants. We initially reserved 1,200,000 shares of common stock for issuance under the 2006 Plan. In October 2007, the 2006 Plan was amended to increase the shares reserved thereunder to 2,525,000.

2008 Long-Term Incentive Plan. The 2008 Long-term Incentive Plan was adopted by our board of directors in October 2008 as an equity-based compensation plan to provide incentives to, and to attract, motivate and retain the highest qualified employees, non-employee directors and other third-party service providers. The 2008 Plan enables our Board of Directors to provide equity-based incentives through awards of options, stock appreciation rights, restricted stock, restricted stock units and other stock or performance-based awards.

Under the 2008 Plan, awards may be granted from time to time to eligible persons, consisting generally of officers, directors, employees and consultants, all generally in the discretion of the Compensation Committee of the board of directors, which is responsible for administering the 2008 Plan. We have initially reserved 3,000,000 shares of common stock for issuance under the 2008 Plan, subject to adjustment to protect against dilution in the event of certain changes in our capitalization. Shareholders holding greater than 50% of our common stock approved the 2008 Plan by written consent. We have not made any grants as yet under the 2008 Plan and do not intend to make any grants under that plan unless and until we distribute an Information Statement relating to the approval of that plan or resubmit the plan for approval at a shareholders meeting.

Item 6.

Selected Financial Data

Not applicable.

Item 7.

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

General

Saratoga Resources, Inc. is an independent oil and natural gas company engaged in the production, development, acquisition and exploitation of natural gas and crude oil properties. Our principal properties were acquired in July 2008 and cover an estimated 37,000 gross acres (33,750 net), substantially all of which are held by production without near-term lease expirations, across 11 fields in the state waters of Louisiana. See “Harvest Acquisitions” below. Prior to the July 2008 acquisition of our Louisiana properties, our operations were focused on production, development, acquisition and exploitation of various mineral interests in the State of Texas.

Since March 31, 2009, we have operated as debtors-in-possession under Chapter 11 of the U.S. Bankruptcy Code. See “Chapter 11 Reorganization” below.

At December 31, 2009, our principal properties covered approximately 37,000 gross acres (33,750 net), substantially all of which were held by production without near-term lease expirations, across 13 fields in the state waters of Louisiana. We own working interests in our properties ranging from 25% to 100%, with our average working interest on a net acreage leasehold basis being approximately 94%. Our net revenue interests in our properties range from 18% to 82%, with our average net revenue interest on a net acreage leasehold basis being approximately 94%. We operate over 90% of the wells that comprise our PV-10, enabling us to more effectively manage our operating costs, capital expenditures and the timing and method of development of our properties. Following the Harvest Acquisitions and prior to the market disruption that occurred during the fourth quarter of 2008, we began an active development program to exploit these opportunities. Our development program was substantially curtailed during 2009 as a result of the economic climate, lack of access to borrowing capacity under our revolving credit facility and our Chapter 11 filing. Most of our properties offer multiple stacked reservoir objectives with substantial behind pipe potential. We have identified multiple prospects on our acreage and, subject to our exit from bankruptcy and establishment of new credit facilities, we intend to renew our development program to exploit these opportunities. We believe this development program will enable us to significantly grow our reserves, production and cash flow. There is no assurance, however, that we will successfully exit bankruptcy or that we will be able to secure new credit facilities on acceptable terms, or at all.

As of December 31, 2009, based on reserve estimates prepared by independent petroleum engineers, we had 107.7 Bcfe of proved reserves, of which 58% were natural gas and 12% were proved developed. The PV-l0 of these proved reserves as of that date were $224.0 million before income taxes, or $145.6 million after future income taxes. Additionally, at December 31, 2009, we had probable reserves of 68.2 Bcfe, consisting of 45.3 Bcf of natural gas and 3.8 MMBls of oil, and possible reserves of 181.5 Bcfe, consisting of 101.1 Bcf of natural gas and 13.4 MMBls of oil. Our average daily net production for December 2009 was 14.4 MMcfe/d, of which 67% was oil.

Harvest Acquisitions

In July 2008, we acquired all of the membership interest in Harvest Oil & Gas, LLC (“Harvest Oil”) and The Harvest Group, LLC (“Harvest Group” and, together with Harvest Oil, the “Harvest Companies” or the “Predecessor Companies”).

Recent Developments

Chapter 11 Reorganization

Wayzata issued a notice of default, dated February 26, 2009, wherein it alleged nine non-monetary breaches of the Wayzata Credit Agreement, or events of default. Wayzata, in its notice of default, did not exercise any of its rights under the Wayzata Credit Agreement, but expressly reserved the right to do so. We disputed Wayzata’s notice of default as premature and based on incomplete data and failure to take into account various developments and circumstances.

Macquarie also issued a notice of default dated February 26, 2009, which was expressly based on Wayzata’s Notice of Default. The Macquarie notice of default was triggered by cross default provisions in the Revolving Credit Agreement defining an event of default as an event or condition occurring which permits the holder of any material debt to accelerate that obligation. Macquarie stated in its notice of default that it was not initiating any action to exercise its rights and remedies available, though it’s right to do so were expressly reserved. As a result of the Macquarie notice of default, Macquarie rejected our requests to access additional credit available under the Revolving Credit Agreement, which restriction of credit potentially impaired our ability to continue our development program. We disputed the Macquarie notice of default.

Confirmation hearings with respect to the Modified Third Amended Plan are scheduled for the week of April 19, 2010.

Mineral Royalty Audit

In October 2009, the Louisiana Department of Mineral Resources notified Saratoga of the completion of audits of royalty payments from Harvest Oil and Harvest Group for the period from September 2005 to March 2009. Pursuant to the notifications, the Department of Mineral Resources asserted deficiencies in royalty payments totaling $1,368,194. Additionally, the Department of Mineral Resources estimated interest and penalties owing of approximately $799,549. Saratoga is reviewing the asserted royalty deficiencies and, based on its review, may contest the asserted deficiencies. Saratoga also intends to review potential claims against the former owners of Harvest Oil and Harvest Group arising from underpayments determined to have occurred during periods prior to Saratoga’s acquisition of the Harvest Companies.

The full amount of the asserted deficiency in royalty payments is included in lease operating expense for 2009 and the estimated interest and penalties are included in interest expense. At December 31, 2009, Saratoga recorded as liabilities subject to compromise $2,167,743 attributable to the asserted deficiencies in royalties.

Drilling and Development Activities

During 2008, we began implementation of a plan to further develop the assets acquired in the Harvest Acquisition. During 2008, we successfully recompleted three wells, completed a workover on one well and successfully drilled a developmental well in the Grand Bay Field which was awaiting completion at December 31, 2008. We had no dry holes during 2008.

During 2009, the developmental well drilled during 2008 was completed and we recompleted five wells. As a result of the macro-economic environment, lack of access to borrowing capacity under our Revolver Facility and operation under Chapter 11 protection, we conducted no additional drilling and development activities during 2009. At December 31, 2009, no wells were being drilled.

In addition to the recompletion, workover and developmental drilling work undertaken during 2008, we engaged two geological and engineering firms to perform full field studies in the Grand Bay and Vermilion 16 fields in order to maximize our potential recoveries from those fields. The Vermilion 16 study was completed during 2009 and the Grand Bay study was ongoing at December 31, 2009 and is expected to be completed in May 2010.

At and for the years ended December 31, 2008 and 2009, we had approximately 81 wells and 86 wells, respectively, in production.

Stock and Option Grants

In April 2008, in connection with financial consulting services rendered to the Company, and pursuant to the terms of a Stock Agreement, 500,000 shares of stock were issued. One half, or 250,000, of the shares were subject to forfeiture unless the consultant provided an average of at least ten (10) hours of services per week through July 1, 2008. These shares were valued at $0.40 per share at the date of grant and became vested as of July 1, 2008. An additional 250,000 of the shares were subject to forfeiture unless the consultant provided an average of at least ten (10) hours of services per week through January 1, 2009. The shares for services to be rendered through January 1, 2009 were forfeited on July 1, 2008 when the consulting contract was cancelled. We recorded $100,000 in stock-based compensation which was included as acquisition costs relating to the Harvest Acquisitions.

In May 2008, we issued 30,000 shares of common stock to a director as compensation for services. These shares were valued at $0.25 per share at the date of grant and vested immediately on grant date. The stock-based compensation expense recorded at grant date was $7,500.

In connection with the Harvest Acquisitions, in July 2008, we entered into an employment agreement and restricted stock agreement with the former President of the Harvest Companies in order to retain his services to facilitate the orderly transition of operations following the Harvest Acquisitions. Under the terms of the employment agreement, we agreed to pay a base salary of $165,000 per year plus participation in our executive benefit programs. Under the terms of a restricted stock agreement, we agreed to issue 500,000 shares of common stock, of which 200,000 shares were subject to forfeiture in the event service as President of the Harvest Companies terminated prior to January 14, 2009 and 200,000 shares were subject to forfeiture in the event service as President of the Harvest Companies terminated prior to July 14, 2009. In February 2009, by mutual agreement, services of the President of the Harvest Companies terminated and the 200,000 unvested shares of restricted stock were cancelled. We recorded stock-based compensation relating to those shares of $892,500 in 2008 and $0 in 2009.

Also in connection with the Harvest Acquisition, in July 2008, we issued 540,000 shares of restricted common stock at $2.55 per share to eight other employees of the Harvest Companies as an inducement for their continuing services following the Harvest Acquisitions. The shares vest 20% in September 2008, 40% in July 2009 and 40% in July 2010. 108,000 shares were vested at December 31, 2008 and 120,000 shares were vested at December 31, 2009. The stock-based compensation recorded in connection with the stock grants was $619,650 in 2008 and $571,000 in 2009. The unamortized stock-based compensation at December 31, 2009 was $71,400 and will be recorded over the requisite service period.

In November 2008, we issued 10,000 shares of common stock at $2.55 per share to a director as consideration for his services as chairmen of the Audit Committee during the second and third quarters of 2008. The stock-based compensation expense recorded at grant date was $22,500.

During 2009, stock options to purchase 75,000 shares of common stock, with a grant-date value of $13,386, were granted to directors. The options are exercisable at $0.36 per share for a term of ten years. The options fully vested immediately. The options were valued using the Black-Sholes model with the following assumptions: $0.36 quoted stock price; $0.36 exercise price; 341% volatility; 5 year estimated life; zero dividends; 1.92% discount rate.

During 2009, we issued 10,000 shares of common stock for services of a director and 2,500 shares of common stock to a consultant for services. The grant-date value of these shares was approximately $3,600.

During 2009, a warrant to purchase 5,000 shares of common stock, with a grant date value of $2,525, was granted to a consultant for services. The warrant is exercisable at $1.50 per share for a term of five years.

Hurricanes Gustav and Ike.

In September 2008, Hurricanes Gustav and Ike resulted in interruptions in production from, and damage to, our south Louisiana fields. Electrical outages, road and waterway closures and similar disruption of critical third-party services resulted in a temporary decline in product sales estimated at 19.4 MBbls of oil and 113.1 MMcf of natural gas during August and September 2008 resulting in a reduction in revenues estimated at $3,098,600.

Inspections to date have revealed damage to our facilities with damage assessments to date estimated at approximately $1,700,000. The Company carries property damage insurance on its south Louisiana operations in the amount of $10,000,000 subject to a deductible of $1,000,000 per event. A claim has been submitted to our insurance carrier with respect to damages arising from the hurricanes and is presently pending. The total impact to the Company arising from the hurricane damage will not be known until the actual cost of the damage is finalized and action on the claim is taken by our insurance carrier.

Elimination of Hedges

In connection with its acquisition of the interests of Macquarie under the Revolving Credit Agreement, in February 2010, Wayzata liquidated all of our existing hedge contracts and applied the proceeds thereof to amounts owed to Wayzata. As a result of Wayzata’s actions, our production is currently unhedged and we are not in compliance with the hedging requirements of the Revolving Credit Agreement.

Revolving Credit Facility

In conjunction with the Harvest Acquisitions, on July 14, 2008, we entered into the Revolving Credit Agreement pursuant to which we assumed and restated the existing Macquarie credit facilities of the Harvest Companies and Macquarie, or other lenders (together, the “Revolving Credit Lenders”), agreed to provide a revolving credit loan facility in an amount up to $25,000,000. Simultaneous with execution of the Revolving Credit Agreement, we borrowed $12,528,878 under the revolving credit facilities to pay amounts due with respect to the acquisition of the Harvest Companies and related transaction costs. Additionally, letters of credit of the Harvest Companies, totaling $9.7 million, remained outstanding following the acquisition and reduce available borrowing under the revolving credit facility.

Pursuant to the terms of the Revolving Credit Agreement, we granted to the Revolving Credit Lenders a first lien on substantially all of our assets, and each of our subsidiaries, including the Harvest Companies, agreed to guaranty all amounts owing under the Revolving Credit Agreement.

Loans made under the Revolving Credit Agreement are subject to borrowing base requirements and bear interest at varying rates based on percentage usage of the borrowing base and margins ranging from 2.25% to 2.75% over the applicable LIBOR Rate, as defined in the Revolving Credit Agreement, and 0.75% to 1.25% over the applicable prime rate. Interest on the revolving credit facility is due monthly with respect to prime rate based loans and at the end of each applicable interest period with respect to Eurodollar loans. Loans under the Revolving Credit Agreement mature on April 1, 2011.

Pursuant to the terms of the Revolving Credit Agreement, we will pay certain administrative fees, letter of credit fees and other fees and expenses in connection with maintenance and advances under the Revolving Credit Agreement.

The Revolving Credit Agreement includes normal covenants and credit conditions and is subject to the terms of the Intercreditor Agreement with us and the Wayzata Lenders.

As a result of the alleged defaults asserted in February 2009 and the subsequent bankruptcy filing, we have had no access to additional borrowing under the Revolving Credit Agreement since early 2009. As of December 31, 2009, the total amount owing under the Revolving Credit Agreement was $13.6 million, consisting of $12.5 million in principal and approximately $500 thousand in accrued interest.

In February 2010, Wayzata acquired all of Macquarie’s interest in the Revolving Credit Agreement.

Under the terms of our Modified Third Amended Plan, if and when the same becomes effective, claims arising under the Revolving Credit Agreement, including costs and accrued interest through the Effective Date, will be treated as allowed claims in the amount of $23.5 million (subject to adjustment for accrued interest if the Effective Date is after May 15, 2010), of which we will pay $5.5 million on the Effective Date. Under the Amended Revolving Credit Agreement, the maturity date will be April 30, 2012 and the applicable interest rate will be adjusted to the alternate base rate plus 2% with the balance owing under the Amended Revolving Credit Agreement being payable interest only on a monthly basis with the balance owed being payable in full at maturity.

Wayzata Credit Agreement

In conjunction with the Harvest Acquisitions, on July 14, 2008, we entered into the Wayzata Credit Agreement pursuant to which Wayzata, or other lenders (together, the “Wayzata Lenders”), agreed to provide loans to us in an amount up to, and did loan to us, $97,500,000 to be used to fund the acquisition of the Harvest Companies.

Pursuant to the terms of the Wayzata Credit Agreement, we granted to the Wayzata Lenders a second lien on substantially all of our assets, and each of our subsidiaries, including the Harvest Companies, agreed to guaranty all amounts owing under the Wayzata Credit Agreement.

Loans made under the Wayzata Credit Agreement bear interest at 20% per annum and are due and payable in monthly installments of interest only with the principal being due and payable in full on July 14, 2011.

Pursuant to the terms of the Wayzata Credit Agreement, we issued to the Wayzata Lenders a warrant to purchase 805,515 shares of our common stock exercisable for a period of five years at a price of $0.01 per share.

The Wayzata Credit Agreement includes financial and other covenants and credit conditions and was originally subject to the terms of an Intercreditor Agreement with us and Macquarie.

At December 31, 2009, the total amount owing under the Wayzata Credit Agreement was $117.7 million, consisting of $97.5 million in principal and $20.2 million in accrued interest.

Under the terms of our Modified Third Amended Plan, if and when the same becomes effective, claims arising under the Wayzata Credit Agreement, including costs and accrued interest through the Effective Date, will be treated as allowed claims in the amount of $127.5 million (subject to adjustment for accrued interest if the Effective Date is after May 15, 2010). Under the Amended Wayzata Credit Agreement, the maturity date will be April 30, 2012 and the interest rate will be adjusted to 11.25% per annum and amounts payable thereunder will be payable interest only on a monthly basis with the balance owed being payable in full at maturity.

Management Notes

In conjunction with the Harvest Acquisitions and the related financing, at closing, we repaid $100,000 of advances from Thomas Cooke, our Chairman, Chief Executive Officer and principal shareholder. The balance owing to Mr. Cooke, totaling $463,412, plus accrued salary in the amount of $157,500, was renewed and extended pursuant to a Subordinated Promissory Note, providing for payment of equal monthly installments of $17,247, plus interest at 10% per annum, over three years.

Accrued salary in the amount of $157,500 owed to Andy Clifford, our President was renewed and extended pursuant to a Subordinated Promissory Note providing for payment of equal monthly installments of $4,375, plus interest at 10%, over three years.

As a result of our Chapter 11 filing, payments on the management notes ceased to be made as of the Petition Date.

At December 31, 2009, the amounts owed under the management notes totaled $605,416 in principal and $45,075 in accrued interest. Amounts owed to Thomas Cooke were $$482,916 in principal and $35,845 in accrued interest, and amounts owed to Andy Clifford were $122,500 in principal and $9,230 in accrued interest.

Under the terms of the Modified Third Amended Plan, if adopted, the amounts payable to our principal officers, Thomas Cooke and Andy Clifford, pursuant to existing management notes, would be payable 100% forty months following the Effective Date, with compound accrued interest and subject to prior satisfaction in full of all allowed claims.

Critical Accounting Policies

We prepare our consolidated and combined 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 prepare the estimates of our oil and gas reserves presented in this report based on guidelines promulgated under GAAP and in accordance with the rules and regulations of the Securities and Exchange Commission. The evaluation of our reserves by the independent reserve engineers 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. Effective for the year ending December 31, 2009 and later, commodity prices are based on the average prices as measure on the first day of each of the last twelve calendar months. In our 2009 year-end reserve report, we used an average Light Crude price of $61.18 per Bbl, and a Henry Hub price of $3.87 per MMbtu adjusted 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. Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 2.2 Bcfe.

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 entitlement method. Our net imbalance position at December 31, 2009, was immaterial.

Derivative Instruments

We account for our derivative activities under FASB ASC 815, Derivatives and Hedging. ASC 815 establishes accounting and reporting standards requiring that every derivative instrument be recorded on the balance sheet as either an asset or a liability measured at its fair value. The statement requires 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 do not designate any future price risk management activities as accounting hedges under ASC 815, and, accordingly, account for them using the mark-to-market accounting method. Under this method, the contracts are carried at their fair value on our consolidated and combined balance sheets under the captions “Derivative assets” and “Derivative liabilities.” Derivative assets and liabilities with the same counterparty and subject to contractual terms which provide for net settlement are reported on a net basis on our consolidated and combined balance sheets. We recognize all unrealized and realized gains and losses related to these contracts on our consolidated and combined statements of income under the caption “Commodity derivative income (expense).”

As of July 1, 2008, Saratoga adopted Financial Accounting Standards Board (FASB) Staff Position (FSP) FASB Interpretation (FIN) No. 39-1, "Amendment of FASB Interpretation No. 39 (ASC 210-20), which effectively amends FIN No. 39, "Offsetting of Amounts Related to Certain Contracts." ASC 210-20 permits the netting of fair values of derivative assets and liabilities for financial reporting purposes, if such assets and liabilities are with the same counterparty and subject to a master netting arrangement. Saratoga has elected to employ net presentation of derivative assets and liabilities when ASC 210-20 conditions are met. ASC 210-20 also requires that when derivative assets and liabilities are presented net, the fair value of the right to reclaim collateral assets (receivable) or the obligation to return cash collateral (payable) is also offset against the net fair value of the corresponding derivative. We routinely exercise our contractual right to net realized gains against realized losses when settling with swap and option counterparties.

As noted above, subsequent to December 31, 2009, Wayzata liquidated all of our then existing derivatives.

See Note 7, “Commodity Derivative Instruments”, for a more detailed discussion of our hedging activities.

Oil and Gas Exploration and Development

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

Property Acquisition Costs

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 to proved properties.

Exploratory Costs

Geological and geophysical 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-venturer 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.

Development Costs

Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.

Depletion and Amortization

Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved oil and gas reserves. Amortization of intangible development costs is based on the unit-of-production method using estimated proved developed oil and gas reserves

Depreciation of Other Property and Equipment

Furniture, fixtures, equipment, and other are depreciated using the straight-line method over the estimated useful lives of the assets. The estimated life of these assets range from three to five years.

Impairment of Properties, Plants and Equipment

Properties, plants and equipment used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions and reported as impairments in the periods in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for exploration and production assets, at an entire complex level for refining assets or at a site level for retail stores. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is determined based on the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell.

The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, prices and costs, considering all available evidence at the date of review. If the future production price risk has been hedged, the hedged price is used in the calculations for the period and quantities hedged. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation. The price and cost outlook assumptions used in impairment reviews differ from the assumptions used in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities. In that disclosure, Accounting Standards Codification 932-235, “Disclosures about Oil and Gas Producing Activities,” requires inclusion of only proved reserves and the use of prices and costs at the balance sheet date, with no projection for future changes in assumptions.

Asset Retirement Obligations and Environmental Costs

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. See Note 9 “Asset Retirement Obligations” for additional information.

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.

Stock Based Compensation

Share-based awards to employees are accounted for under Accounting Standards Codification 718 (ASC 718), “Share-Based Payment”. ASC 718 replaced SFAS No. 123 and supersedes APB Opinion No. 25. ASC 718 requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. The pro forma disclosures previously permitted under SFAS 123 are no longer an alternative to financial statement recognition. We adopted ASC 718 using the modified prospective method which requires the application of the accounting standard as of January 1, 2006. The consolidated and combined financial statements for the years ended December 31, 2009 and 2008 reflect the impact of ASC 718.

Income Taxes

Deferred income taxes are based on the difference between the financial reporting and tax basis of assets and liabilities. The deferred income tax provision represents the change during the reporting period in the deferred tax assets and deferred tax liabilities, net of the effect of acquisitions and dispositions. Deferred income tax assets include tax loss and credit carryforwards and are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion of all of the deferred tax assets will be not be realized. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. We establish reserves when, despite our belief that our tax return positions are fully supportable, we believe that certain positions may be challenged and potentially disallowed. When facts and circumstances change, we adjust these reserves through our provision for income taxes.

To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income tax expense in our Statement of Operations.

We adopted the provisions of ASC 740 (formerly known as “Financial Accounting Standards Board (FASB) Interpretation No. 48”), “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109,” (ASC 740) on January 1, 2007. The adoption did not result in a material adjustment to the Company’s tax liability for unrecognized income tax benefits. If applicable, we would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2009, we had not accrued interest or penalties related to uncertain tax positions. The tax years 2006-2009 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

In May 2007, the FASB issued ASC 740-10 (formerly known as “FSP No. FIN 48-1”), Definition of Settlement in FASB Interpretation No. 48, (ASC 740-10) which amends ASC 740 and provides guidance concerning how an entity should determine whether a tax position is “effectively,” rather than the previously required “ultimately,” settled for the purpose of recognizing previously unrecognized tax benefits. In addition, ASC 740-10 provides guidance on determining whether a tax position has been effectively settled. The guidance in ASC 740-10 is effective upon the initial January 1, 2007 adoption of ASC 740. Companies that have not applied this guidance must retroactively apply the provisions of this ASC to the date of the initial adoption of ASC 740. We have adopted ASC 740-10 and no retroactive adjustments were necessary.

Results of Operations

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Prior to the Harvest Acquisitions, we had minimal operations. Accordingly, the results of operations included in this Form 10-K for the period from January 1, 2008 to July 14, 2008, the date of the Harvest Acquisition, represent the combined operations of the Harvest Companies, as predecessor (the “Predecessor”). The consolidated results of operations for the period from July 15, 2008 to December 31, 2008 and for 2009 represent our consolidated results subsequent to the Harvest Acquisition, as successor (the “Successor”).

The following table sets forth the audited results of operations for 2009 and the combined results of operations for the year ended December 31, 2008, which includes the Successor Company for the period July 15, 2008 to December 31, 2008 and the Predecessor for the period January 1, 2008 to July 14, 2008.


	Successor		Successor		Predecessor		Combined
	For the Year Ended December 31, 2009		July 15, 2008 – December 31, 2008		January 1, 2008 – July 14, 2008		For the Year Ended December 31, 2008
Revenues:
Oil and gas revenues	$	47,391,292	$	22,423,746	$	46,475,559	$	68,899,305
Other revenues		1,478,219		1,419,707		1,116,318		2,536,025
Total revenues		48,869,511		23,843,453		47,591,877		71,435,330
Operating Expense:
Lease operating expense		19,872,914		10,666,669		17,356,190		28,022,859
Exploration expense		1,145,724		-		-		-
Depreciation, depletion and amortization		14,577,949		5,324,763		2,521,020		7,845,783
Accretion expense		1,439,437		534,168		837,094		1,371,262
General and administrative		6,063,497		3,865,046		3,992,925		7,857,971
Impairments		-		1,693,440		-		1,693,440
Taxes other than income		5,672,312		2,510,548		5,609,040		8,119,588
Total operating expenses		48,771,833		24,594,634		30,316,269		54,910,903
Operating income (loss)		97,678		(751,181)		17,275,608		16,524,427
Other income (expense):
Commodity derivative income (expense), net		(4,030,004)		39,133,737		(19,060,603)		20,073,134
Interest income		35,811		67,578		47,836		115,414
Interest expense		(27,517,956)		(10,350,918)		(4,971,970)		(15,322,888)
Total other income (expense)		(31,512,149)		28,850,397		(23,984,737)		4,865,660
Net income (loss) before reorganization expenses income taxes		(31,414,471)		28,099,216		(6,709,129)		21,390,087
Reorganization expenses		5,656,499		-		-		-
Net loss before income taxes		(37,070,970)		-		-		-
Income tax provision (benefit):		(9,719,825)		10,311,954		-		10,311,954
Net income (loss)	$	(27,351,145)	$	17,787,762	$	(6,709,129)	$	11,078,133

Oil and Gas Revenue

Oil and gas revenue for the year ended 2009 decreased to $47,391,292 from $68,899,305 in 2008. The decrease in revenue was attributable to a 41% decline in average hydrocarbon prices realized during 2009 partially offset by a 16% increase in production volumes. The following table discloses the net oil and natural gas production volumes, average daily production, oil and gas revenues, and average sales prices for the years ended December 31, 2008 and 2009:


	2008		2009
Oil and gas production (MMcfe)		5,044		5,876
Average daily production (MMcfe)		13.82		16.10
Oil and gas revenues (in 000’s)	$	68,899	$	47,391
Price per Mcfe	$	13.66	$	8.07

The decline in average prices realized from the sale of oil and gas reflected the sharp worldwide economic decline that began during the second half of 2008 and continued to cause depressed oil and gas prices during 2009, as compared to 2008 pricing, particularly during the first quarter of 2009. Oil and gas prices stabilized and oil prices rose during the last three quarters of 2009 although, at and for the year ended December 31, 2009, prices remain well below 2008 prices.

The increase in production during 2009 was due to recompletions and workovers of 4 wells during the fourth quarter of 2008 and 5 wells during 2009, the commencement of production in September 2009 from a developmental well in the Grand Bay Field and the temporary interruption of production from substantially all of our Louisiana properties as a result of Hurricanes Gustav and Ike that resulted in estimated losses of production of approximately 19.4 MBbls of oil and 113.1 MMcf during 2008.

Operating Expenses

Operating expenses decreased to $48,771,833 for 2009 from $54,910,903 in 2008. The following table sets forth the components of operating expenses for 2008 and 2009:


	2008		2009
Lease operating expense	$	28,022,859	$	19,872,914
Exploration expense		-		1,145,724
Depreciation, depletion and amortization		7,845,783		14,577,949
Accretion expense		1,371,261		1,439,437
General and administrative expenses		7,857,971		6,063,497
Impairments		1,693,440		-
Production and severance taxes		8,119,588		5,672,312
	$	54,910,903	$	48,771,833

As more fully described below, the decrease in operating expenses was primarily attributable to decreases in lease operating expenses, general and administrative expenses and production and severance taxes partially offset by increased depreciation, depletion and amortization.

Lease Operating Expenses

Lease operating expenses for 2009 decreased to $19,872,914, or $3.38 per Mcfe, from $28,022,859 in 2008, or $5.56 per Mcfe. During 2008, the Predecessor had an oil spill in the South Atchafalaya Bay which contributed to an increase in lease operating expenses. Operating costs in our fields have historically been relatively high due to water handling, the need for gas lift to maintain oil production and due to the need for marine transportation in the shallow water, bay environment. We have been actively engaged in field management efforts to reduce our lease operating expenses on a per Mcfe basis. The absence of oil spill costs during 2009 and a general reduction in lease operating expenses resulting from our field management efforts were the primary causes of reductions in lease operating expenses during 2009. Included in 2009 lease operating expenses is $2,112,090 related to workover expenses, $215,015 related to hurricane repairs from hurricanes Ike and Gustav, and $1,368,194 related to the mineral royalty audit.

Exploration Expenses

Exploration expense for 2009 increased to $1,145,724 from $0 in 2008. The increase is due to our undertaking of full field studies on our properties for evaluation of our assets during 2009.

Depreciation, Depletion and Amortization (DD&A)

Depreciation, depletion and amortization for 2009 increased to $14,577,949 from $7,845,783 in 2008. The increase in DD&A was attributable to the acquisition of the Harvest Companies during the third quarter 2008 and development programs during the fourth quarter 2008 and during 2009 which increased the basis of the oil and gas properties. 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.

Accretion expense

Accretion expense for 2009 increased to $1,439,437 from $1,371,261 in 2008. The increase in accretion expense was attributed to an increase in the discount rate due to the higher interest rate we incurred during the financing of the Harvest Companies.

General and Administrative Expenses and Other

General and administrative expense decreased to $6,063,497 from $7,857,971 in 2008. The decrease in general and administrative expense related principally to bad debt charge during 2008.

Impairments

Impairments decreased to $0 from $1,693,440 in 2008. The 2008 impairment charge was due to the significant drop in oil and gas commodity prices during 2008.

Production and Severance Taxes

Production and ad valorem taxes decreased to $5,672,312 from $8,119,588 in 2008. The decrease is due to the decrease in oil and gas revenues during 2009.

Other Income (Expense), Net

Net other income (expenses) totaled $(31,512,149) of expenses for 2009 and $4,865,660 of income for 2008. The following table sets forth the components of net other income (expenses) for 2008 and 2009:


	2008		2009
Commodity derivative income (expense)	$	20,073,134	$	(4,030,004)
Interest income		115,414		35,811
Interest expense		(15,322,888)		(27,517,956)
	$	4,865,660	$	(31,512,149)

As more fully described below, the changes in other income (expense), net, was principally attributable to fluctuations in commodity derivative income (expense) during 2009 and increased net interest expense during 2009.

Commodity Derivative Income (Expense)

Commodity derivative income (expense) reflects changes within a period in the prices of commodities underlying our crude oil and natural gas hedges. In general, where prices of underlying commodities rise during a period we recognize commodity derivative expense and where prices of underlying commodities decrease during a period we recognize commodity derivative income. Commodity derivative expense totaled $(4,030,004) in 2009 as compared to income of $20,073,134 in 2008. Pursuant to the terms of the Wayzata Credit Agreement and the Revolving Credit Agreement, we were party to certain derivative contracts and entered into additional derivative contracts to reduce the impact of changes in the prices of oil and natural gas. The commodity derivative income (expense) during 2009 and 2008 reflects the extreme volatility of crude oil and natural gas prices during 2008 and 2009, with oil and natural gas prices rising sharply during the first nine months of 2008 followed by a steep and rapid decline in prices lasting through the first quarter of 2009 followed by a rise in crude oil prices beginning in the second quarter of 2009. In particular, the sharp decrease in oil and gas prices during 2008 resulted in a gain while the partial recovery of oil and gas prices during 2009 resulted in a loss during 2009. In February 2010, Wayzata disclosed that it had acquired the Saratoga debt owed to Macquarie and had unwound all of Saratoga’s commodity hedges

Interest Income (Expense), Net

Interest income (expense), net, reflects interest incurred on debt under the Wayzata note and the Revolver Facility. Net interest expense increased to $(27,517,956) from $15,322,888 in 2008. The increase in net interest expense was attributable to the incurrence of approximately $110 million of debt in connection with the Harvest Acquisitions.

Income Tax Provision.

For 2009, we recorded an income tax benefit of $9,719,825 compared to income tax expense of $10,311,954 for 2008. The income tax benefit for 2009 was attributable to the tax losses incurred while the income tax provision for 2008 was attributable to the successor company reporting taxes as a c-corporation following the Harvest Acquisition which was previously operated as a limited liability company.

The effective tax rates for 2009 and 2008 were 26.2% and 36.7%, 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 and any amounts owing during the period related to our hedging positions. Pending our exit from bankruptcy, we expect to fund our operations and limited capital expenditures and satisfy our debt service obligations through operating cash flow and cash on hand. Since prior to our bankruptcy filing in March 2009, we have not had access to available capital under our Revolving Credit Agreement.

As a result of the liquidation of our oil and gas hedges during February 2010 and the accompanying decline in monthly revenues absent an increase in commodity prices, we may seek to establish debtor-in-possession financing (“DIP Financing”) to support operations during the pendency of our bankruptcy. If we successfully exit from bankruptcy, we intend to undertake efforts to restart our development program and, in that regard, expect that we will be required to seek new financing to supplement and/or take out the existing revolving credit facility and term debt to Wayzata.

We believe that our cash flows from operations and cash on hand are sufficient to support our liquidity needs during the pendency of our bankruptcy, including for the balance of 2010. We do not, however, believe that our cash flows from operations and cash on hand will be adequate to fully pursue our planned drilling and development activities. Assuming we are able to exit bankruptcy in the manner provided for in the Modified Third Amended Plan and to restructure our credit facilities as contemplated therein, we may still be required to secure additional financing to restart our drilling and development plan or to refinance out debt upon maturity in 2012. Future declines in oil and gas prices, and accompanying declines in revenues and profitability could result in our inability to support our operations and drilling and development activities and comply with the terms of our credit facilities. Such price declines were a principal cause of our 2009 Chapter 11 filing.

We have no commitments to provide additional capital or financing if needed to retire our existing indebtedness and, given the current condition of the capital and credit markets, there is no assurance that any such capital or financing will be available on acceptable terms, or at all, if needed.

Cash, Cash Flows and Working Capital

We had a cash balance of $21,575,483 and working capital of $6,320,500 at December 31, 2009 as compared to a cash balance of $5,677,994 and a working capital deficit of $10,528,527 at December 31, 2008. The increase in cash on hand and working capital is attributable to liabilities that existed at the date of our bankruptcy filing that remain payable and have been reclassified as non-current liabilities subject to compromise. At December 31, 2009, liabilities subject to compromise totaled $19,631,567.

Operations provided cash flow of $18,740,157 during 2009 as compared to pro forma cash provided by operations of $25,120,031 during 2008. The decline in operating cash flows during 2009 was principally attributable to the substantial decline in oil and natural gas prices offset by decrease in lease operating expenses during 2009 as compared to 2008 and the accompanying decline in revenues and profitability.

Financing activities used cash flows of $1,514,034 during 2009 as compared to pro forma cash used by financing of $4,722,812 during 2008. Cash flows used for financing during 2009 related primarily to payments related to insurance premiums and repayments of notes payables to related parties.

Investing activities used cash totaling $4,356,702 during 2009 as compared to pro forma cash used in investing of $15,890,233 during 2008. Cash used in investing activities during 2009 related primarily to development of oil and gas properties.

Debt and Non-Current Liabilities; Impact of Bankruptcy

We incurred substantial indebtedness in connection with the Harvest Acquisitions, including amounts borrowed under our Wayzata Credit Agreement and our Revolving Credit Agreement. At December 31, 2009, we had $108.8 million of indebtedness outstanding, consisting of $96.3 million under the Wayzata Credit Agreement (excluding $1.2mm debt discount) and $12.5 million under the Revolving Credit Agreement.

Additionally, at December 31, 2009, we had liabilities subject to compromise of $19.6 million, including $2.2 million attributable to the state mineral royalty audit and $0.6 million owed on notes payable to officers. Under our Modified Third Amended Plan, we propose to pay 75%-80% of those liabilities (excluding amounts attributable to the state mineral royalty audit, notes payable to officers and amounts owing under the Revolving Credit Agreement and the Wayzata Credit Agreement) if and when the Modified Third Amended Plan becomes effective with the balance being payable over a period of one year.

Under the Modified Third Amended Plan, we propose to pay (i) $5.5 million under the Revolving Credit Agreement on the effective date of the Modified Third Amended Plan with the balance owing thereunder being paid on an interest only basis monthly with all unpaid balances thereunder being payable April 30, 2012, (ii) interest only on the Amended Wayzata Credit Agreement, payable monthly at 11.25% per annum, with all unpaid balances thereunder being payable April 30, 2012, (iii) amounts owing with respect to the state mineral royalty audit in monthly installments over twenty-four months following the effective date, and (iv) amounts owing to officers under existing promissory notes forty months after the effective date with compound accrued interest. As noted, there is no assurance that the Modified Third Amended Plan will become effective or that we will successfully exit from bankruptcy, in which event we may be required to secure financing to pay off some or all of our debt or liquid some or all of our assets.

Capital Expenditures

Our capital spending for 2009 was $3.8 million relating primarily to our drilling, development, recompletion and workover program. As a result of our operation as debtor-in-possession and inability to access our Revolver Facility during much of 2009, planned capital expenditures under our drilling and development program were curtailed or deferred during 2009.

Our 2010 capital budget will focus on those projects that we believe will generate and lay the foundation for production growth. 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 and, during the pendency of our bankruptcy, will depend upon our ability to utilize cash collateral and/or secure DIP Financing.

Contractual Obligations

The following table details our long-term debt and contractual obligations as of December 31, 2009:


	Payments due by period
	Total		2010		2011 – 2012		2013 – 2014		Thereafter
Debt	$	110,028,878	$	-	$	110,028,878	$	-	$	-
Debt – related parties (includes current portion)		605,428		-		605,428		-		-
Operating leases		573,804		220,481		291,462		61,861		-
Capital leases		-		-		-		-		-
Asset retirement obligations		31,755,000		951,000		3,820,000		1460,000		25,524,000
Performance bonds		-		-		-		-		-
Total	$	142,963,110	$	1,171,481	$	114,745,768	$	1,521,861	$	25,524,000

Our contractual obligations may be materially altered based on the ultimate outcome of our pending bankruptcy.

Risk Management Activities – Commodity Derivative Instruments

Due to the volatility of oil and natural gas prices and requirements under our Revolving Credit Agreement, 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 may partially limit our potential gains from future increases in prices. None of these instruments are used for trading purposes.

In accordance with the terms of our Revolving Credit Agreement, we have entered into commodity derivative agreements. At December 31, 2009, commodity derivative instruments were in place covering approximately 48% of our projected crude oil and natural gas sales over the next 3 years. See Note 7 “Commodity Derivative Instruments” to our consolidated and combined financial statements for further information.

Subsequent to December 31, 2009, Wayzata acquired all rights under the Revolving Credit Agreement and liquidated all of our commodity derivative agreements, applying the proceeds therefrom to the reduction of debt. As a result, as of the date of this report, we had no commodity derivative instruments in place and, in turn, were out of compliance with the requirements of the Revolving Credit Agreement relative to the maintenance of such hedges. Under the Amended Revolving Credit Agreement, as contemplated by the Modified Third Amended Plan and assuming the same becomes effective, we may not, without the consent of Wayzata, hedge more than 60% of our production.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements or guarantees of third party obligations at December 31, 2009.

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. Our ability to enter into such risk management transactions has been curtailed during the pendency of our bankruptcy.

Due to the instability of prices and to achieve a more predictable cash flow, prior to the Harvest Acquisition, the Harvest Companies put in place natural gas and crude oil derivative instruments for a portion of their production through December 2011. We assumed those commodity derivative instruments pursuant to the Harvest Acquisitions. Pursuant to the terms of our Revolving Credit Agreement, we are required to hedge between 60% and 80% of our proved developed production. At December 31, 2009, commodity derivative instruments were in place covering approximately 48% of our projected crude oil and natural gas sales over the next 3 years. Please refer to Note 7 “Commodity Derivative Instruments” to the consolidated and combined financial statements included herein for additional information on our commodity derivative instruments and activity.

As of December 31, 2009, we had entered into the following natural gas derivative instruments:


	NYMEX Contract Price Per MMBtu
	Fixed-Price Swaps			Put Options			Call Options
		Weighted			Weighted			Weighted
		Average		Volume in	Average		Volume in	Average
Period	MMBtu	Fixed Price		MMBtus	Strike Price		MMBtus	Strike Price
2010	397,880	$	7.18	143,100	$	6.50	-	-
2011	241,089	$	6.85	131,175	$	6.50	-	-

As of December 31, 2009, we had entered into the following crude oil derivative instruments:


	NYMEX Contract Price Per Bbl
	Fixed-Price Swaps			Put Options			Call Options
		Weighted			Weighted			Weighted
		Average		Volume in	Average		Volume in	Average
Period	MBbls	Fixed Price		MBbls	Strike Price		MBbls	Strike Price
2010	149,186	$	79.48	24,277	$	50.00	-	-
2011	110,826	$	75.73	26,484	$	50.00	-	-

As noted above, subsequent to December 31, 2009, all of our natural gas and oil derivative instruments were liquidated by Wayzata. Under the Amended Revolving Credit Agreement, as contemplated by the Modified Third Amended Plan and assuming the same becomes effective, we may not, without the consent of Wayzata, hedge more than 60% of our production.

Interest Rate Risk

We consider our interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 90 percent of our debt. At December 31, 2009, total debt included approximately $12.5 million of floating-rate debt. As a result, our annual interest cost in 2010 will fluctuate based on short-term interest rates on what is presently approximately ten percent of our total debt outstanding at December 31, 2009.

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 58 of this report.

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A(T). 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, 2009 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 not effective as of December 31, 2009.

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, 2009, 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.

Based on the evaluation performed, we identified the following material weaknesses in our internal control over financial reporting as of December 31, 2009:

Lack of adequate internal accounting and financial reporting infrastructure. We presently maintain a very limited internal accounting staff and do not employ a controller, resulting in our Vice President – Finance carrying out multiple functions that would normally be segregated among multiple positions. As a result, we lack adequate segregation of duties and are overly reliant upon outside consultants in the accounting and financial reporting process; and

Non-timely recording of certain accounting entries. Primarily as a result of our limited internal accounting and financial reporting infrastructure and the added demands on the accounting and financial reporting personnel due to our operation in bankruptcy, certain adjusting journal entries were required at the end of accounting periods, based on review by our outside accountants, which entries should have been recorded during the period. In particular, share-based compensation expense, certain oil and gas accruals and tax accruals were recorded only after review by our outside auditors instead of being recorded as the same arose which would have been the case had we maintained sufficient internal accounting personnel.

Based on our assessment, management has concluded that our internal control over financial reporting at December 31, 2009, were not effective.

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 temporary rules of the Securities and Exchange Commission that permit the company 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 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.

Other Information

Not applicable

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

Executive Officers and Directors

The following table sets forth the names, ages and offices of our present executive officers and directors.


Name	Age	Position
Thomas F. Cooke	61	Chief Executive Officer and Chairman
Andrew Clifford	55	President and Director
Edward Hebert	37	Vice President – Finance
Kevin Smith	65	Director
Rex White	77	Director

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

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 to his service as an officer of the company, Mr. Cooke has been self-employed as an independent oil and gas producer for more than 20 years.

Andrew C. Clifford has served as our President and a Director since October 2007. He is a petroleum geologist/geophysicist with over 28 years of experience in domestic and international oil and gas exploration and production. Mr. Clifford’s broad 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. Mr. Clifford served as an advisory director to the company from June 2006 until his appointment as a director.

Edward Hebert has served as our Vice President – Finance and Chief Accounting Officer since September 2008. Mr. Hebert is a CPA with broad energy industry experience. Prior to joining the company, Mr. Hebert served as Vice President of Finance for Internet REIT, Inc., a privately held internet media company, from 2006 to 2008; as Vice President and Controller of Particle Drilling Technologies, Inc., a Nasdaq-listed oilfield services company, from 2004 to 2006; as a financial accounting and reporting consultant for Prejean Company, a financial services firm, from 2003 to 2004, where he provided a broad-range of accounting and reporting services to Prejean clients, including oil and gas companies; as a senior accountant for Arena Energy, a privately held oil and gas company, from 2001 to 2003; and as an auditor in the Energy Division of Arthur Andersen from 1999 to 2001.

Kevin M. Smith has served as a Director of the Company since 1997. Mr. Smith has in excess of 35 years experience as an exploration geophysicist. Since 1984 Mr. Smith's work experience has been exclusively devoted to his own geophysical consulting firm (Kevin M. Smith, Inc.). Mr. Smith received a Bachelor of Science degree with a dual major of Geology and Geophysics from the University of Houston. He also did post graduate studies in Geology and Geophysics at the University of Houston.

Rex H. White has served as a Director of the Company since 2006. Mr. White is a self-employed attorney, Board Certified in Oil, Gas and Mineral Law, with over 46 years of experience in the energy industry. Prior to commencing his legal career, Mr. White worked as a petroleum geologist/geophysicist for approximately 10 years, including 7 years with Mobil Oil Corporation. Mr. White’s career in the energy industry includes service as Special Counsel to the Texas Railroad Commission, Assistant Attorney General of the State of Texas, President of the Texas Independent Producer and Royalty Owners Association, and a Presidential appointment to The National Petroleum Council. Mr. White holds a B.S. in Geology, a M.A. in Geology with a minor in Petroleum Engineering and a law degree all from the University of Texas.

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.

Advisory Director

Since October 2007, J.W. “Bill” Rhea has served as an advisory director. Mr. Rhea has over 32 years of business, financial and petroleum engineering experience in all phases of the upstream oil and gas industry, onshore and offshore, both domestically and internationally on four continents. Mr. Rhea is a second-generation oil and gas businessman and, in addition to serving in senior management and chief executive roles in several independent oil and gas companies (public and private), has also been a consultant to industry. Mr. Rhea is steeply versed in the prospect generation and assembly process using state of the art remote sensing and focusing technologies coupled with more traditional 2D and 3D seismic technologies to assemble, drill, and develop world class prospects. Over his career, Mr. Rhea has also worked on acquisitions, mergers, and divestitures of oil and gas assets and companies. Mr. Rhea is currently a petroleum exploration consultant.

Key Employees

Brian Daigle. Mr. Daigle has served as Operations Manager of the Harvest Companies since 2006 and is responsible for the day-to-day management of the companies’ physical assets. Prior to joining the Harvest Companies, from 2004 to 2006 Mr. Daigle was self-employed as a consultant to various operators providing operations management, technical support for facility installation, and managing daily production operations. Mr. Daigle served as Production Superintendent for Denbury Resources from 2001 to 2004. Mr. Daigle has more than 26 years of diversified experience in the oil and gas industry — focused on production operations, facility design, regulatory compliance, and project management in the Gulf of Mexico and inland waters of the State of Louisiana.

Monnie Greer. Ms. Greer has served as Senior Reservoir Engineer for the Harvest Companies since 2006 and is responsible for the overall reserves management of both companies. Prior to joining the Harvest Companies, Ms. Greer served as founder of Evangeline Natural Resources from 2005 to 2006, specializing in identifying remaining reserves in previously abandoned wells and returning these wells to production. Ms. Greer also served as Vice President of Engineering for Cenergy Oil & Gas, as well as varied positions in Denbury Resources, Matrix Oil & Gas, Energy Partners and Shell Exploration and Production. Ms. Greer has more than 20 years of multi-disciplined experience, specializing in subsurface mechanical and reservoir evaluation.

Willard Powell. Mr. Powell has served as Senior Development Geologist for the Harvest Companies since 2006 and is responsible for identifying and developing drilling and workover opportunities on the companies’ asset base. Prior to joining the Harvest Companies, Mr. Powell served as Vice President of Geology for Cenergy Oil & Gas from 2004 to 2007. Mr. Powell also served as Senior Geologist for Denbury Resources, Matrix Oil & Gas, and Shell Exploration and Production. Mr. Powell has more than 41 years of experience, with specialization in developmental geology.

Elizabeth Goodman. Ms. Goodman has served as Geophysical Supervisor for the Harvest Companies since 2005 and is responsible for evaluating the oil and gas potential of the companies’ asset base by assimilation of geological and 3D seismic data. Prior to joining the Harvest Companies, from 2002 to 2005 Ms. Goodman served as an independent consultant to operators utilizing her geophysical expertise to identify remaining oil and gas potential. Ms. Goodman has also served in various positions at Denbury Resources, Matrix Oil & Gas, and Texaco Exploration & Production. Ms. Goodman has more than 25 years experience in oil and gas development, specializing in the integration of geological, geophysical and engineering data for prospect delineation and risk evaluation.

Steve Freeman. Mr. Freeman has served as Senior Production Engineer for the Harvest Companies since 2005 and is responsible for the planning, coordinating and supervision of well work operations, as well as working closely with reservoir engineers, geologists and operations managers/production superintendents to optimize production and identify new well work opportunities. Mr. Freeman served as Production Engineer for Forest Oil Corporation from 2004 to 2005 and as Area Operations Engineer for Denbury Resources from 2001 to 2004. Mr. Freeman also served in various positions at Matrix Oil & Gas and Chevron. Mr. Freeman has more than 25 years experience in domestic oil and gas operations, specializing in production, workover, and completion operations.

Board Committees

The board currently has, and appoints members to, two standing committees: the audit committee and the compensation committee. Each member of these committees is independent as defined by applicable NYSE Amex and SEC rules. Each of the committees has a written charter approved by the board.

Audit Committee

The audit committee is composed of two non-employee directors, Messrs. Smith and White, each of whom meets the independence and financial literacy requirements as defined by applicable NYSE Amex rules. The audit committee assists the Board in 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 none of the present members of the audit committee 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 two non-employee directors, Messrs. Smith and White, each of whom meets the independence requirement as defined by applicable NYSE Amex rules. The committee is responsible for establishing and administering the policies that govern annual compensation. It reviews and approves salaries, bonus and incentive compensation, perquisites, equity compensation, and all other forms of compensation for our executive officers, including the chief executive officer. The compensation committee is also responsible for reviewing and administering our incentive compensation plans, equity incentive programs and other benefit plans. It periodically reviews and makes recommendations to the Board with respect to director compensation.

Nomination of Directors

The board of directors does not maintain a standing Nominating Committee. Instead, the Board has adopted, by resolution, a process of nominating directors wherein nominees must be selected, or recommended for the Board’s selection, by a majority of the independent directors with independence determined in accordance with NYSE Amex standards. Because of the relatively small size of the Board and the current demands on the independent directors, the Board determined that the nomination process would best be carried out, while maintaining the independence of the nominating process, by drawing upon the resources of all Board members with the requirement that nominees be selected by a majority of the independent directors.

In the event of a vacancy on the Board, the process followed by the independent directors in nominating and evaluating director candidates includes requests to Board members and others for recommendations, meetings from time to time to evaluate biographical information and background material relating to potential candidates and interviews of selected candidates by members of the Board.

In considering whether to recommend any particular candidate for inclusion in the Board’s slate of recommended director nominees, the independent directors apply criteria adopted by the Board. These criteria include the candidate’s integrity, business acumen, knowledge of our business and industry, experience, diligence, absence of conflicts of interest and the ability to act in the interests of all stockholders. No specific weights are assigned to particular criteria and no particular criterion is a prerequisite for each prospective nominee. The Board does not have a formal policy with respect to diversity of nominees. We believe that the backgrounds and qualifications of our directors, considered as a group, should provide a composite mix of experience, knowledge and abilities that will best allow the board to fulfill its responsibilities.

The Board may utilize the services of a search firm to help identify candidates for director who meet the qualifications outlined above.

Stockholders may recommend individuals to the independent directors for consideration as potential director candidates by submitting their names, together with appropriate biographical information and background materials and a statement as to whether the stockholder or group of stockholders making the recommendation has beneficially owned more than 5% of our common stock for at least a year as of the date such recommendation is made, to Independent Directors, c/o Corporate Secretary, Saratoga Resources, Inc., 7500 San Felipe, Suite 675, Houston, Texas 77063. Assuming that appropriate biographical and background material has been provided on a timely basis, the stockholder-recommended candidates will be evaluated by following substantially the same process, and applying substantially the same criteria, as it follows for candidates recommended by our Board or others. If the Board determines to nominate a stockholder-recommended candidate and recommends his or her election, then his or her name will be included in the proxy card for the next annual meeting.

Board Leadership Structure and Risk Oversight Role

Our Chief Executive Officer also serves as Chairman of our Board of Directors and we do not presently maintain a “Lead Independent Director”. We believe that such a leadership structure is appropriate for our company given the small size of our company, our operation as debtor-in-possession under supervision of the U.S. Bankruptcy Court and our need to control costs and facilitate rapid response to matters arising in our bankruptcy case.

Our Board provides high level oversight to our risk management activities, consisting principally of interfacing with management with regard to proper risk management policies and implementation of those policies through commodity derivative transactions. In general, the Board familiarizes itself with the risk management policies being pursued and the actual transactions carried out in that regard so as to assure that the policy is sound and the transactions undertaken are consistent with the policy. Given the contractual requirements of the Revolving Credit Agreement, the Board believes that our company and management has little discretion with regard to risk management transactions.

Code of Ethics

The Board of Directors has adopted a Code of Business Ethics covering all of our officers, directors and employees. We require all employees to adhere to the Code of Business Ethics in addressing legal and ethical issues encountered in conducting their work. The Code of Business Ethics requires that our employees avoid conflicts of interest, comply with all laws and other legal requirements, conduct business in an honest and ethical manner and otherwise act with integrity and in the company's best interest.

The Board of Directors has also 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.

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 2009. To our knowledge, all of the filing requirements were satisfied on a timely basis in fiscal year 2009. In making these disclosures, we have relied solely on copies of reports provided to us.

Item 11.

Executive Compensation

Named Executive Officers

The following table sets forth in summary form the compensation earned during each of the two years ended 2009 by our named executive officers and highest paid employees:


Name and Principal Position	Year	Salary ($)		Bonus ($)	Stock Awards ($)	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)	Total ($)
Thomas Cooke, CEO	2009	180,000		15,000	—	—	—	—	8,400	203,400
	2008	180,000	⁽¹⁾	—	—	—	—	—	—	180,000
Andy Clifford, President	2009	180,000		15,000	—	—	—	—	8,400	203,400
	2008	180,000	⁽¹⁾	—	—	—	—	—	—	180,000
Edward Hebert, Vice President –	2009	155,000			—	—	—	—	—	155,000
Finance ⁽²⁾	2008	41,523		—	—	—	—	—	—	41,523

_______________________

(1)

Includes $112,500 of salary accrued and owing to each of Mr. Cooke and Mr. Clifford on the closing of the Harvest Acquisitions and evidenced by a promissory note delivered on closing of the Harvest Acquisitions, which note was repayable, with interest accruing at 10% per annum, in equal monthly installments over three years. Pursuant to our Modified Third Amended Plan of Reorganization, the note evidencing accrued salary is proposed to be amended to eliminate monthly installments and to provide that the note would be payable in full, including all accrued interest, forty months from the Effective Date of the Modified Third Amended Plan.

(2)

Mr. Hebert began employment with the company on September 22, 2008.

Employment Agreements

On October 9, 2007, we entered into an Employment Agreement with Thomas F. Cooke, our Chairman and Chief Executive Officer, pursuant to which Mr. Cooke will continue to serve in those positions for a term of three years. Mr. Cooke draws an annual salary of $180,000 and participates in all of our executive benefit programs, with salary beginning to accrue as of September 1, 2007 and being deferred and accrued until closing of the Harvest Acquisitions.

In October 2007, we entered into an Employment Agreement with Andy Clifford pursuant to which Mr. Clifford will serve as President for a period of three years. Mr. Clifford draws an annual salary of $180,000 and participates in all of our executive benefit programs, with salary beginning to accrue as of September 5, 2007 and being deferred and accrued until closing of the Harvest Acquisitions. Pursuant to the Employment Agreement and a Stock Grant Agreement, Mr. Clifford was granted 2.5 million shares of stock on signing of the Employment Agreement. 2,000,000 of the shares were restricted and subject to forfeiture on termination of Mr. Clifford’s employment if, on that date (1) the company had not completed the acquisition of oil and gas properties and interests with an aggregate value of at least $25 million during Mr. Clifford’s employment, or (2) Mr. Clifford was not continuing in his service as President on the first anniversary of the commencement of his employment. Mr. Clifford’s employment was also subject to termination in the event of failure to conclude a satisfactory acquisition and financing. As result of the completion of the Harvest Acquisitions, the early termination rights lapsed. All shares issued to Mr. Clifford are now fully vested and no longer subject to forfeiture.

2006 Employee and Consultant Stock Plan

In January 2006, our Board of Directors adopted the Saratoga Resources, Inc. 2006 Employee and Consultant Stock Plan (the “Stock Plan”).

Pursuant to the Stock Plan, 1,200,000 shares of common stock were reserved for issuance to employees and consultants as compensation for past or future services or the attainment of goals. In October 2007, the Stock Plan was amended to increase the shares reserved thereunder to 2,525,000.

The Stock Plan is administered by the Board of Directors subject to the right of the Board of Directors to appoint a committee of the Board of Directors to administer the same.

2008 Long-Term Incentive Plan

Effective October 17, 2008, we adopted the Saratoga Resources, Inc. 2008 Long-term Incentive Plan (the “2008 Plan”). The 2008 Plan reserves a total of 3,000,000 for issuance to eligible employees, officers, directors and other service providers pursuant to grants of options, restricted stock, performance stock and other equity based compensation arrangements. As of December 31, 2009, no awards had been made under the 2008 Plan.

Directors

The following table sets forth the compensation paid to directors during 2009:


	Fees Earned or Paid in Cash ($)	Stock Awards ($) (1)	Option Awards ($)(2)(3)	Non-Equity incentive Plan Compensation ($)	All other Compensation ($)	Total ($)
Kevin Smith	—	—	4,462	—	—	4,462
Rex White	—	—	4,462	—	—	4,462
Marvin Chronister ⁽⁴⁾	—	2,700	4,462	—	—	7,162

_________________

(1)

Represents the fair value of common stock issued to Mr. Chronister. During 2009, Mr. Chronister was issued 5,000 shares of common stock as compensation for his service as Chairman of the Audit Committee.

(2)

The dollar amounts reflect the aggregate grant date fair value of the options computed in accordance with FASB ASC Topic 718. Assumptions used in the calculation of this amount are included in Note 12 to our audited financial statements for the fiscal year ended December 31, 2009.

(3)

The following are the aggregate number of option awards outstanding that have been granted to each of our non-employee directors as of December 31, 2009: Mr. Smith: 25,000; Mr. White: 25,000; and Mr. Chronister: 25,000.

(4)

Mr. Chronister resigned as a director effective April 1, 2009.

Beginning in 2009, the only compensation paid for services of non-employee directors, other than reimbursement of expenses associated with service as such, is the annual grant of 20,000 stock options. We may consider payment of certain additional amounts for services of directors in the future.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth information as of March 30, 2010, based on information obtained from the persons named below, with respect to the beneficial ownership of shares of our common stock held by (i) each person known by us to be the owner of more than 5% of the outstanding shares of our common stock, (ii) each director, (iii) each named executive officer, and (iv) all executive officers and directors as a group:


Name and Address of Beneficial Owner ⁽¹⁾	Number of Shares Beneficially Owned ⁽¹⁾		Percentage of Class ⁽²⁾
Thomas F. Cooke ⁽⁴⁾	6,144,922	⁽³⁾	36.8%
Andrew C. Clifford ⁽⁴⁾	2,638,598	⁽⁵⁾	15.8%
Kevin Smith	273,643	⁽⁶⁾	1.6%
Rex H. White	77,500	⁽⁷⁾	*
Edward Hebert	-		*
Macquarie Americas Corp. ⁽⁸⁾	3,300,000		19.8%
All directors and officers as a group (5 persons)	9,134,663		54.6%

_________

Less than 1%.

(1)

Unless otherwise indicated, each beneficial owner has both sole voting and sole investment power with respect to the shares beneficially owned by such person, entity or group. The number of shares shown as beneficially owned include all options, warrants and convertible securities held by such person, entity or group that are exercisable or convertible within 60 days of March 30, 2010.

(2)

The percentages of beneficial ownership as to each person, entity or group assume the exercise or conversion of all options, warrants and convertible securities held by such person, entity or group which are exercisable or convertible within 60 days, but not the exercise or conversion of options, warrants and convertible securities held by others shown in the table.

(3)

Includes 108,648 shares held by June Cooke, Mr. Cooke’s spouse, of which Mr. Cooke disclaims beneficial ownership.

(4)

Address is c/o Saratoga Resources, Inc., 7500 San Felipe, Suite 675, Houston, Texas.

(5)

Includes 6,173 shares held by his spouse in a SEP-IRA and 7,425 shares held by his SEP-IRA. Includes 2,500,000 shares held by CPK Resources, LLC of which Mr. Clifford is the principal officer and owner.

(6)

Includes 20,000 shares held by Sandra Smith, Mr. Smith’s spouse, of which Mr. Smith disclaims beneficial ownership, and 25,000 shares underlying presently exercisable stock options.

(7)

Includes 25,000 shares underlying presently exercisable stock options.

(8)

Address is 125 W. 55^th Street, 22^nd Floor, NY, NY. Based upon information regarding holdings reported on a Schedule 13D filed with the SEC on July 24, 2008 by Macquarie Americas Corp.

Item 13.

Certain Relationships and Related Transactions, and Director Independence

Officer Loans

In conjunction with the closing of the Harvest Acquisitions, during 2008, we issued subordinated promissory notes to Thomas F. Cooke and Andy Clifford, our principal shareholders and officers, evidencing accrued salaries and expenses owing to those officers. The notes were subordinated to the rights of our senior lenders, accrued interest at 10% per annum and were repayable in equal monthly installments of principal and interest over three years.

Pursuant to our bankruptcy filing, no payments have been on the notes to Messrs. Cooke and Clifford following the Petition Date. As part of our Modified Third Amended Plan of Reorganization, we have proposed that the terms of the notes owing to Messrs. Cooke and Clifford be modified to eliminate the payment of monthly installments, to provide that interest would be accrued and compounded annually and to provide for the payment in full of the notes, including accrued interest, forty months following the Effective Date of the Modified Third Amended Plan, and subject to the prior payment of all amounts owed with respect to accepted claims in the bankruptcy.

At December 31, 2009, amounts owing under the notes to Messrs. Cooke and Clifford totaled $482,916 and $122,500, respectively. During 2009, we paid $12,333 and $3,128 in interest to Messrs. Cooke and Clifford, respectively.

Transactions with Macquarie and Affiliates

The revolving credit facility bears interest at varying rates that averaged 4.5% during 2009. Interest paid and accrued to Macquarie totaled approximately $569,000 during 2009. At December 31, 2009, we owed a total of $12,528,878 to Macquarie under the Revolver Facility.

Item 14.

Principal Accountant Fees and Services

The following table presents fees billed for professional services rendered by our principal accountants for the audit of our annual financial statements for the years ended December 31, 2009 and 2008 and fees billed for other services rendered by that firm during those periods.


	2009		2008
Audit fees ⁽¹⁾	$	171,333	$	71,990
Audit related fees		-		-
Tax fees		20,613		-
All other fees		-		-
Total	$	191,946	$	71,990

(1)

Audit fees consist of fees billed for professional services rendered for the audit of our consolidated annual financial statements and review of the interim consolidated financial statements included in quarterly reports and services that are normally provided by in connection with statutory and regulatory filings or engagements.

The policy of our board Audit Committee is to pre-approve all audit and non-audit services provided by the independent auditors.

PART IV

Item 15.

Exhibits and Financial Statement Schedules

Financial statements. See “Index to Financial Statements” on page 58 of this report.

Exhibits


		Incorporated by Reference
Exhibit Number		Incorporated by Reference			Filed Herewith
Exhibit Number	Exhibit Description	Form	Date Filed	Number	Filed Herewith
2.1	Third Amended Plan of Reorganization of Saratoga Resources, Inc. and its affiliated debtors, Modified March 31, 2010				X
3.1	Restated Articles of Incorporation of Saratoga Resources, Inc.	10-SB	10/6/99	3(i)
3.2	Bylaws of Saratoga Resources, Inc.	10-SB	10/6/99	3(ii)
10.1	Saratoga Resources, Inc. 2006 Employee and Consultant Stock Plan*	8-K	1/30/06	10.2
10.2	Amendment No. 1 to 2006 Employee and Consultant Stock Plan*	8-K	10/11/07	10.1
10.3	Saratoga Resources, Inc. 2008 Long-term Incentive Plan*	10-Q	11/19/08	10.1
10.4	Employment Agreement, dated October 9, 2007, with Thomas Cooke*	8-K	10/11/07	10.2
10.5	Employment Agreement, dated October 8, 2007, with Andrew Clifford*	8-K	10/11/07	10.3
10.6	Stock Grant Agreement, dated October 8, 2007, with Andrew Clifford*	8-K	10/11/07	10.4
10.7	Purchase and Sale Agreement, dated October 18, 2007, between Saratoga Resources, Inc., Harvest Oil & Gas, LLC, Barry Ray Salsbury, Brian Carl Albrecht and Shell Sibley	8-K	10/22/07	10.1
10.8	Purchase and Sale Agreement, dated October 24, 2007, between Saratoga Resources, Inc., The Harvest Group, LLC, Barry Ray Salsbury, Brian Carl Albrecht, Shell Sibley, Willie Willard Powell and Carolyn Monica Greer	8-K	10/25/07	10.1
10.7	First Amendment to Purchase and Sale Agreement, dated December 14, 2007, between Saratoga Resources, Inc., Harvest Oil & Gas, LLC, Barry Ray Salsbury, Brian Carl Albrecht and Shell Sibley	8-K	10/17/07	10.1
10.8	First Amendment to Purchase and Sale Agreement, dated December 14, 2007, between Saratoga Resources, Inc., The Harvest Group, LLC, Barry Ray Salsbury, Brian Carl Albrecht, Shell Sibley, Willie Willard Powell and Carolyn Monica Greer	8-K	10/17/07	10.2
10.9	Second Amendment to Purchase and Sale Agreement, dated January 18, 2008, between Saratoga Resources, Inc., Harvest Oil & Gas, LLC, Barry Ray Salsbury, Brian Carl Albrecht and Shell Sibley	8-K	1/22/08	10.1
10.10	Second Amendment to Purchase and Sale Agreement, dated January 18, 2008, between Saratoga Resources, Inc., The Harvest Group, LLC, Barry Ray Salsbury, Brian Carl Albrecht, Shell Sibley, Willie Willard Powell and Carolyn Monica Greer	8-K	1/22/08	10.2
10.11	Third Amendment to Purchase and Sale Agreement, dated February 18, 2008, between Saratoga Resources, Inc., Harvest Oil & Gas, LLC, Barry Ray Salsbury, Brian Carl Albrecht and Shell Sibley	8-K	2/19/08	10.1
10.12	Third Amendment to Purchase and Sale Agreement, dated February 18, 2008, between Saratoga Resources, Inc., The Harvest Group, LLC, Barry Ray Salsbury, Brian Carl Albrecht, Shell Sibley, Willie Willard Powell and Carolyn Monica Greer	8-K	2/1/08	10.2
10.13	Fourth Amendment to Purchase and Sale Agreement, dated July 11, 2008, between Saratoga Resources, Inc., Harvest Oil & Gas, LLC, Barry Ray Salsbury, Brian Carl Albrecht and Shell Sibley	8-K	7/18/08	10.1


10.14	Fourth Amendment to Purchase and Sale Agreement, dated July 11, 2008, between Saratoga Resources, Inc., The Harvest Group, LLC, Barry Ray Salsbury, Brian Carl Albrecht, Shell Sibley, Willie Willard Powell and Carolyn Monica Greer	8-K	7/18/08	10.2
10.15	Credit Agreement, dated July 14, 2008, between Saratoga Resources, Inc. and Wayzata Investment Partners, LLC	8-K	7/18/08	10.3
10.16	Amended and Restated Credit Agreement, dated July 14, 2008, between Saratoga Resources, Inc. and Macquarie Bank Limited	8-K	7/18/08	10.4
10.17	Wayzata Investment Partners LLC Warrant, dated July 14, 2008	8-K	7/18/08	10.5
10.18	Subordinated Promissory Note, dated July 14, 2008, payable to Thomas F. Cooke	8-K	7/18/08	10.6
10.19	Subordinated Promissory Note, dated July 14, 2008, payable to Andrew C. Clifford	8-K	7/18/08	10.7
10.20	Employment Agreement, dated July 14, 2008 between Saratoga Resources, Inc. and Barry Salsbury*	8-K	7/18/08	10.8
14.1	Code of Ethics for CEO and Senior Financial Officers	10-KSB	1/25/06	14.1
21.1	List of subsidiaries				X
23.1	Consent of Malone & Bailey, P.C.				X
23.2	Consent of Collarini Associates				X
31.1	Section 302 Certification of CEO				X
32.2	Section 302 Certification of CFO				X
32.1	Section 906 Certification of CEO				X
32.2	Section 906 Certification of CFO				X
99.1	Reserve Report of Independent Engineer				X

Compensatory plan or arrangement.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	SARATOGA RESOURCES, INC.


Dated: April 14, 2010	By:	/s/ Thomas F. Cooke
		Thomas F. Cooke
		Chairman and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ Thomas F. Cooke	Chairman, Chief Executive Officer and	April 14, 2010
Thomas F. Cooke	Director (Principal Executive Officer)

/s/ Andrew C. Clifford	President and Director	April 14, 2010
Andrew C. Clifford

/s/ Kevin Smith	Director	April 14, 2010
Kevin Smith

/s/ Rex H. White	Director	April 14, 2010
Rex H. White

/s/ Edward Hebert	Vice President – Finance	April 14, 2010
Edward Hebert	(Principal Accounting and Financial Officer)

SARATOGA RESOURCES, INC.

INDEX TO FINANCIAL STATEMENTS


Reports of Independent Registered Public Accounting Firm	F-1

Consolidated and Combined Balance Sheets as of December 31, 2009 and December 31, 2008	F-3

Consolidated and Combined Statement of Operations for the year ended December 31, 2009, for the period July 15, 2008 through December 31, 2008 (Successor), and the period January 1, 2008 through July 14, 2008 (Predecessor)	F-4

Consolidated and Combined Statements of Members’ Capital (Deficit) for the period from January 1, 2008 through July 14, 2008 (Predecessor) and Consolidated Statements of Equity for the years ended December 31, 2009 and 2008 (Successor)	F-5

Consolidated and Combined Statement of Cash Flows for the year ended December 31, 2009 and for the period July 15, 2008 through December 31, 2008 (Successor), and the period January 1, 2008 through July 14, 2008 (Predecessor)	F-6

Notes to Consolidated and Combined Financial Statements	F-7

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Saratoga Resources, Inc

Houston, Texas

We have audited the consolidated balance sheet of Saratoga Resources, Inc. and subsidiaries (“Successor Company) as of December 31, 2009 and 2008, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the year ended December 31, 2009 and for the period from July 14, 2008 through December 31, 2008. These financial statements are the responsibility of the Successor Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Successor Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Successor Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Successor Company as of December 31, 2009 and 2008, and the results of its operations and cash flows for the year ended December 31, 2009 and for the period from July 14, 2008 through December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, Saratoga Resources, Inc. acquired Harvest Oil and Gas, Inc and The Harvest Group, Inc. The transaction was accounted for as a business combination and the basis of assets and liabilities were adjusted to their estimated fair values. Accordingly, the consolidated financial statements as of and for the year ended December 31, 2009 and for the period from July 14, 2008 through December 31, 2008 are not comparable with prior periods.

The accompanying consolidated financial statements have been prepared assuming that Saratoga Resources, Inc. (Debtor-in-Possession) will continue as a going concern. As discussed in Note 1 to the financial statements, Saratoga Resources, Inc. filed a voluntary petition for reorganization under Chapter 11 of the US Bankruptcy Code on March 31, 2009, which raises substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters also are described in Note 1. The consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty.

/s/ MALONEBAILEY, LLP

www.malone-bailey.com

Houston, Texas

April 14, 2010

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Saratoga Resources, Inc

Houston, Texas

We have audited the combined statements of operations, members’ deficit, and cash flows for the period from January 1, 2008 through July 14, 2008 of Harvest Oil and Gas, LLC and The Harvest Group, LLC (“Predecessor Company”). These financial statements are the responsibility of the Predecessor Company’s management. Our responsibility is to express an opinion on the financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Predecessor Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Predecessor Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.

In our opinion, the combined financial statements present fairly, in all material respects, the financial position of Predecessor Company as of July 14, 2008, and the results of its operations and cash flows for the period from January 1, 2008 through July 14, 2008, in conformity with accounting principles generally accepted in the United States of America.

/s/ Malone & Bailey, PC

www.malone-bailey.com

Houston, Texas

April 15, 2009

F-2

Saratoga Resources, Inc.

(DEBTOR-IN-POSSESSION)

CONSOLIDATED BALANCE SHEETS


	December 31,		December 31,
	2009		2008
ASSETS
Current assets:
Cash and cash equivalents	$	21,575,483	$	5,677,994
Accounts receivable		6,375,864		7,392,887
Prepaid expenses and other		1,184,468		1,186,090
Derivative asset		328,980		346,058
Total current assets		29,464,795		14,603,029

Property and equipment:
Oil and gas properties - proved (successful efforts method)		160,709,425		154,449,346
Other		537,280		504,470
		161,246,705		154,953,816
Less: Accumulated depreciation, depletion and amortization		(21,596,154)		(7,018,203)
Total property and equipment, net		139,650,551		147,935,613

Derivative asset		-		9,795,194
Other assets, net		3,719,405		4,078,889
Total assets	$	172,834,751	$	176,412,725

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	2,673,078	$	11,869,017
Revenue and severance tax payable		3,773,503		783,459
Accrued liabilities		19,910,354		1,705,408
Short-term notes payable		414,257		581,836
Current portion of long-term debt – related parties		-		259,488
Asset Retirement Obligation - current		873,103		-
Deferred taxes		-		9,932,348
Total current liabilities		27,644,295		25,131,556

Long-term liabilities
Asset retirement obligation		9,316,970		9,124,717
Derivative liabilities		764,029		-
Long-term debt, net of discount of $1,217,578 and $1,740,250, respectively		108,811,300		108,288,628
Long-term debt – related parties		-		428,057
Total long-term liabilities		118,892,299		117,841,402

Liabilities subject to compromise		19,631,567		-

Commitment and contingencies (see notes)

Stockholders' equity:
Common stock, $0.001 par value; 100,000,000 shares authorized 16,690,292 and 16,877,792 shares issued and outstanding at December 31, 2009 and 2008, respectively		16,690		16,878
Additional paid-in capital		19,887,814		19,309,658
Retained earnings		(13,237,914)		14,113,231

Total stockholders' equity		6,666,590		33,439,767

Total liabilities and stockholders' equity	$	172,834,751	$	176,412,725

See notes to consolidated and combined financial statements.

F-3

Saratoga Resources, Inc.

(DEBTOR-IN-POSSESSION)

STATEMENTS OF OPERATIONS


			For the Periods
	For the Year Ended December 31, 2009 (Successor)		July 15, 2008 – December 31, 2008 (Successor)		January 1, 2008 – July 14, 2008 (Predecessor)
	(Consolidated)		(Consolidated)		(Combined)
Revenues:
Oil and gas revenues	$	47,391,292	$	22,423,746	$	46,475,559
Other revenues		1,478,219		1,419,707		1,116,318

Total revenues		48,869,511		23,843,453		47,591,877

Operating Expense:
Lease operating expense		19,872,914		10,666,669		17,356,190
Exploration expense		1,145,724		-		-
Depreciation, depletion and amortization		14,577,949		5,324,763		2,521,020
Accretion expense		1,439,437		534,168		837,094
General and administrative		6,063,497		3,865,046		3,992,925
Impairments		-		1,693,440		-
Taxes other than income		5,672,312		2,510,548		5,609,040

Total operating expenses		48,771,833		24,594,634		30,316,269

Operating income (loss)		97,678		(751,181)		17,275,608

Other income (expense):
Commodity derivative income (expense), net		(4,030,004)		39,133,737		(19,060,603)
Interest income		35,811		67,578		47,836
Interest expense		(27,517,956)		(10,350,918)		(4,971,970)

Total other income (expense)		(31,512,149)		28,850,397		(23,984,737)

Income (loss) before reorganization expenses and income taxes		(31,414,471)		28,099,216		(6,709,129)

Reorganization expenses		5,656,499		-		-

Income (loss) before income taxes		(37,070,970)		28,099,216		(6,709,129)

Income tax provision (benefit)		(9,719,825)		10,311,954

Net income (loss)	$	(27,351,145)	$	17,787,262	$	(6,709,129)

Net Income per share:
Basic	$	(1.64)	$	1.35	$	-
Diluted	$	(1.64)	$	1.24	$	-

Weighted average number of common shares outstanding:
Basic		16,687,561		13,205,945		-
Diluted		16,687,561		14,334,725		-

See notes to consolidated and combined financial statements.

F-4

Saratoga Resources, Inc.

(DEBTOR-IN-POSSESSION)

STATEMENTS OF CHANGES IN MEMBERS’ DEFICIT (PREDECESSOR) AND

STOCKHOLDERS' EQUITY (SUCCESSOR)


				Additional Paid-in Capital		Net Income (Loss)		Members’ Capital (Deficit)		Total Stockholders’ Equity
	Common Stock
	Shares		Amount
Predecessor Entity (Combined)
Balance, December 31, 2007	-	$	-	$	-	$	-	$	(12,385,212)	$	-

Members’ distribution	-		-		-		-		(3,811,195)		-

Net loss	-		-		-		-		(6,709,129)		-

Balance, July 14, 2008	-	$	-	$	-	$	-	$	(22,905,536)	$	-


Successor Entity (Consolidated)
Balance, December 31, 2007	10,645,292	$	10,645	$	3,049,394	$	(3,674,031)	$	-	$	(613,992)

Common and restricted stock issued for services	1,332,500		1,333		104,333		-		-		105,666

Common stock issued for acquisition	4,900,000		4,900		12,490,100		-		-		12,495,000

Fair value of warrants issued in connection with debt financing	-		-		2,054,039		-		-		2,054,039

Fair value of warrants issued for services	-		-		69,652		-		-		69,652

Stock-based employee compensation	-		-		1,542,140		-		-		1,542,140

Net income	-		-		-		17,787,262		-		17,787,262

Balance, December 31, 2008	16,877,792	$	16,878	$	19,309,658	$	14,113,231	$	-	$	33,439,767

Common stock issued for services	12,500		12		3,593		-		-		3,605

Restricted stock forfeited	(200,000)		(200)		200		-		-		-

Fair value of warrants issued for services	-		-		2,525		-		-		2,525

Stock-based employee compensation	-		-		571,838		-		-		571,838

Net income	-		-		-		(27,351,145)		-		(27,351,145)

Balance December 31, 2009	16,690,292	$	16,690	$	19,887,814	$	(13,237,914)	$	-	$	6,666,590

See notes to consolidated and combined financial statements.

F-5

Saratoga Resources, Inc.

(DEBTOR-IN-POSSESSION)

STATEMENTS OF CASH FLOWS


			For the Periods
	For the Year Ended December 31, 2009 (Successor)		July 15, 2008 – December 31, 2008 (Successor)		January 1, 2008 – July 14, 2008 (Predecessor)
	(Consolidated)		(Consolidated)		(Combined)
Cash flows from operating activities:
Net income (loss)	$	(27,351,145)	$	17,787,262	$	(6,709,129)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		14,577,949		5,324,763		2,521,020
Accretion expense		1,439,437		534,168		837,094
Impairments		-		1,693,440		-
Amortization of debt issuance costs		751,738		440,130		-
Amortization of debt discount		522,672		313,816		2,762,698
Commodity derivative (income) expense		8,812,571		(39,404,983)		15,155,991
Stock-based compensation		577,968		1,547,763		-
Deferred taxes		(9,838,825)		9,838,829		-
Changes in operating assets and liabilities:
Accounts receivable		1,017,023		10,567,925		(5,252,765)
Prepaids and other		1,622		722,446		(1,214,106)
Accounts payable		1,051,123		8,089,827		(596,719)
Revenue and severance tax payable		5,134,090		(2,886,879)		3,670,338
Accrued liabilities		22,043,934		437,441		(1,116,005)
Due to related parties		-		-		55,666

Net cash provided by operating activities		18,740,157		15,005,948		10,114,083

Cash flows from investing activities:
Additions to oil and gas property		(3,838,118)		(12,236,991)		(4,957,082)
Acquisition of Harvest Companies		-		2,030,440		-
Additions to other property and equipment		(32,810)		(211,532)		(14,362)
Other assets		(485,774)		(257,194)		(243,512)

Net cash used in investing activities		(4,356,702)		(10,675,277)		(5,214,956)

Cash flows from financing activities:
Distributed capital		-		-		(3,811,194)
Repayment of short-term notes payable		(1,966,650)		(1,122,267)		(2,232,082)
Proceeds from debt borrowings		1,799,071		4,345,878		-
Proceeds from debt borrowings - related party		-		687,545		-
Repayment of debt borrowings - related party		(82,117)		(482,942)		-
Debt issuance cost		-		(2,107,750)		-
Settlement of commodity hedges recorded in purchase accounting		1,763,730		-		-

Net cash provided (used) in financing activities		1,514,034		1,320,464		(6,043,276)

Net increase (decrease) in cash and cash equivalents		15,897,489		5,651,135		(1,144,149)

Cash and cash equivalents - beginning of period		5,677,994		26,859		4,207,149

Cash and cash equivalents - end of period	$	21,575,483	$	5,677,994	$	3,063,000

Supplemental disclosures of cash flow information:
Cash paid for interest	$	3,306,907	$	9,567,516	$	2,209,272

Non-cash investing and financing activities:
Accounts payable for oil and gas additions	$	2,796,041	$	-	$	-
Revisions to asset retirement obligations	$	374,081	$	-	$	-
Common stock issued in connection with Harvest acquisition	$	-	$	12,495,000	$	-
Note payable issued in connection with Harvest acquisition	$	-	$	105,683,000	$	-

See notes to consolidated and combined financial statements.

F-6

Saratoga Resources, Inc.

(Debtor and Debtor-In-Possession)

NOTES TO THE CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

Saratoga Resources, Inc. (“Saratoga” or the “Successor Company”) is an independent oil and natural gas company engaged in the production, development, acquisition and exploitation of natural gas and crude oil properties. Since 1996, and before our completion of the Harvest Acquisitions (as defined below) in July 2008, Saratoga’ operations and operating assets were limited to (1) ownership of a working interest in the Red Hawk Fusselman and Red Hawk Mississippian fields, including the Adcock Farms No. 1 well, in Dawson County, Texas, (2) rights in approximately 27 square miles of 3D seismic data in the area including the Company’s Dawson County well, (3) a license to approximately 2,000 miles of 2D seismic data in the U.S. gulf coast region, and (4) a 50% working interest in a 80 acre leasehold held-by-production in Dawson County, Texas, adjoining the Adcock Farms No. 1 well site.

Bankruptcy and Going Concern

On March 31, 2009, Saratoga and its subsidiaries, all of which are 100%-owned: Harvest Oil and Gas, LLC, The Harvest Group, LLC, Lobo Operating, Inc. and Lobo Resources, Inc. (collectively the “Debtors”), filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code. The accompanying consolidated financial statements of Saratoga have been prepared in accordance with FASB ASC 852, Reorganizations and on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. However, as a result of the bankruptcy filings, such realization of assets and satisfaction of liabilities are subject to a significant number of uncertainties. Saratoga’s consolidated financial statements do not reflect adjustments that might be required if it (or each of the Debtors) is unable to continue as a going concern. FASB ASC 852 requires the following for Debtor entities:

Reclassification of unsecured or under-secured pre-petition liabilities to a separate line item in the balance sheet which we have called Liabilities Subject to Compromise (“LSTC”);

Non-accrual of interest expense for financial reporting purposes, to the extent not paid during bankruptcy and not expected to be an allowable claim. However, unpaid contractual interest is calculated for disclosure purposes. We are accruing interest for financial reporting purposes.

Adjust any unamortized deferred financing costs and discounts/premiums associated with debt classified as LSTC to reflect the expected amount of the probable allowed claim;

Segregation of reorganization items (direct and incremental costs, such as professional fees, of being in bankruptcy) as a separate line item in the statement of operations outside of income from continuing operations. During 2009, we incurred $5,656,499 of reorganization costs, which reflects cash payments of $5,656,499, all of which are related to operating activities;

Evaluation of actual or potential bankruptcy claims, which are not already reflected as a liability on the balance sheet, under FASB ASC 450, Contingencies. If valid unrecorded claims, including parent guarantees of subsidiary debt, meeting the criteria set out in the above guidance are presented in future periods, Saratoga would accrue for these amounts, also at the expected amount of the allowed claim rather than at the expected settlement amount.

Disclosure of condensed combined debtor entity financial information, if the consolidated financial statements include material subsidiaries that did not file for bankruptcy protection.

F-7

Upon confirmation of Saratoga’s plan of reorganization, and emergence from Chapter 11 reorganization, “fresh-start reporting” must be adopted if the reorganization value of Saratoga’s assets immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if holders of existing voting shares immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. Essentially, the reorganization value of the entity, as mutually agreed to by the debtor-in-possession and its creditors, would be allocated to the entity’s assets in conformity with the procedures specified by FASB ASC 805, Business Combinations.

Our consolidated and combined financial statements have been prepared on a going concern basis in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), including the provisions of AICPA’ Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code” (“SOP 90-7”). This contemplates the realization of assets and satisfaction of liabilities in the ordinary course of business. Accordingly, our consolidated and combined financial statements do not include any adjustments relating to the recoverability of assets and classification of liabilities that might be necessary should we be unable to continue as a going concern.

Due to our Chapter 11 proceedings, the realization of assets and satisfaction of liabilities, without substantial adjustments and/or changes in ownership, are subject to uncertainty. Accordingly, there is substantial doubt about the current financial reporting entity’s ability to continue as a going concern.

The accompanying consolidated and combined financial statements do not reflect or provide for the consequences of the Chapter 11 proceedings. In particular, the financial statements do not show (1) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (2) as to pre-petition liabilities, the amounts that may be allowed for claims or contingencies, or their status and priority; (3) as to shareowners’ equity accounts, the effect of any changes that may be made in our capitalization; or (4) as to operations, the effect of any changes that may be made in our business.

Financial Statements Presented

The Harvest Acquisition was accounted for under the purchase method of accounting pursuant to FASB Accounting Standards Codification 805, Business Combinations. Accordingly, the effect of the Harvest Acquisitions have been included in the Company’s consolidated statement of operations subsequent to the Acquisition Date, and the respective assets and liabilities have been recorded at their estimated fair values in the Company’s consolidated balance sheet as of the Acquisition Date.

The consolidated financial statements for the Successor Company at December 31, 2009 and 2008, and for the year end December 31, 20098 and period July 15, 2008 to December 31, 2008, include the financial statements of Saratoga Resources, Inc., and its subsidiaries, all of which are 100%-owned: Harvest Oil & Gas, LLC, The Harvest Group, LLC, Lobo Operating, Inc. and Lobo Resources, Inc. Intercompany transactions and balances are eliminated in consolidation.

The combined financial statements for the Predecessor Company for the period January 1, 2008 to July 14, 2008, include the financial statements of Harvest Oil & Gas, LLC and The Harvest Group, LLC. All significant intercompany balances and transactions have been eliminated. See Note 3 “Harvest Acquisition”.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Material estimates that are particularly susceptible to significant change in the near term include the determination of depreciation, depletion and amortization, plugging and abandonment liabilities, and the valuation of oil and gas property.

F-8

Dependence on Oil and Gas Prices

As an independent oil and gas producer, our revenue, profitability and future rate of growth are substantially dependent on prevailing prices for natural gas and oil. Historically, the energy markets have been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. Prices for oil and gas have recently declined materially. Any continued and extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital and on the quantities of oil and gas reserves that we can economically produce.

Revenue Recognition

Derivative Instruments

We account for our derivative activities under FASB Accounting Standards Codification 815-20 (ASC 815-20), “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137, 138 (ASC 815-20) and 149. The statement, as amended, establishes accounting and reporting standards requiring that every derivative instrument be recorded on the balance sheet as either an asset or a liability measured at its fair value. The statement requires 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 do not designate any future price risk management activities as accounting hedges under ASC 815-20, and, accordingly, account for them using the mark-to-market accounting method. Under this method, the contracts are carried at their fair value on our consolidated and combined balance sheet under the captions “Derivative assets” and “Derivative liabilities.” Derivative assets and liabilities with the same counterparty and subject to contractual terms which provide for net settlement are reported on a net basis on our consolidated and combined balance sheet. We recognize all unrealized and realized gains and losses related to these contracts on our consolidated and combined statements of income under the caption “Commodity derivative income (expense).”

As of July 1, 2008, Saratoga adopted ASC 815-10, "Amendment of FASB Interpretation No. 39," (ASC 815-10) which effectively amends FIN No. 39, "Offsetting of Amounts Related to Certain Contracts." 815-10 permits the netting of fair values of derivative assets and liabilities for financial reporting purposes, if such assets and liabilities are with the same counterparty and subject to a master netting arrangement. Saratoga has elected to employ net presentation of derivative assets and liabilities when 815-10 conditions are met. 815-10 also requires that when derivative assets and liabilities are presented net, the fair value of the right to reclaim collateral assets (receivable) or the obligation to return cash collateral (payable) is also offset against the net fair value of the corresponding derivative. The Company routinely exercises its contractual right to net realized gains against realized losses when settling with swap and option counterparties.

See Note 7, “Commodity Derivative Instruments”, for a more detailed discussion of our hedging activities.

Concentration of Credit Risk

Accounts receivable relate primarily to the sale of natural gas and crude oil. Credit terms, typical of industry standards, are of a short-term nature and generally do not require collateral.

Sales of oil and gas production to each of BP, Shell and Chevron accounted for 14%, 38% and 39%, respectively of our consolidated revenues (before the effects of hedging) in 2009. We believe that the loss of BP, Shell or Chevron would not have a material adverse effect on us because alternative purchasers are readily available.

F-9

The use of hedging transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. We have entered into hedging contracts with one counterparty. If our counterparty were to default on its obligations to us under the hedging contracts or seek bankruptcy protection, it could have a material adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes.

Periodically during the year ended December 31, 2009, we maintained cash balances in a financial institution in excess of federally insured limits.

Cash and Cash Equivalents

For the purpose of the Statement of Cash Flows, we consider all highly liquid investments with a maturity of three months or less to be cash equivalents.

Accounts Receivable

Receivables are carried at original invoice amount. Uncollectible accounts receivable are charged directly against earnings when they are determined to be uncollectible. Use of this method does not result in a material difference from the valuation method required by generally accepted accounting principles. At December 31, 2009, no reserve for allowance for doubtful accounts was needed.

Oil and Gas Exploration and Development

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

Property Acquisition Costs

Exploratory Costs

Geological and geophysical 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. See Note 8 “Oil and Gas Assets.”

Development Costs

Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.

Depletion and Amortization

F-10

Depreciation of Other Property and Equipment

Impairment of Properties, Plants and Equipment

The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, prices and costs, considering all available evidence at the date of review. If the future production price risk has been hedged, the hedged price is used in the calculations for the period and quantities hedged. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation. The price and cost outlook assumptions used in impairment reviews differ from the assumptions used in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities. In that disclosure, FASB Accounting Standards Codification 932-235, “Disclosures about Oil and Gas Producing Activities,” requires inclusion of only proved reserves and the use of prices and costs at the balance sheet date, with no projection for future changes in assumptions. There was no loss on impairment recognized during the year ended December 31, 2009. During 2008 there was an impairment loss of $2,671,661 as a result of a severe decline in oil and gas prices.

Asset Retirement Obligations and Environmental Costs

F-11

Stock Based Compensation

Income Taxes

Deferred income taxes are based on the difference between the financial reporting and tax basis of assets and liabilities. The deferred income tax provision represents the change during the reporting period in the deferred tax assets and deferred tax liabilities, net of the effect of acquisitions and dispositions. Deferred income tax assets include tax loss and credit carryforwards and are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will be not be realized. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. We establish reserves when, despite our belief that our tax return positions are fully supportable, we believe that certain positions may be challenged and potentially disallowed. When facts and circumstances change, we adjust these reserves through our provision for income taxes.

We adopted the provisions of ASC 740 (formerly known as “Financial Accounting Standards Board (FASB) Interpretation No. 48”), “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109,” (ASC 740) on January 1, 2007. The adoption did not result in a material adjustment to our tax liability for unrecognized income tax benefits. If applicable, we would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2009, no interest or penalties related to uncertain tax positions had been accrued. The tax years 2006-2009 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

In May 2007, the FASB issued ASC 740-10 Definition of Settlement in FASB Interpretation No. 48, (ASC 740-10) which amends FIN 48 and provides guidance concerning how an entity should determine whether a tax position is “effectively,” rather than the previously required “ultimately,” settled for the purpose of recognizing previously unrecognized tax benefits. In addition, ASC 740-10 provides guidance on determining whether a tax position has been effectively settled. The guidance in ASC 740-10 is effective upon the initial January 1, 2007 adoption of FIN 48. Companies that have not applied this guidance must retroactively apply the provisions of this standard to the date of the initial adoption of FIN 48. We have adopted ASC 740-10 and no retroactive adjustments were necessary.

Recently Issued Accounting Standards and Developments

In August 2009, the FASB issued Accounting Standards Update (ASU) No. 2009-05, Fair Value Measurements and Disclosures (ASU 2009-05). ASU 2009-05 amends Subtopic 820-10, Fair Value Measurements and Disclosures , to provide guidance on the fair value measurement of liabilities. ASU 2009-05 provides clarification for circumstances in which a quoted price in an active market for the identical liability is not available. ASU 2009-05 is effective for interim and annual periods beginning after August 26, 2009. The Company adopted the provisions of ASU 2009-05 for the period ended December 31, 2009. There was no impact on the Company’s operating results, financial position or cash flows.

F-12

In June 2009, the FASB issued ASU No. 2009-01, Generally Accepted Accounting Principles (ASU 2009-01). ASU 2009-01 establishes “The FASB Accounting Standards Codification,” or Codification, which became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. On the effective date, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. ASU 2009-01 is effective for interim and annual periods ending after September 15, 2009. The Company adopted the provisions of ASU 2009-01 for the period ended December 31, 2009. There was no impact on the Company’s operating results, financial position or cash flows.

In May 2009, the FASB issued SFAS No. 165, Subsequent Events (ASC 855) to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. ASC 855 is effective for interim and annual reporting periods ending after June 15, 2009. The Company adopted the provisions of ASC 855 for the period ended December 31, 2009. There was no impact on the Company’s operating results, financial position or cash flows.

In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments, (ASC 320-10-65), to expand other-than-temporary impairment guidance for debt securities to enhance the application of the guidance and improve the presentation and disclosure of other-than temporary impairments on debt and equity securities within the financial statements. The adoption of ASC 320-10-65 during 2009 did not have a significant impact on the Company’s operating results, financial position or cash flows.

In April 2009, the FASB issued FSP No. FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, (ASC 820-10-65) to provide additional guidance for estimating fair value when the volume and level of activity for an asset or liability has significantly decreased. In addition, ASC 820-10-65 includes guidance on identifying circumstances that indicate a transaction is not orderly. The adoption of ASC 820-10-65 during 2009 did not have a significant impact on the Company’s operating results, financial position or cash flows.

In December 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting (ASC 2010-3), which amends the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, as well as adding a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being eliminated. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by Release No. 33-8995 are now required to price proved oil and gas reserves using the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. SEC Release No. 33-8995 is effective beginning for financial statements for fiscal years ending on or after December 31, 2009. The impact on the Company’s operating results, financial position and cash flows has been recorded in the financial statements; additional disclosures were added to the accompanying notes to the consolidated financial statements for the Company’s supplemental oil and gas disclosure. See Supplemental Oil and Gas Information for more details.

In January 2010, the FASB issued FASB Accounting Standards Update (ASU) No. 2010-03 Oil and Gas Estimations and Disclosures (ASU 2010-03). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule ASC 2010-3, as discussed above, ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The Company adopted ASU 2010-03 effective December 31, 2009. See Supplemental Oil and Gas Information for more details.

F-13

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133 (ASC 815-10-65). ASC 815-10-65 requires entities that utilize derivative contracts to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. ASC 815-10-65 also requires entities to disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of ASC 815 have been applied, and the impact that hedges have on an entity’s operating results, financial position or cash flows. The Company adopted ASC 815-10-65 on January 1, 2009. There was no impact on the Company’s operating results, financial position or cash flows for the year ended December 31, 2009.

Effective January 1, 2009, the Company adopted FSP No. FAS 157-2, Effective Date of FASB Statement No. 157 (ASC 820-10-55). ASC 820-10-55 delayed the effective date of ASC 820 for all non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until the beginning of the first quarter of fiscal 2009. These include goodwill and other non-amortizable intangible assets. The adoption of ASC 820-10-55 did not have a significant impact on the Company’s operating results, financial position or cash flows.

In June 2008, the FASB issued Emerging Issues Task Force (EITF) 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (ASC 260). ASC 260 clarifies that share-based payment awards that entitle their holders to receive non-forfeitable dividends or dividend equivalents before vesting should be considered participating securities. The adoption of ASC 260 on January 1, 2009 did not have a significant impact on the Company’s operating results, financial position or cash flows.

NOTE 3. HARVEST ACQUISITION

On July 14, 2008, Saratoga acquired (the “Harvest Acquisitions”) all of the equity interests in Harvest Oil & Gas, LLC (“Harvest Oil”) and the Harvest Group, LLC (“Harvest Group,” and together with Harvest Oil, the “Harvest Companies” or the “Predecessor Companies”).

The Predecessor Companies were independent oil and natural gas companies engaged in the production, development, and exploitation of natural gas and crude oil properties, together covering approximately 33,000 gross acres (30,000 net) across 11 fields in the state waters of Louisiana. In connection with the Harvest Acquisitions, we entered into employment agreements with, or otherwise retained the services of, the management and certain key employees of the Harvest Companies.

As consideration for the membership interests in the Predecessor Companies, we paid to the former members of the Harvest Companies a combined purchase price of $105,683,000 in cash and issued 4.9 million shares of common stock. The cash portion of the purchase price included $33,650,818 and $30,000,000 paid by the Harvest Companies to pay a note payable to Macquarie Bank Limited and to obtain a release of a net profits interest and an overriding royalty interest in the properties of the Harvest Companies held by Macquarie Bank Limited and its affiliates (together, “Macquarie”), respectively, which amounts Saratoga paid directly to Macquarie on behalf of the Harvest Companies at closing. Of the 4.9 million shares of common stock issued in the acquisitions, 3.3 million shares were issued directly to Macquarie pursuant to an agreement between Macquarie and the members of the Harvest Companies relating to the release of the net profits interest and overriding royalty interest held by Macquarie. Prior to the Harvest Acquisitions, there existed no material relationship between the Harvest Companies and Saratoga or any of its affiliates, or any of its directors or officers, or any associates of its directors or officers.

The cash portion of the purchase price payable in connection with the Harvest Acquisitions was paid from borrowings under the Wayzata Credit Agreement and the Revolving Credit Agreement (see “—Wayzata Credit Agreement” and “—Revolving Credit Agreement” below).

The following is a summary of the purchase price considerations:

$105.6 million in cash, which excludes $1.1 million in acquisition costs less $3.1 million cash acquired from The Harvest Companies; and

4,900,000 shares of common stock valued at $2.55 per share (the last reported sales price on the closing date) for an aggregate amount of approximately $12.5 million.

F-14

The acquisition has been accounted for in accordance with the provisions of FASB Accounting Standards Codification 805 (ASC 805), “Business Combinations.” The total purchase price was allocated to the individual assets acquired and liabilities assumed based on the estimated fair values. No goodwill was recorded as there was no excess of the purchase price over the net assets acquired. . The allocation of the purchase price is as follows:


Current assets, including acquired cash of $3,063,000	$	22,932,347
Property and equipment		140,337,343
Other assets		1,323,000
Total assets acquired		164,592,690

Current liabilities		9,695,600
Derivative liabilities		29,263,731
Asset retirement obligations		6,422,791
Total liabilities acquired		45,382,122

Net assets acquired	$	119,210,568

The following table presents pro forma data that reflects revenue, income from continuing operations, net income and income per share for the years ended December 31, 2008 as if the Harvest Acquisition had occurred at the beginning of the periods.


Pro-Forma Information	2008
Oil and gas revenue	$	68,899,305
Income from operations		16,524,427
Net income (loss)	$	11,078,133

Basic income (loss) per share	$	0.84
Diluted Income (loss) per share	$	0.77

Wayzata Credit Agreement

In conjunction with the acquisition of Harvest Oil and Harvest Group, on July 14, 2008, we entered into a Credit Agreement (the “Wayzata Credit Agreement”) with Wayzata Investment Partners, LLC (“Wayzata”) pursuant to which Wayzata, or other lenders (together, the “Wayzata Lenders”), agreed to provide loans in an amount up to, and did loan, $97,500,000 to fund the acquisition of the Harvest Companies.

Pursuant to the terms of the Wayzata Credit Agreement, we granted to the Wayzata Lenders a second lien on substantially all of our assets, and each of its subsidiaries, including the Harvest Companies, agreed to guaranty all amounts owing under the Wayzata Credit Agreement.

Pursuant to the terms of the Wayzata Credit Agreement, we issued to the Wayzata Lenders a warrant to purchase 805,515 shares of common stock exercisable for a period of five years at a price of $0.01 per share. These warrants were valued at $2,054,039 at the date of issuance and will impact the effective interest rate.

The Wayzata Credit Agreement includes normal covenants and credit conditions and is subject to the terms of an Intercreditor Agreement with us and Macquarie Bank Limited. See Note 15 “Subsequent Events – Plan of Reorganization” for a description of proposed amendments to the Wayzata Credit Agreement.

F-15

Macquarie Credit Agreement

In conjunction with the acquisition of Harvest Oil and Harvest Group, on July 14, 2008, we entered into a Credit Agreement (the “Revolving Credit Agreement”) with Macquarie pursuant to which we assumed and restated the existing Macquarie credit facilities of the Harvest Companies and Macquarie, or other lenders (together, the “Revolving Credit Lenders”), agreed to provide a revolving credit loan facility in an amount up to $25,000,000. Simultaneous with execution of the Revolving Credit Agreement, we borrowed $12,528,878 under the revolving credit facilities to pay amounts due with respect to the acquisition of the Harvest Companies and related transaction costs. Additionally, letters of credit of the Harvest Companies, totaling $11.5 million, remained outstanding following the acquisition and reduce available borrowing under the revolving credit facility.

Pursuant to the terms of the Revolving Credit Agreement, we will pay $30,000 per year in administrative fees, letter of credit fees equal to the then applicable LIBOR margin payable to the lenders plus a fronting fee of 12.5 basis points and commitment fees and expenses of 50 basis points on the unused portion of the borrowing base under the Revolving Credit Agreement. These fees will have an impact on interest expense and the effective interest rate.

The Revolving Credit Agreement includes normal covenants and credit conditions and is subject to the terms of the Intercreditor Agreement with us and the Wayzata Lenders.

In February 2010, Wayzata disclosed that it had acquired the Saratoga debt owed to Macquarie. Refer to Note 15, Subsequent Events. See Note 15 “Subsequent Events – Plan of Reorganization” for a description of proposed amendments to the Revolving Credit Agreement.

Renewal and Extension of Shareholder Loan and Accrued Salaries of Officers

In conjunction with the Harvest Acquisitions and the related financing, at closing, we repaid $100,000 of advances from Thomas Cooke, our Chairman, Chief Executive Officer and principal shareholder. We owed Mr. Cooke at December 31, 2009 $482,929, pursuant to a Subordinated Promissory Note, providing for payment of equal monthly installments of $17,247, plus interest at 10% per annum, due July 2011.

We owed Mr. Clifford at December 31, 2009, $122,500, pursuant to a Subordinated Promissory Note, providing for payment of equal monthly installments of $4,375, plus interest at 10% per annum, due July 2011.

Since our March 31, 2009 bankruptcy filing, no amounts have been paid to Messrs. Cooke or Clifford with respect to the Subordinated Promissory Notes. See Note 15 “Subsequent Events – Plan of Reorganization” for a discussion of proposed amendments to the terms of the Subordinated Promissory Notes.

Employment Agreement and Stock Grant

In connection with the Harvest Acquisitions, on July 14, 2008, we appointed Barry Salsbury as President of the Harvest Companies, our principal operating subsidiaries, in order to facility the orderly transition of operations following the Harvest Acquisitions. Mr. Salsbury co-founded and, since 2004, served as President of the Harvest Companies.

F-16

We entered into an employment agreement and restricted stock agreement with Mr. Salsbury. Under the terms of Mr. Salsbury’s employment agreement, Mr. Salsbury agreed to serve as President of the Harvest Companies for a term of three years and was entitled to a base salary of $165,000 per year plus participation in our executive benefit programs. Under the terms of a restricted stock agreement, Mr. Salsbury was issued 500,000 shares of common stock, of which 200,000 shares were subject to forfeiture in the event that Mr. Salsbury was not continuing in his service as President of the Harvest Companies on January 14, 2009 and 200,000 shares were subject to forfeiture in the event that Mr. Salsbury was not continuing in his service as President of the Harvest Companies on July 14, 2009. In February 2009, following the mutual determination that the post-Harvest Acquisition management transition had been completed, Mr. Salsbury retired as President of the Harvest Companies and the 200,000 unvested shares of restricted stock issued to Mr. Salsbury were forfeited.

NOTE 4. DEBT

As of the indicated dates, debt consisted of the following:


	December 31,
	2009		2008
Senior secured revolving credit facility due 2011	$	12,528,878	$	12,528,878
20% subordinated secured note due 2011		96,282,422		95,759,750
	$	108,811,300	$	108,288,628

Senior secured revolving credit facility

The Revolving Credit Agreement provides for reserve-based loans of up to $25 million is secured by a first priority security interest in, and first lien on, substantially all of our assets and matures in 2011. Loans under the revolving credit facility are subject to borrowing base requirements and bear interest at varying rates based on percentage of borrowing base and margins ranging from 2.25% to 2.75% over the applicable LIBOR rate or 0.75% to 1.25% over the applicable prime rate. Interest on the revolving credit facility is due monthly with respect to prime rate based loans and at the end of each applicable interest period with respect to Eurodollar loans. At December 31, 2009, we owed $12,528,878 under the Revolving Credit Agreement.

Letters of credit totaling approximately $9,675,360 million were outstanding at December 31, 2009 and reduce amounts available to be drawn under the Revolving Credit Agreement.

In February 2009, notice of default under the Revolving Credit Agreement was given and, at December 31, 2009, we had no access to additional borrowings under the Revolving Credit Agreement. See Note 15 “Subsequent Events – Plan of Reorganization” for a discussion of proposed amendments to the Revolving Credit Agreement.

Subordinated secured note

The $97.5 million term credit facility is secured by a second lien on substantially all of our assets and matures on July 14, 2011. Loans under the facility bear interest at 20% per annum. Interest is due in monthly installments and the principal is due in full at maturity.

F-17

We are subject to certain restrictive financial covenants under the credit facility, including an interest coverage ratio of at least 1.5 to 1.0, a current ratio of at least 1.0 to 1.0, a total debt to annualized earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) ration of 3.5 to 1.0, a minimum quarterly EBITDA, a total debt to annualized EBITDA ration of 3.5 to 1.0, capital expenditures cannon exceed budgeted capital expenditures, a total proved PV10 to net debt ratio of 1.25 to 1.0, production cannot be less than 90% of budgeted production, and lease operating expenses and general and administrative expense cannot be more than 10% of budgeted expenses. The credit facility also includes customary restrictions with respect to liens, indebtedness, loans and investments, material changes in our business, asset sales or leases or transfers of assets, restricted payments, such as distributions and dividends, mergers or consolidations, transactions with affiliates and rate management transactions.

In February 2009, Wayzata provided notice of alleged covenant breaches under the term credit facility. See Note 15 “Subsequent Events – Plan of Reorganization” for a discussion of proposed amendments to the Wayzata Credit Agreement.

NOTE 5. LIABILITIES SUBJECT TO COMPROMISE

As a result of the Chapter 11 Filings, the payment of prepetition indebtedness may be subject to compromise or other treatment under the Debtors’ plan of reorganization. Generally, actions to enforce or otherwise effect payment of prepetition liabilities are stayed. See Note 1, “Organization and Basis of Presentation - Bankruptcy and Going Concern”.

The Debtors have been paying and intend to continue to pay undisputed postpetition claims in the ordinary course of business. In addition, the Debtors may reject prepetition executory contracts and unexpired leases with respect to the Debtors’ operations, with the approval of the Court. Damages resulting from rejection of executory contracts and unexpired leases are treated as general unsecured claims and will be classified as liabilities subject to compromise.

FASB ASC 852, Reorganizations requires prepetition liabilities that are subject to compromise to be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. The amounts currently classified as liabilities subject to compromise may be subject to future adjustments depending on Court actions, further developments with respect to disputed claims, determinations of the secured status of certain claims, the values of any collateral securing such claims, or other events.

Liabilities subject to compromise consist of the following at December 31, 2009:


Accounts payable	$	13,043,112
Revenue and severance tax payable		2,144,046
Accrued interest		2,871,856
Accrued liabilities		967,125
Notes payable – related parties		605,428
Total liabilities subject to compromise	$	19,631,567

See Note 15 “Subsequent Events – Plan of Reorganization” for a discussion of the proposed payment of various classes of holders of liabilities subject to compromise.

NOTE 6. MINERAL ROYALTY AUDIT

In October 2009, the Louisiana Department of Mineral Resources notified us of the completion of audits of royalty payments from Harvest Oil and Harvest Group for the period from September 2005 to March 2009. Pursuant to the notifications, the Department of Mineral Resources asserted deficiencies in royalty payments totaling $1,368,194. Additionally, the Department of Mineral Resources estimated interest and penalties owing of approximately $799,549. We are reviewing the asserted royalty deficiencies and, based on our review, may contest the asserted deficiencies. We also intend to review potential claims against the former owners of Harvest Oil and Harvest Group arising from underpayments determined to have occurred during periods prior to our acquisition of the Harvest Companies.

F-18

NOTE 7. COMMODITY DERIVATIVE INSTRUMENTS

We periodically use derivative instruments in connection with anticipated crude oil and natural gas sales to mitigate the variability of cash flows associated with commodity price fluctuations. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements.

During the year ended December 31, 2009, we recognized a realized gain of $6,546,297 in the Statement of Operations and an unrecognized loss of $10,576,301 as the result of market-to-market valuations.

As of December 31, 2009, we had entered into the following natural gas derivative instruments:


	NYMEX Contract Price Per MMBtu
	Fixed-Price Swaps			Put Options			Call Options
		Weighted			Weighted			Weighted
		Average		Volume in	Average		Volume in	Average
Period	MMBtu	Fixed Price		MMBtus	Strike Price		MMBtus	Strike Price
2010	397,880	$	7.18	143,100	$	6.50	-	-
2011	241,089	$	6.85	131,175	$	6.50	-	-

As of December 31, 2009, we had entered into the following crude oil derivative instruments:


	NYMEX Contract Price Per Bbl
	Fixed-Price Swaps			Put Options			Call Options
		Weighted			Weighted			Weighted
		Average		Volume in	Average		Volume in	Average
Period	MBbls	Fixed Price		MBbls	Strike Price		MBbls	Strike Price
2010	149,186	$	79.48	24,277	$	50.00	-	-
2011	110,826	$	75.73	26,484	$	50.00	-	-

At December 31, 2009, we recognized a current asset of $328,980 and a long-term liability of $764,029 related to the estimated fair value of these derivative instruments.

See Note 15 “Subsequent Events – Liquidation of Derivative Instruments” for a discussion of the liquidation of our commodity derivative instruments.

NOTE 8. OIL AND GAS ASSETS

Property and equipment consisted of the following at:


	December 31,
	2009		2008
Oil and gas properties (proved):
Gross oil and gas properties (proved)	$	160,709,425	$	154,449,346
Accumulated depreciation, depletion and amortization		(21,379,660)		(6,939,036)
Net oil and gas properties (proved)		139,329,765		147,510,310
Other property and equipment		537,280		504,470
Accumulated depreciation and amortization		(216,494)		(79,167)
Net other property and equipment		320,786		425,303
Net property and equipment	$	139,650,551	$	147,935,613

F-19

NOTE 9. ASSET RETIREMENT OBLIGATIONS

We account for plugging and abandonment costs in accordance with FASB Accounting Standards Codification 410-20, Accounting for Asset Retirement Obligations.

We maintain an escrow agreement that has been established for the purpose of assuring maintenance and administration of a performance bond which secures certain plugging and abandonment obligations assumed in the acquisition of oil and gas properties from the Predecessor Companies over certain fields.

At December 31, 2009 and 2008, the amount of the escrow account totaled $2,065,968 and $1,580,198, respectively and shown as other assets.

A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations are as follows:


Balance at December, 2007 (Predecessor)	$	12,375,931
Accretion expense		837,094
Additions		-
Revisions		-
Settlements		-
Balance at July 14, 2008 (Predecessor)	$	13,213,025


Balance at July 15, 2008 (Successor)	$	-
Accretion expense		534,168
Additions		6,422,791
Revisions		2,167,758
Settlements		-
Balance at December 31, 2008 (Successor)		9,124,717
Accretion expense		1,439,437
Additions		-
Revisions		(374,081)
Settlements		-
Balance at December 31, 2009 (Successor)	$	10,190,073

NOTE 10. RELATED PARTY TRANSACTIONS

During the year ended December 31, 2008, our principal officers advanced funds, provided services and paid costs on our behalf. As of December 31, 2009, we owed Thomas Cooke, our Chairman, Chief Executive Officer and principal shareholder, $482,916 in principal and $35,845 in accrued interest, and owed Andy Clifford, our President, $122,500 in principal and $9,230 in accrued interest for their funding of acquisition expenses and deferred salary. The indebtedness to the principle shareholder bears interest at 10%.

In connection with the Harvest Acquisitions, we issued 3,300,000 shares of common stock to Macquarie Americas Corp., making Macquarie Americas Corp. a principal shareholder of our company. Also, in conjunction with the Harvest Acquisitions, we entered into the Revolving Credit Agreement with Macquarie Bank Limited, an affiliate of Macquarie Americas Corp. Pursuant to the terms of the Revolving Credit Agreement, Macquarie Bank Limited agreed to provide a revolving credit loan facility in an amount up to $25,000,000 and we granted to Macquarie Bank Limited a first lien on substantially all of our assets. The revolving credit facility bears interest at varying rates that averaged 4.5% and 5.3% during 2009 and 2008, respectively. Interest paid and accrued to Macquarie Bank Limited totaled approximately $570,000 and $261,000 during 2009 and 2008, respectively. At December 31, 2009, we owed a total of $12,528,878 in principal and $431,226 in accrued interest to Macquarie Bank Limited under the Revolving Credit Agreement. In February 2010, Wayzata disclosed that it had acquired the Saratoga debt owed to Macquarie and had unwound all of Saratoga’s commodity hedges. Refer to Note 15, Subsequent Events.

F-20

NOTE 11. COMMITMENTS AND CONTINGENCIES

Contractual Commitments

We have commitments under non-cancellable operating lease agreements for our office spaces located in Covington, Louisiana and Houston, Texas. Future minimum payments required under these leases as of December 31, 2009 were as follows:

Rent expense with respect to our lease commitments for office space for the year ended December 31, 2009 was $238,038 and for the period from January 1, 2008 to July 14, 2008 as predecessor was $70,612 and from July 15, 2008 to December 31, 2008 as successor was $86,745.

In connection with the acquisition of the Harvest Companies, we by agreement assumed certain plugging and abandonment, reclamation, restoration, and clean up liabilities and obligations related thereto. To secure these liabilities, we maintain $9,675,360 million at December 31, 2009 in letters of credit with Macquarie. The letters of credit are secured by the various oil and gas properties.

The following table details our long-term debt and contractual obligations as of December 31, 2009:


	Payments due by period
	Total		2010		2011 – 2012		2013 – 2014		Thereafter
Debt	$	110,028,878	$	-	$	110,028,878	$	-	$	-
Debt – related parties (includes current portion)		605,428		-		605,428		-		-
Operating leases		573,804		220,481		291,462		61,861		-
Capital leases		-		-		-		-		-
Asset retirement obligations		31,755,000		951,000		3,820,000		1460,000		25,524,000
Performance bonds		-		-		-		-		-
Total	$	142,963,110	$	1,171,481	$	114,745,768	$	1,521,861	$	25,524,000

Our contractual obligations may be materially altered based on the ultimate outcome of our pending bankruptcy.

Contingencies

From time to time the Company may become involved in litigation in the ordinary course of business. At the present time, other than the Company’s operation under Chapter 11 of the U.S. Bankruptcy Code, the Company’s management is not aware of any such litigation that could have a material adverse effect on its results of operations, cash flows or financial condition.

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of December 31, 2009, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company’s properties.

F-21

NOTE 12. COMMON STOCK

Net Income per Common Share

A reconciliation of the components of basic and diluted net income per common share is presented in the tables below:


	For the Year Ended December 31,
	2009					2008
			Weighted					Weighted
			Average					Average
			Common					Common
	Income		Shares			Income		Shares
	(Loss)		Outstanding	Per Share		(Loss)		Outstanding	Per Share
Basic:
Income (loss) attributable to common stock	$	(27,351,145)	16,687,561	$	(1.64)	$	17,787,262	13,205,945	$	1.35
Effective of Dilutive Securities:
Stock options and other		-	-				-	1,128,780
Diluted:
Income (loss) attributable to common stock, including assumed conversions	$	(27,351,145)	16,687,561	$	(1.64)	$	17,787,262	14,335,725	$	1.24

Potentially dilutive securities excluded from the computation of weighted average diluted shares of common stock because the impact of these potentially dilutive securities were antidilutive totaled 1,165,516 for the year ended December 31, 2009.

Equity Issuance

In April 2008, in connection with financial consulting services rendered to the Company, and pursuant to the terms of a Stock Agreement, 500,000 shares of stock (the “Shares”) were issued. One half, or 250,000, of the Shares were subject to forfeiture unless the consultant provided an average of at least ten (10) hours of services per week through July 1, 2008. These shares were valued at $0.40 per share at the date of grant and became vested as of July 1, 2008. An additional 250,000 of the Shares were subject to forfeiture unless the consultant provided an average of at least ten (10) hours of services per week through January 1, 2009. The shares for services to be rendered through January 1, 2009 were forfeited on July 1, 2008 when the consulting contract was cancelled. The Company recorded $100,000 in fair value which was included as acquisition costs relating to the Harvest Acquisitions.

Under the terms of a restricted stock agreement, Mr. Salsbury was issued 500,000 shares of common stock, of which 200,000 shares were subject to forfeiture in the event that Mr. Salsbury was not continuing in his service as President of the Harvest Companies on January 14, 2009 and 200,000 shares were subject to forfeiture in the event that Mr. Salsbury was not continuing in his service as President of the Harvest Companies on July 14, 2009. In February 2009, Mr. Salsbury retired as President of the Harvest Companies and the 200,000 unvested shares of restricted stock issued to Mr. Salsbury were cancelled. The stock-based compensation recorded during fiscal 2009 and 2008 was $0 and $892,500.

In July 2008 the Company issued 4,900,000 shares of common stock at $2.55 per share to the former owners of Harvest Oil in conjunction with the acquisition. 3,300,000 of these shares were issued directly to Macquarie pursuant to an agreement between Macquarie and the members of the Harvest Companies relating to the release of the net profits interest and overriding royalty interest held by Macquarie. The fair value of the shares issued in connection with the Harvest Acquisitions was $12,495,000.

F-22

In July 2008, the Company issued 540,000 shares restricted common stock at $2.55 per share to 8 other employees of the Harvest Companies as an inducement for their continuing services following the Harvest Acquisitions. The shares vest 20% in September 2008, 40% in July 2009 and 40% in July 2010. 108,000 shares were vested at December 31, 2008. The stock-based compensation recorded during fiscal 2009 and 2008 was $571,838 and $619,650, respectively.

In November 2008, pursuant to the terms of the appointment of Marvin Chronister as a director and chairman of the Audit Committee of the Company’s board of directors, the Company issued 10,000 shares of common stock at $2.55 per share to Mr. Chronister as consideration for his services as chairmen of the Audit Committee during the second and third quarters of 2008. The stock-based compensation expense recorded at grant date was $22,500.

In November 2008 the Company issued 2,500 shares of common stock at $2.55 per share to a consultant for services provided. The stock-based compensation recorded at grant date was $5,625.

During the year ended December 31, 2009, we issued 12,500 shares of common stock for services of a director and 2,500 shares of common stock to a consultant for services. The grant-date value of these shares was approximately $3,600.

During the year ended December 31, 2009, 200,000 shares of restricted common stock were forfeited and cancelled. In addition, 536,000 shares of restricted stock vested during 2009.

The following table summarizes information about restricted share activity for the year ended December 31, 2009 as previously described:


	Number of Restricted Shares	Weighted Average Grant Date Fair Value per Share
Outstanding at December 31, 2007	2,000,000	$	0.12
Granted	1,290,000		2.13
Forfeited	-		-
Vested	(2,458,000)		0.35
Outstanding at December 31, 2008	832,000	$	2.55
Granted	-		-
Forfeited	(200,000)		2.55
Vested	(536,000)		2.55
Outstanding at December 31, 2009	96,000	$	2.55

Stock-Based Compensation

In January 2006, our Board of Directors adopted the Saratoga Resources, Inc. 2006 Employee and Consultant Stock Plan (the “Stock Plan”).

The Stock Plan is administered by the Board of Directors subject to the right of the Board of Directors to appoint a committee of the Board of Directors to administer the same.

F-23

During the year ended December 31, 2009, we issued 12,500 shares of common stock for services of consultants and directors and granted stock options to purchase 75,000 shares of common stock. Stock based compensation expense attributable to common shares and grants of options was $577,968 and $1,547,763 during the year ended December 31, 2009 and 2008. The unamortized amount of stock-based compensation that has not been recorded as of December 31, 2009 was $71,400.

During the year ended December 31, 2009, stock options to purchase 75,000 shares of common stock, with a grant-date value of $13,386, were granted to directors. The options are exercisable at $0.36 per share for a term of ten years. The options fully vested immediately. The options were valued using the Black-Sholes model with the following assumptions: $0.36 quoted stock price; $0.36 exercise price; 341% volatility; 5 year estimated life; zero dividends; 1.92% discount rate.

The following table presents the options outstanding at December 31, 2009:


	Number of Shares Underlying Options		Weighted Average Exercise Price per Share		Weighted Average Grant Date Fair Value per Share		Weighted Average Remaining Contractual Life (in Years)	Aggregate Intrinsic Value (1)
Outstanding at December 31, 2007		-		-		-	-		-
Granted		-		-		-	-		-
Exercised		-		-		-	-		-
Forfeited		-		-		-	-		-
Outstanding at December 31, 2008		-		-		-	-		-
Granted		75,000	$	0.36	$	0.18	9.2	$	198,000
Exercised		-		-		-	-		-
Forfeited		-		-		-	-		-
Outstanding at December 31, 2009		75,000	$	0.36	$	0.18	9.2	$	198,000
Exercisable at December 31, 2009		75,000	$	0.36	$	0.18	9.2	$	198,000

(1)

The intrinsic value of an option is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the warrant. On December 31, 2009, the last reported sales price of our common stock on the OTC:BB was $3.00 per share.

The following table summarizes information about stock options outstanding and exercisable at December 31, 2009:


Options Outstanding and Exercisable
Exercise Price	Number of Shares Underlying Warrants	Weighted Average Exercise Price per Share	Weighted Average Remaining Contractual Life (in Years)
0.36	75,000	0.36	9.2
	75,000	0.36	9.2

Warrants

In May 2008, we issued warrants to purchase 30,000 shares of common stock to a law firm as an inducement to provide services. The warrants are exercisable at $0.25 per share. These warrants were valued using the Black-Scholes model with the following assumptions: a term of 5 years, a discount rate of 3.12% and a stock price on measurement date of $0.17, and a volatility rate of 302%. The fair value for this grant is $7,196 and was recorded as acquisition costs relating to the Harvest Acquisitions.

In May 2008, we issued warrants to purchase 250,000 shares of common stock to a law firm as an inducement to provide services. The warrants are exercisable at $0.25 per share. These warrants were valued using the Black-Scholes model with the following assumptions: a term of 5 years, a discount rate of 3.12% and a stock price on measurement date of $0.25, and a volatility rate of 301%. The fair value for this grant is $62,456 and was recorded as acquisition costs relating to the Harvest Acquisitions.

F-24

In July 2008, Pursuant to the terms of the Wayzata Credit Agreement, the Company issued to the Wayzata Lenders a warrant to purchase 805,515 shares of common stock exercisable for a period of five years at a price of $0.01 per share. These warrants were valued using the Black-Scholes model with the following assumptions: a term of 5 years, a discount rate of 3.12% and a stock price on measurement date of $2.55, and a volatility rate of 326%.The fair value for this grant was $2,054,039 at the date of issuance and is recorded as a debt discount on the Wayzata loan. The debt discount is amortized to interest expense over the maturity date of the loan using the effective interest method.

The following table presents the warrants outstanding at December 31, 2009:


	Number of Shares Underlying Warrants		Weighted Average Exercise Price per Share		Weighted Average Grant Date Fair Value per Share		Weighted Average Remaining Contractual Life (in Years)	Aggregate Intrinsic Value (1)
Outstanding at December 31, 2007		-	$	-	$	-	-	$	-
Granted		1,085,516		0.07		1.96	3.5		3,180,893
Exercised		-		-		-	-		-
Forfeited		-		-		-	-		-
Outstanding at December 31, 2008		1,085,516		0.07		1.96	3.5		3,180,893
Granted		5,000	$	1.50	$	0.51	3.5	$	7,500
Exercised		-		-		-	-		-
Forfeited		-		-		-	-		-
Outstanding at December 31, 2009		1,090,516	$	0.08	$	1.99	3.5	$	3,188,393
Exercisable at December 31, 2009		1,090,516	$	0.08	$	1.99	3.5	$	3,188,393

(1)

The intrinsic value of a warrant is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the warrant. On December 31, 2009, the last reported sales price of our common stock on the OTC:BB was $3.00 per share.

The following table summarizes information about stock warrants outstanding and exercisable at December 31, 2009:


Warrants Outstanding and Exercisable
Exercise Price	Number of Shares Underlying Warrants	Weighted Average Exercise Price per Share		Weighted Average Remaining Contractual Life (in Years)
0.01	805,516	$	0.01	3.5
0.17	30,000	$	0.17	3.4
0.25	250,000	$	0.25	3.4
1.50	5,000	$	1.50	3.5
	1,090,516	$	0.08	3.5

NOTE 13. INCOME TAXES

The Company is subject to income tax in the United States. Current tax obligations associated with our provision for income taxes are reflected in the accompanying Balance Sheet as component of “Accrued liabilities” and the deferred tax obligations are reflected in “Deferred income taxes”.

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.

F-25

Our provision (benefit) for income taxes at December 31, 2009 and 2008 consisted of the following:


		2009		2008
Current:
Federal	$	-	$	(3,859,397)
State		212,520		473,125
		212,520		(3,386,272)

Deferred:
Federal		(8,727,541)		13,698,226
State		(1,204,804)		-
		(9,932,345)		13,698,226
Total tax provision (benefit)	$	(9,719,825)	$	10,311,954

The U.S. federal statutory income tax rate is reconciled to the effective rate at December 31, 2009 and 2008 as follows:


	2009	2008
Income tax expense at U.S. federal statutory rate	35.0%	35.0%
Valuation allowance	(11.0)%	-
State and local income taxes, net of federal income tax benefit	3.3%	1.1%
Permanent differences	(4.6)%	-
Temporary differences	3.5%	0.6%
Provision for income taxes	26.2%	36.7%

The components of the net deferred tax assets (liabilities) at December 31, 2009 and 2008 are as follows:


	2009		2008
*Deferred tax asset*
Net operating loss	$	9,594,084	$	-
Stock-based compensation		592,019		356,076
Debt issuance cost (amortization)		360,936		205,618
Impairment		-		592,704
Accretion		-		196,229
Other		8,455		-
Capital loss carryover		103,752		-
Charitable contributions		5,116		-
Total deferred tax assets		10,664,362		1,350,627
Deferred tax liability
Depletion on oil and gas properties		6,438,650		(1,250,777)
Derivatives		166,407		(13,791,744)
Property and equipment (depreciation)		-		(6,332)
Total deferred tax liabilities		6,605,057		(15,048,853)
Less: valuation allowance		(4,059,305)		-
Deferred tax asset (liability)	$	-	$	(13,698,226)

At December 31, 2009, we had $8.9 million of federal net operating loss, or NOL, carryforwards; the federal NOL carryforwards have expiration dates through the year 2029.

At this time, we have not established a valuation allowance for uncertainties in realizing the benefit of tax loss and credit carryforwards, and other deferred tax assets; while we expect to realize the deferred tax assets at December 31, 2009, changes in estimates of future taxable income or in tax laws may alter this expectation.

F-26

NOTE 14. FAIR VALUE MEASUREMENTS

Certain of our financial and nonfinancial assets and liabilities are reported at fair value in the accompanying balance sheets. Effective January 1, 2008, we adopted the provisions of SFAS No. 157 (ASC 820) for financial assets and liabilities. ASC 820 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, ASC 820 establishes a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. ASC 820 requires that an entity give consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets and liabilities at fair value. In accordance with FSP 157-2, we have not applied the provisions of ASC 820 to our asset retirement obligations.

The following table provides fair value measurement information within the hierarchy for our financial assets and liabilities at December 31, 2009:


	Fair Value Measurement Classification
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)
					Significant Unobservable Inputs (Level 3)

							Total
							Total
Assets (liabilities):
Oil and gas derivative option contracts	$	-	$	(616,770)	$	-	$	(616,770)
Oil and gas derivative swap contracts		-		1,051,819		-		1,051,819
Total	$	-	$	435,049	$	-	$	435,049

The estimated fair value of crude oil and natural options and price swaps contracts was based upon forward commodity price curves based on quoted market prices.

NOTE 15. SUBSEQUENT EVENTS

Liquidation of Derivative Instruments

In February 2010, Wayzata acquired all of the rights under the Revolving Credit Agreement and liquidated all of our then existing derivative instruments.

Plan of Reorganization

On February 11, 2010 we filed our Third Amended Plan of Reorganization (the “Third Amended Plan”). On March 30, 2010, following negotiations with Wayzata which resulted in an agreement in principal as to amended terms of both the Wayzata Credit Agreement (the “Amended Wayzata Credit Agreement”) and the Revolving Credit Agreement (the “Amended Revolving Credit Agreement, we filed a modified Third Amended Plan (the “Modified Third Amended Plan”).

F-27

Under the Modified Third Amended Plan, on the Effective Date hereof, (1) the claim arising under the Revolving Credit Agreement would be allowed in the amount of $23.5 million (subject to adjustment for accrued interest if the Effective Date is after May 15, 2010), of which $5.5 million would be paid on the Effective Date, the applicable interest rate under the Amended Revolving Credit Agreement would be revised to a base rate plus 2%, the maturity date under the Amended Revolving Credit Agreement would be revised to April 30, 2012, liens arising under the Revolving Credit Agreement would remain in place substantially in their current form and the remaining indebtedness owed would be payable monthly on an interest only basis and on terms substantially identical to those included in the Revolving Credit Agreement, as amended by the Modified Third Amended Plan and reflected in the Amended Revolving Credit Agreement, (2) the claim arising under the Wayzata Credit Agreement would be allowed in the amount of $127.5 million (subject to adjustment for accrued interest if the Effective Date is after May 15, 2010), the interest rate under the Amended Wayzata Credit Agreement would be revised to 11.25%, the maturity date under the Amended Wayzata Credit Agreement would be revised to April 30, 2012, liens arising under the Wayzata Credit Agreement would remain in place substantially in their current form and the indebtedness owed would be payable monthly on an interest only basis and on the terms set out in the Amended Wayzata Credit Agreement, (3) oil lien claim creditors and other secured creditors would be paid 100% of their claims, including costs and accrued interest, with 80% being paid in cash on the Effective Date and 20% being payable in four equal quarterly installments, subject to certain prepayment requirements should we secure financing during the twelve months following the Effective Date, (4) unsecured creditors would be paid 100% of their claims, with 75% being paid in cash on the Effective Date and 25%, plus costs and accrued interest, being payable in four equal quarterly installments, subject to certain prepayment requirements should we secure financing during the twelve months following the Effective Date, (5) state lessor audit royalty claims in the amount of $1,709,656 would be paid 100% in twenty-four equal monthly installments of $71,235.68, and (6) amounts payable to our principal officers, Thomas Cooke and Andy Clifford, pursuant to existing promissory notes, would be payable 100% forty months following the Effective Date, with compound accrued interest and subject to prior satisfaction in full of all allowed claims. The Modified Third Amended Plan also provides for the issuance of (1) a warrant in favor of Wayzata to purchase up to 2,000,000 shares of our common stock exercisable at $0.01 per share, which warrant will vest and become exercisable 111,111 shares on the Effective Date and 111,111 shares per month over the following seventeen months unless all amounts payable under the Amended Wayzata Credit Agreement paid in full, in which case any unvested portion of the warrant on the date of repayment in full will be forfeited, and (2) 483,310 shares of common stock to be issued pro rata among the oil lien claim creditors, other secured creditors and unsecured creditors. The Modified Third Amended Plan provides that all outstanding common stock and warrants would remain outstanding and retain identical rights following the Effective Date, provided, however, that the current equity holders would not be entitled to receive any dividends or distributions in respect of their equity holdings unless and until the holders of all allowed claims have been paid in full in cash in accordance with the Modified Third Amended Plan. Effectiveness of the Modified Third Amended Plan is subject, among other things, to confirmation of the plan by the Bankruptcy Court and execution of the Amended Revolving Credit Agreement and the Amended Wayzata Credit Agreement. There can be no assurance that the Modified Third Amended Plan will ultimately be confirmed and the terms thereof carried out.

NOTE 16. SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED

Proved Oil and Gas Reserves

Proved oil and gas reserves were estimated by independent petroleum engineers. The reserves were based on the following assumptions:

Future revenues were based on year-end oil and gas prices. Future price changes were included only to the extent provided by existing contractual agreements.

Production and development costs were computed using year-end costs assuming no change in present economic conditions.

Future net cash flows were discounted at an annual rate of 10%.

Reserve estimates are inherently imprecise and these estimates are expected to change as future information becomes available.

F-28

The following summarizes our estimated total net proved reserves for the years in the three-year period ended December 31, 2009:


	Gas (Mcf)	Oil (Bbls)	Mcfe
Estimated at December 31, 2006 (Predecessor)	20,113,000	3,346,000	40,191,000
Purchase, discoveries, extensions, and improved recovery, net of revisions of previous estimates	27,812,000	1,019,000	33,926,000
Production	(3,083,000)	(616,000)	(6,779,000)
Estimated at December 31, 2007 (Predecessor)	44,842,000	3,749,000	67,338,000

Purchase, discoveries, extensions, and improved recovery, net of revisions of previous estimates	6,397,000	1,338,000	14,425,000
Production	(1,612,000)	(572,000)	(5,044,000)
Estimated at December 31, 2008 (Successor)	49,627,000	4,515,000	76,719,000
Purchase, discoveries, extensions, and improved recovery, net of revisions of previous estimates	14,735,500	3,690,000	36,875,500
Production	(2,114,600)	(626,900)	(5,876,000)
Estimated at December 31, 2009 (Successor)	62,247,900	7,578,100	107,718,500

Capitalized costs for our oil and gas producing activities consisted of the following at the end of each of the years in the three-year period ended December 31, 2009:


	2009 (Successor)		2008 (Successor)		2007 (Predecessor)
Proved properties	$	160,709,425	$	154,449,346	$	40,756,840
Unproved properties		-		-		-
		160,709,425		154,449,346		40,756,840
Accumulated depreciation, depletion and amortization		(21,379,660)		(6,939,036)		(11,963,125)
Net capitalized costs	$	139,329,765	$	147,510,310	$	28,793,715

Costs incurred for oil and gas property acquisitions, exploration and development for each of the years in the three-year period ended December 31, 2009 are as follows:


	2009 (Successor)		2008 (Successor)		2007 (Predecessor)
Acquisitions	$	-	$	146,861,318	$	-
Reimbursement of escrow held in acquisition		-		-		(5,182,321)
Overriding royalty interest given up to lender		-		-		-
Capitalized asset retirement obligation		-		-		-
Revisions to asset retirement obligation		(374,081)		(4,648,962)
Impairments		-		-		-
Exploration		-		-		-
Development		6,634,160		12,236,990		7,948,397
	$	6,260,079	$	154,449,346	$	2,766,076

F-29

The following table sets forth the consolidated and combined results of operations for the year ended December 31, 2009 and 2008, together with the consolidated and combined results of operations of the Harvest Acquisition as predecessor for the year ended December 31, 2007.


	For the Year Ended December 31, 2009 (Successor)		July 15, 2008 – December 31, 2008 (Successor)		January 1, 2008 – July 14, 2008 (Predecessor)		For the Year Ended December 31, 2008 (Combined)		For the Year Ended December 31, 2007 (Predecessor)
Oil and gas sales	$	47,391,292	$	22,423,746	$	46,475,559	$	68,899,305	$	57,414,900
Production costs		(19,872,914)		(10,666,669)		(17,356,190)		(28,022,859)		(25,180,731)
Exploration expenses		(1,145,724)		-		-		-		-
Depreciation, depletion and amortization		(14,440,621)		(5,245,596)		(2,507,086)		(7,752,682)		(7,373,867)
Impairments		-		(1,693,440)		-		(1,693,440)		-
Taxes other than income		(5,672,312)		(2,510,548)		(5,609,040)		(8,119,588)		(5,769,828)
Income before income taxes		6,259,721		2,307,493		21,003,243		23,310,736		19,090,474
Income tax provision*		1,640,047		846,812		7,707,848		8,554,660		7,005,893
Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)	$	4,619,674	$	1,460,681	$	13,295,395	$	14,756,076	$	12,084,581

----------------------------------

*Income tax provision for predecessor represents pro forma data using our effective tax rate. The acquisition of the Harvest Companies occurred on July 14, 2008. The Harvest Companies were limited liability companies and did not have an income tax provision.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information was developed utilizing procedures prescribed by Accounting Standards Codification 932-235 (ASC 932-235), “Disclosures about Oil and Gas Producing Activities.” The information is based on estimates prepared by independent petroleum engineers. The “standardized measure of discounted future net cash flows” should not be viewed as representative of the current value of our proved oil and gas reserves. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

In reviewing the information that follows, we believe that the following factors should be taken into account:

•

future costs and sales prices will probably differ from those required to be used in these calculations;

•

actual production rates for future periods may vary significantly from the rates assumed in the calculations;

•

a 10% discount rate may not be reasonable relative to risk inherent in realizing future net oil and gas revenues; and

•

future net revenues may be subject to different rates of income taxation.

Under the standardized measure, future cash inflows were estimated by applying year-end oil and gas prices applicable to our reserves to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of open hedge positions. Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate and year-end prices and costs are required by ASC 932-235.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible outcomes.

F-30

The standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves is as follows:


(dollars in thousands)	2009 (Successor)		2008 (Successor)		2007 (Predecessor)
Future cash inflows	$	696,034	$	402,022	$	608,792
Future production costs		(185,139)		(79,702)		(109,168)
Future development costs		(165,960)		(102,416)		(84,420)
Future net cash flows before income taxes		344,935		219,904		415,204
Future income tax expense		(121,711)		(76,967)		-
Future net cash flows before 10% discount		223,224		142,937		415,204
10% annual discount for estimating timing of cash flows		(77,638)		(44,943)		(115,137)
Standardized measure of discounted future net cash flows	$	145,586	$	97,994	$	300,067

Set forth in the table below is a summary of the changes in the standardized measure of discounted future net cash flows for our proved oil and gas reserves during each of the years in the three-year period ended December 31, 2009:


(dollars in thousands)	2009 (Successor)		2008 (Successor)		2007 (Predecessor)
Beginning of year	$	97,994	$	300,067	$	145,424
Sales of oil and gas produced, net of production costs		(20,705)		(36,956)		(26,463)
Net change in prices and production costs		26,116		(190,296)		77,932
Extension, discoveries, and improved recovery, less related costs		104,992		107,522		154,076
Development costs incurred during the year		13,902		12,942		2,305
Net change in estimated future development costs		(46,465)		(30,937)		(40,841)
Revisions of previous quantity estimates		(2,494)		(25,355)		(8,756)
Net change from purchases and sales of minerals in place		-		-		-
Net change in income taxes		(27,907)		(50,485)		-
Accretion of discount		153		2,530		1,608
Other		-		8,962		(5,218)
End of year	$	145,586	$	97,994	$	300,067

F-31