Edgar Filing: SARATOGA RESOURCES INC /TX

SARATOGA RESOURCES, INC.

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

Amendment No.1

(Mark One)

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

For the Fiscal Year Ended December 31, 2008

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, 2008, based on the closing sales price of the registrant’s common stock on that date, was approximately $1,350,000. 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 31, 2009 was 16,882,792.

DOCUMENTS INCORPORATED BY REFERENCE

None.

TABLE OF CONTENTS


		Page
PART 1

Item 1.	Business	5
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	24
Item 2.	Properties	24
Item 3.	Legal Proceedings	24
Item 4.	Submission of Matters to a Vote of Security Holders	24

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
Item 6.	Selected Financial Data	26
Item 7.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 8.	Financial Statements and Supplementary Data	43
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	43
Item 9A.	Controls and Procedures	43
Item 9B	Other Information	44

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	44
Item 11.	Executive Compensation	49
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	51
Item 13.	Certain Relationships and Related Transactions, and Director Independence	51
Item 14.	Principal Accountant Fees and Services	53

PART IV

Item 15.	Exhibits and Financial Statement Schedules	54

SIGNATURES		56

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.

EXPLANATORY NOTE

This Amendment No. 1 on Form 10-K/A amends and restates certain disclosure items in our annual report on Form 10-K for the year ended December 31, 2008, which we originally filed on April 15, 2009.

On May 19, 2009, management concluded that the previously filed consolidated financial statements of the Company as of and for the year ended December 31, 2008 needed to be restated.

The restatement results from errors in accounting for the acquisition (the “Harvest Acquisition”) of Harvest Oil & Gas, LLC and The Harvest Group, LLC. The Company, in reporting the Harvest Acquisition in its Form 10-K for the year ended December 31, 2008, made certain estimates as permitted by SFAS No. 141 “Business Combinations.” Subsequent to filing the Form 10-K, the Company reassessed those estimates including the application of SFAS 109, Accounting for Income Taxes related to the Harvest Acquisition. During this reassessment, the Company identified an error whereby the tax basis of its oil and gas properties was not properly adjusted,. resulting in an error in tax depletion, which caused the deferred tax assets to be overstated by $3,663,471. In addition, the Company identified an error in the purchase price allocation related to the Harvest Acquisition. This error resulted in an overstatement of depletion and impairment expense by $4,015,067 and $978,221, respectively, which resulted in a corresponding understatement of net oil and gas properties of $4,993,288, a $3,865,729 overstatement of deferred tax liabilities and an overstatement of income tax expense of $202,258. In addition, the revised statements of operations and cash flows reflect a reclassification of accretion expense from depletion, where it was previously reported.

Accordingly, this Form 10-K/A includes our restated financial statements for the year ended December 31, 2008 to correct our income tax expense, deferred tax asset and deferred tax liability, oil and gas properties, depletion and impairment expense, net income and retained earnings with accompanying notes. This Form 10-K/A also updates disclosure in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operation” to reflect the restated financial statements described above and in Item 9A. “Controls and Procedures” to reflect the re-evaluation of our disclosure controls and procedures and our internal control over financial reporting by our management, including our Chief Executive Officer and our Senior Financial Officer, in connection with the filing of this Form 10-K/A.

Except for the foregoing restated information, the Form 10-K/A continues to describe conditions as of the date of the original filing and we have not updated the disclosures contained herein to reflect events that occurred at a later date. Other events occurring after the original filing or other disclosures necessary to reflect subsequent events have been addressed in reports filed with the SEC subsequent to the date of the original filing. In addition, we have included as exhibits to this amendment new certifications of our Chief Executive Officer and Chief Financial Officer.

PART I

Item 1.

Business

As discussed elsewhere in this Form 10-K, 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. The following discussion should be read in light of the foregoing.

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 33,000 gross acres (30,000 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.

Our total proved reserves as of December 31, 2008 were 76.7 Bcfe, consisting of 49.6 Bcf of natural gas and 4.5 MMbbls of oil. The PV-10 of our proved reserves at year-end was $148.5 million before future income taxes, or $97.9 million after future income taxes. During 2008, we added 14.4 Bcfe through purchases, extensions, discoveries and revisions and produced 5.0 Bcfe. Our average daily net production for December 2008 was 14.0 MMcfe/d, of which 58.7% was oil. We have 63 proved behind pipe and shut-in development opportunities in 6 fields, 35 proved undeveloped opportunities, 62 probable behind pipe and shut-in development opportunities and 6 probable undeveloped opportunities. We have also started full field studies at all of our fields.

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 Macquairie 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.

Recent Developments

Our operations, financial position and outlook have been materially impacted by events following the Harvest Acquisition, including the following:

Declines in Oil and Natural Gas Prices. Late in the third quarter of 2008, accelerating during the fourth quarter of 2008, and continuing into the first quarter of 2009, the United States and global economies suffered severe disruptions in credit and financial markets that have been accompanied by economic contraction and a sharp drop in the price of oil and natural gas due to a projected decline in demand. While we entered into hedging transactions to reduce our exposure to commodity price risks, we are 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 are 63% and 65% respectively lower than they were when we closed the Harvest Acquisitions and entered into the Credit Agreements with Wayzata and Macquarie.

Notices of Default. 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 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 Macquarie 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 states in its notice of default that it is not initiating any action to exercise its rights and remedies available, though its right to do so is 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.

Chapter 11 Filing. 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, we, and our principal operating subsidiaries, filed voluntary Chapter 11 petitions in the U.S. Bankruptcy Court for the Western District of Louisiana.

We intend, subject to bankruptcy court approval, to continue to operate our business and manage our properties as debtors in possession. While we believe that we have sufficient cash to operate our business in the immediate term, upon filing of the bankruptcy petitions, we began discussions with our senior secured lender, and other potential lenders, for new debtor-in-possession (“DIP”) financing to supplement existing working capital. At March 31, 2009, we had cash on hand of approximately $4.7 million.

We intend to use the Chapter 11 process to resolve issues with our lenders and to develop our holdings, continue to grow our production and revenues and reduce our operating expenses pending resolution of issues with our lenders. There is no assurance, however, that we will be able to successfully operate, or finance our operations, in bankruptcy or that we will be able to emerge from bankruptcy with our properties in tact or our current ownership structure.

Our Strategy

Subject to approval of the bankruptcy court, availability of adequate financing and ultimate emergence from bankruptcy, we intend to continue pursuit of our strategy of using our competitive strengths to increase our reserves, production and cash flow. The following are key elements of our strategy:

Grow Through Exploitation, Development and Exploration of Our Properties. We 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 93% of the wells that comprise our proved reserves as of December 31, 2008, and we own net revenue interests in our properties that average approximately 74% 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 115 square miles in the Grand Bay and Vermillion 16 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, 2008.


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	28.6	38%	$	55,191	16,024	18-72%	52	5,915	13
Vermilion 16	35.1	93%		79,392	4,094	70-85%	2	977	*
Other	13.1	46%		13,896	13,632	31-82%	27	7,147	5
All Properties	76.7	65%	$	148,479	33,750		81	14,039	15

* Not meaningful

(1)

Based on December 31, 2008 prices of $42.70 per Bbl and $5.63 per MMBtu.

(2)

Average net production for December 2008.

(3)

Calculated by dividing total net proved reserves by current net production for December 2008.

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 18% to 72% 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 and Big Hum levels below 13,500 feet. Collarini Engineering began a full field study of the Grand Bay Field in October 2008 and this study is expected to continue into mid-2009. Our leases in the Grand Bay Field, which are all held by production, cover an estimated 17,544 gross acres (16,024 net).

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 46% to 81%.

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 is expected to continue into mid-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 eleven other fields, all in Louisiana state waters, with working interests ranging from 40% to 100%. The net revenue interest ranges from 31% to 82%, except for Breton Sound 31 Field, where we have a 36% net profits interest. The leases, which are all held by production, cover an estimated 15,441 gross acres (13,632 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 installed a line heater at Main Pass 25 Field in late 2008, which allowed us to increase oil production from that field.

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 seven platform facilities plus 81 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 revenues from Clayton Williams Energy, Inc. and McMoRan Oil and Gas, LLC.

Natural Gas and Oil Reserves

Due to the inherent uncertainties and the limited nature of reservoir data, proved 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, 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 oil and natural gas sales prices estimated to be in effect as of the date of such reserve estimates and 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, 2008 were a WTI Cushing spot price of $42.70 per Bbl and a Henry Hub spot natural gas price of $5.63 per MMBtu, adjusted by property for energy content, quality, transportation fees, and regional price differentials.

The following table sets forth our estimated net proved oil and natural gas reserves and the PV-10 value of such reserves as of December 31, 2008. The reserve data and the present value as of December 31, 2008 were prepared by Collarini Associates, independent petroleum engineers. The PV-10 value is not intended to represent the current market value of the estimated oil and natural gas reserves owned by us. For further information concerning the present value of future net revenues from these proved reserves, see Supplemental Oil and Gas Disclosures in the Notes to Consolidated and Consolidated Financial Statements.


	Oil	Natural Gas	Undiscounted Future Net Revenue	Present Value of Proved Reserves Discounted at 10% (1)
	(Mbbl)	(MMcf)	($000’s)	($000’s)
Developed Producing	1,274	4,468	(302)	11,464
Developed Nonproducing	1,898	9,227	65,338	46,487
Proved Undeveloped	1,343	35,932	154,869	90,528
Total Proved	4,515	49,627	219,905	148,479

(1)

Management believes that the presentation of PV-10 may be considered a non-GAAP financial measure as defined in Item 10(e) of Regulation S-K. Therefore we have included a reconciliation of the measure to the most directly comparable GAAP financial measure (standardized measure of discounted future net cash flows in the table immediately below). Management believes that the presentation of PV-10 value provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of our natural gas and oil properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. Management also uses this pre-tax measure when assessing the potential return on investment related to its oil and gas properties and in evaluating acquisition candidates. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by us. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows.


	As of December 31, 2008
PV-10	$	148,479
Future income taxes, discounted at 10%		50,485
Standardized measure of discounted future net cash flows	$	97,994

Production and Price History

The table below sets forth certain information regarding the production volumes, revenue, average prices received and average production costs associated with our sale of oil and natural gas for the year ended December 31, 2008. As noted above, our principal operating assets as of December 31, 2008 were acquired on July 14, 2008. Prior to that date, our oil and natural gas properties consisted of holdings in a single prospect and well in Dawson County, Texas. Information regarding years prior to 2008 is not material and has been omitted.


	Combined		Successor		Predecessor
	For the Year Ended December 31, 2008		July 15, 2008 – December 31, 2008		January 1, 2008 – July 14, 2008
Net Production:
Oil (Bbl)		571,975		230,671		341,304
Natural gas (Mcf)		1,612,470		644,985		967,485
Natural gas equivalent (Mcfe)		5,044,320		2,029,011		3,015,309

Oil and natural gas sales Mmcfe ($ 000’s)	$	68,899.3	$	22,423.7	$	46,475.6

Average sales price per Mmcfe	$	13.7	$	11.1	$	15.4

Oil and natural gas costs ($ 000’s)
Lease operating expenses	$	28,022.9	$	10,666.7	$	17,356,2
Production taxes		8,119.5		2,510.5		5,609.0
Total	$	36,142.4	$	13,177.2	$	22,965,2

Average production cost per Mcfe	$	7.17	$	6.50	$	7.62

Drilling Activity

During 2008, beginning with the Harvest Acquisition in July 2008, we drilled 1 productive developmental well in our Grand Bay field in which we own 100% working interest. That well was awaiting completion at December 31, 2008.

The following table sets forth certain information regarding the actual drilling results for 2008:


	Exploratory Wells ⁽¹⁾		Developmental Wells ⁽¹⁾
	Gross	Net	Gross	Net
Productive	-	-	1	1
Dry	-	-	-	-

(1)

Gross wells represent the total number of wells in which we owned an interest; net wells represent the total of our net working interests owned in the wells.

At December 31, 2008, no wells were being drilled.

In addition to the developmental well drilled, during 2008 we recompleted three wells and performed a workover on one well.

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.

Acreage Position

The following table summarizes our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2008.


	Developed acres		Undeveloped acres
	Gross	Net	Gross	Net
Grand Bay	17,544	16,024	-	-
Vermilion 16	3,573	3,573	522	522
Other	15,441	13,632	-	-

Total	37,028	33,229	522	522

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.

Our oil and natural gas properties consist primarily of oil and natural gas wells and our interests in leasehold acreage, both developed and undeveloped.

Marketing and Customers

We market substantially all of our oil and natural gas production from the properties we operate pursuant to a marketing contract with Professional Oil and Gas Marketing, LLC (“POGM”) that expires March 31, 2010. POGM accounted for 100% of our gas, oil and condensate production revenues during fiscal 2008.

We believe there are numerous purchasers of oil and natural gas that would purchase all of our production in the absence of purchases by POGM. Therefore, the loss of POGM as a customer would not be expected to have a significant impact on our ability to market our oil and natural gas production or our results of operations.

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, 2008, we had 27 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:

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

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

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

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

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

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

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

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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.

Future Laws and Regulations

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to restrict or regulate emissions of greenhouse gases. At least 17 states, as well as other regions, have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and regional greenhouse gas cap-and-trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources, e.g., cars and trucks, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The court’s holding in Massachusetts, et al. v. EPA, that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant,” may lead to future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the Kyoto Protocol, an international treaty pursuant to which participating countries, not including the United States, have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Passage of climate-related legislation or other regulatory initiatives by Congress or various states of the U.S., or the adoption of regulations by the EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business, may have an adverse effect on demand for our services or products and may result in compliance obligations with respect to the release, capture and use of carbon dioxide that could have an adverse effect on our 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.

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, accordingly, 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.

Our pending bankruptcy and indebtedness may limit our ability to borrow additional funds or capitalize on acquisition or other business opportunities.

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.

We have incurred substantial indebtedness in acquiring our properties. At December 31, 2008, our indebtedness under our revolving credit facility and term loan totaled $110.0 million, including $97.5 million of term loan which bears interest at 20% per annum. Additionally, we are presently seeking DIP financing to support our operations during the pendency of the Chapter 11 case.

Our leverage and the current and future restrictions contained in the agreements governing our indebtedness and any future DIP financing 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:

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

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

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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;

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

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

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

If we are unable to obtain DIP financing on satisfactory terms, we may be unable to support our existing operations and development program during the pendency of the Chapter 11 case. 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 DIP 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.

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

We expect to make substantial capital expenditures for the acquisition, development, production, exploration and abandonment of oil and gas properties. Our capital requirements 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, during the pendency of the Chapter 11 case, DIP financing. 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 during, and following, the Chapter 11 case. 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 filing for protection under the Chapter 11. Should the current crises continue for an extended period, our financial position may deteriorate along with our ability to operate in, and successfully emerge from, Chapter 11 and our ability to obtain financing to support operations during and following the Chapter 11 case, 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:

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operating a larger organization;

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coordinating potentially geographically disparate organizations, systems and facilities;

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integrating corporate, technological and administrative functions;

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diverting management’s attention from other business concerns;

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an increase in our indebtedness; and

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potential environmental or regulatory liabilities and title problems.

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

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

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.

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:

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domestic and foreign supplies of oil and natural gas;

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

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

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level of consumer product demand;

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level of global oil and natural gas exploration and productivity;

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domestic and foreign governmental regulations;

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level of global oil and natural gas inventories;

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

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weather conditions;

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technological advances affecting oil and natural gas consumption;

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overall U.S. and global economic conditions; and

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price and availability of alternative fuels.

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower oil and natural gas prices may not only decrease our expected future revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in us having to make 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 periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. 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 currently have excellent relationships with oil field service companies, there is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploitation and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.

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:

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severe weather;

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

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

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changes in the regulatory environment.

For example, 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.

Our future business will involve 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:

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fires;

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explosions;

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blow-outs and surface cratering;

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uncontrollable flows of gas, oil and formation water;

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

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pipe, cement, subsea well or pipeline failures;

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casing collapses;

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

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abnormally pressured formations; and

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

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injury or loss of life;

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

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pollution and other environmental damage;

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clean-up responsibilities;

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regulatory investigations and penalties;

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suspension of our operations; and

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repairs to resume operations.

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 will 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:

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the timing and amount of capital expenditures;

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

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the operator’s expertise and financial resources;

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approval of other participants in drilling wells;

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selection of technology; and

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the rate of production of the reserves.

Our insurance may not protect us against 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:

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require the acquisition of a permit before drilling commences;

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

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

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impose substantial liabilities for pollution resulting from operations.

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

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

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incurring investigatory or remedial obligations; and

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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.”

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 March 31, 2009, except as noted below, 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.

On March 31, 2009, we, and our principal operating subsidiaries, filed petitions under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Western District of Louisiana, Lafayette Division (Case Nos. 09-50397, 09-50398, 09-50399, 09-50400 and 09-50401). See “Item 1. Business – Recent Developments – Chapter 11 Filing.”

Item 4.

Submission of Matters to a Vote of Security Holders

On October 21, 2008, the holders of 8,536,275 shares of our common stock, or 50.6% of the outstanding shares, approved by written consent the adoption of the Saratoga Resources, Inc. 2008 Long-Term Incentive Plan.

PART II

Item 5.

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

Market Information

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 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

Calendar Year 2007	Fourth Quarter	$4.00	$0.15
	Third Quarter	0.15	0.12
	Second Quarter	0.25	0.15
	First Quarter	0.20	0.15

At April 6, 2009, the closing price of our common stock on the OTC Bulletin Board was $0.30.

Holders

As of April 6, 2009, there were approximately 1,347 record holders of our common stock.

Dividends

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

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2008 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 reflected in column (a))
Equity compensation plans approved by security holders ⁽¹⁾	―	―	3,000,000
Equity compensation plans not approved by security holders ⁽²⁾	―	―	1,430,000
Total	―	―	4,430,000

(1)

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

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.

Unregistered Sale of Equity Securities

In December 2008, pursuant to the terms of the appointment of Marvin Chronister as a director and chairman of the Audit Committee of our board of directors, we issued 10,000 shares of common stock to Mr. Chronister as consideration for his services as chairmen of the Audit Committee during the second and third quarters of 2008.

The securities described above were issued pursuant to the exemption from registration provided by Section 4(2) of the Securities Act of 1933.

Item 6.

Selected Financial Data

Not applicable.

Item 7.

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

The accompanying consolidated and combined financial statements have been prepared assuming that Saratoga Resources, Inc. will continue as a going concern. As discussed in Note 3 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 and combined 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. The following discussion should be read in light of the foregoing.

Restatement of Financial Statements

On May 19, 2009, management concluded that the previously filed consolidated financial statements of the Company as of and for the year ended December 31, 2008 needed to be restated.

The restatement results from errors in accounting for the acquisition (the “Harvest Acquisition”) of Harvest Oil & Gas, LLC and The Harvest Group, LLC. The Company, in reporting the Harvest Acquisition in its Form 10-K for the year ended December 31, 2008, made certain estimates as permitted by SFAS No. 141 “Business Combinations.” Subsequent to filing the Form 10-K, the Company reassessed those estimates including the application of SFAS 109, Accounting for Income Taxes related to the Harvest Acquisition. During this reassessment, the Company identified an error whereby the tax basis of its oil and gas properties was not properly adjusted resulting in an error in tax depletion, which caused the deferred tax assets to be overstated by $3,663,471. In addition, the Company identified an error in the purchase price allocation related to the Harvest Acquisition. This error resulted in an overstatement of depletion and impairment expense by $4,015,067 and $978,221, respectively, which resulted in a corresponding understatement of net oil and gas properties of $4,993,288, a $3,865,729 overstatement of deferred tax liabilities and an overstatement of income tax expense of $202,258. In addition, the revised statements of operations and cash flows will reflect a reclassification of accretion expense from depletion, where it was previously reported.

As a result of the restatement, net income for the year ended December 31, 2008 was increased by $5,195,546.

The following is a summary of the effect of the restatement on the consolidated financial statements and net income per share amounts affected on our previously reported consolidated financial statements:

RESTATED
CONSOLIDATED BALANCE SHEET
AS OF DECEMBER 31, 2008
(SUCCESSOR)


	As Reported		Adjustments		Restated
ASSETS
Property and equipment:
Oil and gas properties - proved (successful efforts method)	$	151,047,857	$	3,401,489	$	154,449,346
Total property and equipment		151,552,327		3,401,489		154,953,816
Less: Accumulated depreciation, depletion and amortization		(8,610,002)		1,591,799		(7,018,203)
Total property and equipment, net		142,942,325		4,993,288		147,935,613

Other assets, net		7,742,360		(3,663,471)		4,078,889

Total assets	$	175,082,908	$	1,329,817	$	176,412,725

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Deferred taxes	$	13,798,077	$	(3,865,729)	$	9,932,348

Total current liabilities		28,997,285		(3,865,729)		25,131,556

Stockholders' equity (deficit):
Retained earnings		8,917,685		5,195,546		14,113,231

Total stockholders' equity		28,244,221		5,195,546		33,439,767

Total liabilities and stockholders' equity	$	175,082,908	$	1,329,817	$	176,412,725

RESTATED
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE PERIOD JULY 15, 2008 TO DECEMBER 31, 2008
(SUCCESSOR)


	As Reported		Adjustments		Restated
Operating Expense:
Depreciation, depletion and amortization	$	9,873,998	$	(4,549,235)	$	5,324,763
Accretion expense		-		534,168		534,168
Impairments		2,671,661		(978,221)		1,693,440

Total operating expenses		29,587,922		(4,993,288)		24,594,634

Operating income (loss)		(5,744,469)		4,993,288		(751,181)

Net income (loss) before income taxes		23,105,928		4,993,288		28,099,216

Income tax provision (benefit):
Current		473,125		(3,859,397)		(3,386,272)
Deferred		10,041,087		3,657,139		13,698,226

Net income	$	12,591,716	$	5,195,546	$	17,787,262

Net Income per share:
Basic	$	0.95	$	0.39	$	1.35

Diluted	$	0.88	$	0.36	$	1.24

RESTATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE PERIOD JULY 15, 2008 TO DECEMBER 31, 2008
(SUCCESSOR)


	As Reported		Adjustments			Restated
Cash flows from operating activities:
Net income (loss)	$	12,591,716	$	5,195,546	$	17,787,262
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		9,873,998		(4,549,235)		5,324,763
Accretion expense		-		534,168		534,168
Impairments		2,671,661		(978,221)		1,693,440
Deferred taxes		10,041,087		(202,258)		9,838,829

Net cash provided by operating activities	$	15,005,948	$	-	$	15,005,948

General

Saratoga Resources, Inc. (“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, our 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 160 acre leasehold, running through October 2009, in Dawson County, Texas, adjoining the Adcock Farms No. 1 well site.

In October 2007, we entered into separate Purchase and Sale Agreements, each as amended, to acquire all the membership interests of Harvest Oil & Gas, LLC and The Harvest Group, LLC (the “Harvest Acquisitions”), and in July 2008 we completed the Harvest Acquisitions. Since completion of the Harvest Acquisitions, we are principally focused on exploration, exploitation, and development of natural gas and crude oil properties in the state waters of Louisiana. Our properties provide us with a valuable reserve base, an extensive portfolio of lower-risk drilling opportunities and a proved reserve commodity mix that is 67% natural gas and 33% oil.

At December 31, 2008, our principal properties covered approximately 37,080 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. Most of our properties offer multiple stacked reservoir objectives with substantial behind pipe potential. We have identified multiple prospects on our acreage and have initiated an aggressive development program to exploit these opportunities. We believe this development program will enable us to significantly grow our reserves, production and cash flow.

As of January 1, 2009, based on reserve reports prepared by independent petroleum engineers, we had 76.7 Bcfe of proved reserves, of which 65% were natural gas and 53% were proved developed. The PV-l0 of these proved reserves as of that date were $148.5 million before future estimated income taxes. Our average daily net production for December 2008 was 14.0 MMcfe/d, of which 58.7% was oil.

Prior to the Harvest Acquisitions, we had minimal operations. Accordingly, the results of operations included in this Form 10-K for the year ended December 31, 2007 and for the period from January 1, 2008 to July 14, 2008 represent the combined operations the Harvest Acquisitions, as predecessor. The consolidated results of operations for the period from July 14, 2008 to December 31, 2008 represent our consolidated results subsequent to the Harvest Acquisition, as successor.

2008 and 2009 Developments

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”).

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 Acquisitions, and to finance the acquisitions 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 Acquisitions and associated costs.

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 normal covenants and credit conditions and is subject to the terms of an Intercreditor Agreement with us and Macquarie.

Revolving Credit Agreement

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 $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 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.

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. 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.

Employment Agreement and Stock Grant

In connection with the Harvest Acquisitions, 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 has served as President of the Harvest Companies.

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 cancelled.

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 Mbls 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 $1,500,000. 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. 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 claims filed.

Macroeconomic Impact on Oil and Natural Gas Prices

Late in the third quarter of 2008 and accelerating during the early fourth quarter of 2008, the United States and global economies suffered a severe disruption in credit and financial markets that have been accompanied by economic contraction and a sharp drop in the price of oil and natural gas due to a projected decline in demand for oil and natural gas. While we enter into hedging transactions to reduce our exposure to commodity price risks, we are subject to risks associated with declines in the price of oil and natural gas relating to our unhedged production. Any prolonged decrease in the price of oil and natural gas could have a material adverse effect on our revenues, profitability and cash flows and our financial condition and borrowing capacity. As a result of the economic events of the fourth quarter of 2008, our oil and gas revenues and profitability during the fourth quarter of 2008 were adversely impacted and are expected to continue to be adversely impacted for the foreseeable future. We, in turn, have scaled back our drilling and development plans for 2009.

Notices of Default.

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 Macquarie 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 its 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.

Chapter 11 Filing.

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, we, and our principal operating subsidiaries, filed voluntary Chapter 11 petitions in the U.S. Bankruptcy Court for the Western District of Louisiana.

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, did 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 and no wells were being drilled at December 31, 2008.

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. Those studies were ongoing at December 31, 2008.

At and for the year ended December 31, 2008, we had approximately 81 wells in production, including 80 wells in Louisiana and one well in Texas.

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 Proved 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.

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 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 at year-end. In our 2008 year-end reserve report, we used December 31, 2008 a Light Crude price of $42.70 per Bbl, and a Henry Hub price of $5.63 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 prices.

Revenue Recognition

The Company recognizes oil and gas revenue from its 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. The Company recognizes revenue related to gas balancing agreements based on the entitlement method. The Company’s net imbalance position at December 31, 2008, was immaterial.

Derivative Instruments

We account for our derivative activities under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137, 138 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 SFAS No. 133, 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," (FSP FIN No. 39-1) which effectively amends FIN No. 39, "Offsetting of Amounts Related to Certain Contracts." FSP FIN No. 39-1 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 FSP FIN No. 39-1 conditions are met. FSP FIN No. 39-1 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 its swap and option counterparties.

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, SFAS No. 69, “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

Effective January 1, 2006, the Company adopted SFAS No. 123(R), “Share-Based Payment”. SFAS 123(R) replaced SFAS No. 123 and supersedes APB Opinion No. 25. SFAS 123(R) 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. The Company adopted SFAS 123(R) 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, 2008 and 2007 reflect the impact of adopting SFAS 123(R).

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 a 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.

The Company adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109,” (FIN 48) 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, the Company would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2008, the Company had not accrued interest or penalties related to uncertain tax positions. The tax years 2005-2008 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 FSP No. FIN 48-1, Definition of Settlement in FASB Interpretation No. 48, (FIN 48-1) 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, FIN 48-1 provides guidance on determining whether a tax position has been effectively settled. The guidance in FIN 48-1 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 FSP to the date of the initial adoption of FIN 48. The Company has adopted FIN 48-1 and no retroactive adjustments were necessary.

Results of Operations

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

The following table sets forth the audited 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 Companies for the period January 1, 2008 to July 14, 2008, together with the audited combined results of operations of Predecessor Companies for the year ended December 31, 2007.


	Successor		Predecessor		Combined		Predecessor
	July 15, 2008 – December 31, 2008		January 1, 2008 – July 14, 2008		For the Year Ended December 31, 2008		For the Year Ended December 31, 2007
	(Restated)				(Restated)
Revenues:
Oil and gas revenues	$	22,423,746	$	46,475,559	$	68,899,305	$	57,414,900
Other revenues		1,419,707		1,116,318		2,536,025		339,778

Total revenues		23,843,453		47,591,877		71,435,330		57,754,678

Operating Expense:
Lease operating expense		10,666,669		17,356,190		28,022,859		25,180,731
Depreciation, depletion and amortization		5,324,763		2,521,020		7,845,783		7,402,479
Accretion expense		534,168		837,094		1,371,262		1,226,443
General and administrative		3,865,046		3,992,925		7,857,971		2,172,332
Impairments		1,693,440		-		1,693,440		-
Taxes other than income		2,510,548		5,609,040		8,119,588		5,769,828

Total operating expenses		24,594,634		30,316,269		54,910,903		41,751,813

Operating income (loss)		(751,181)		17,275,608		16,524,427		16,002,865

Other income (expense):
Commodity derivative income (expense), net		39,133,737		(19,060,603)		20,073,134		(12,019,439)
Interest income		67,578		47,836		115,414		181,304
Interest expense		(10,350,918)		(4,971,970)		(15,322,888)		(11,138,562)

Total other income (expense)		28,850,397		(23,984,737)		4,865,660		(22,976,697)

Net income (loss) before income taxes		28,099,216		(6,709,129)		21,390,087		(6,973,832)

Income tax provision (benefit):
Current		(3,386,272)		-		(3,386,272)		-
Deferred		13,698,226		-		13,698,226		-

Net income (loss)	$	17,787,762	$	(6,709,129)	$	11,078,133	$	(6,973,832)

Oil and Gas Revenue

Oil and gas revenue for the year ended 2008 increased to $68,899,305 from $57,414,900 in 2007. The increases in revenue were attributable to higher hydrocarbon prices during the first three quarters of 2008. The following table discloses the net oil and natural gas production volumes, sales, and average sales prices for the years ended December 31, 2008 and 2007:


	2008		2007
Oil and gas production (Mmcfe)		5,044		6,779
Oil and gas revenues (in 000’s)	$	68,899	$	57,415
Price per Mcfe	$	13.66	$	8.47

Average daily production for the years ended 2008 and 2007 was approximately 18.6 MMcfe and 13.8 MMcfe, respectively. Average daily production reflects the effects of Hurricanes Gustav and Ike that resulted in production declines during August and September 2008 estimated at 19.4 MBbls of oil and 113.1MMcf of natural gas, or an estimated loss of revenues for 2008 of $3,098.600. The temporary declines in production attributable to Hurricanes Gustav and Ike were offset by additional production brought on line during the fourth quarter of 2008 following commencement of our drilling and development program.

As a result of the sharp worldwide economic decline during the second half of 2008, our average prices realized from the sale of oil and gas declined markedly in the fourth quarter of 2008 to $57.95 per barrel of oil and $7.31 per Mcf of gas or $8.88 per Mcfe.

Operating Expenses

Operating expenses increased to $54,910,903 for 2008 from $41,751,813 in 2007. The following table sets forth the components of operating expenses for 2008 and 2007:


	Combined 2008		Predecessor 2007
Lease operating expense	$	28,022,859	$	25,180,731
Depreciation, depletion and amortization		7,845,783		7,402,479
Accretion expense		1,371,261		1,226,443
General and administrative expenses		7,857,971		2,172,332
Impairments		1,693,440		-
Production and severance taxes		8,119,588		5,769,828
	$	54,910,903	$	41,751,813

As more fully described below, the increase in operating expenses was attributable to the increase in the scope of operations during 2008, an increase in the basis of the oil and gas properties relating to the Harvest Acquisition resulting in an increase in depreciation, depletions and amortization expense, the operation and support of the properties of the Harvest Companies, an increase in overhead in the period leading up to the Harvest Acquisitions and costs associated with transition of management and control of the Harvest Companies.

Lease Operating Expenses

Lease operating expenses for 2008 increased to $28,022,859, or $5.56 per Mcfe, from $25,180,731 in 2007, or $3.71 per Mcfe. The increase in lease operating expenses was attributable to the impacts of hurricanes Gustav and Ike. Operating costs in our fields are 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 are actively engaged in field management efforts to reduce our lease operating expenses on a per Mcfe basis.

Depreciation, Depletion and Amortization (DD&A)

Depreciation, depletion and amortization totaled $7,845,783 for 2008, as compared to $7,402,479 for 2007. The increase is due to the acquisition of the Harvest Companies during the third quarter 2008 and development programs during the fourth quarter 2008 which increased the basis of the oil and gas properties from $40,756,840 at December 31, 2007 to $154,449,346 at December 31, 2008. Depreciation, depletion and amortization is computed on the units-of-production method separately on each individual property. DD&A expense includes the accrual of future plugging and abandonment costs. The Company accounts for future plugging and abandonment costs in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets (i.e., future plugging and abandonment costs) to be recognized at their fair value at the time the obligations are incurred. Upon initial recognition of the liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The estimate of future plugging and abandonment costs is highly subjective.

Accretion expense

Accretion expense for 2008 increased to $1,371,261, from $1,226,443 in 2007. 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 Predecessor Companies.

General and Administrative Expenses and Other

General and administrative expense increased from $2,172,332 for 2007 to $7,857,971 for 2008. The increase in general and administrative expense in 2008 related principally to the assumption of the corporate overhead of the Harvest Companies following the Harvest Acquisitions and the incurrence of certain transition costs following the acquisition. Included in general and administrative expenses during 2008 were non-cash compensation charges totaling $1,547,763 attributable to equity based stock awards made in contemplation of, or in connection with, the Harvest Acquisitions.

Impairments

Impairments increased to $1,693,440 for 2008 from $0 for 2007. The increase is due to significantly lower oil and gas commodity prices at year-end 2008.

Production and Ad Valorem Taxes

Production and Ad Valorem Taxes increased to $8,119,588 for 2008 from $5,769,828 for 2007. The increase is due to the increase in oil and gas revenues during 2008.

Other Income (Expense), Net

Net other income (expenses) totaled $4,865,660 of income for 2008 and $(22,976,697) of expenses in 2007. The following table sets forth the components of net other income (expenses) for 2008 and 2007:


	Combined 2008		Predecessor 2007
Commodity derivative income (expense)	$	20,073,134	$	(12,019,439)
Interest income		115,414		181,304
Interest expense		(15,322,888)		(11,138,562)
	$	4,865,660	$	(22,976,697)

As more fully described below, the changes in other income (expense), net, was principally attributable to a decrease in commodity pricing during the fourth quarter of 2008 which resulted in an increase in commodity derivative income. The increase in interest expense during 2008 was attributable to the debt financing for the Harvest Acquisitions.

Commodity Derivative Income (Expense)

Commodity derivative income increased to a gain of $20,073,134 for 2008 from a loss of $(12,019,439) for 2007. Pursuant to the terms of the Wayzata Credit Agreement and the Revolving Credit Agreement, we have entered into certain derivative contracts and entered into additional derivative contracts during September 2008 to reduce the impact of changes in the prices of oil and natural gas. The commodity derivative income during 2008 reflects the extreme volatility of crude oil and natural gas prices during 2008, in particular, the sharp drop in oil and gas prices during the fourth quarter of 2008.

Interest Income (Expense), Net

Interest income (expense), net, reflects interest incurred on debt under the Wayzata Credit Agreement and the Revolving Credit Agreement. Net interest expense increased to $15,322,888 in 2008 from $11,138,562 in 2007. 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.

Our income tax provision increased to $10,311,954 for 2008 from $0 in 2007. 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 rate for 2008 was 37%. 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. We expect to fund our operations and capital expenditures and satisfy our debt service obligations through operating cash flow, borrowings under our Revolving Credit Agreement and cash on hand.

However, as noted, Wayzata has alleged certain financial covenant defaults that we dispute. As a result of Wayzata’s notice of default, Macquarie has provided a notice of default and has denied our requests to draw additional borrowings under our Revolving Credit Agreement. As a result of such notices of default and our inability to arrive at a mutually acceptable forbearance agreement with Wayzata and Macquarie, on March 31, 2009, we filed petitions for protection under Chapter 11. Pending our establishment of a DIP financing facility, we will not have access to further borrowing which may result in curtailment of certain planned operations.

We had a cash balance of $5,677,994 and a working capital deficit of $(10,528,527) at December 31, 2008 as compared to a cash balance of $4,207,149 and a working capital deficit of $(30,566,357) at December 31, 2007. The working capital deficit for 2007 was attributed to the debt under the Revolving Credit Agreement being classified as a current liability. At December 31, 2007 and 2008, we were considered in default and the bank had not waived the covenants that were considered in default.

Net cash flow from operations was a positive $15,005,948 for the Successor Company for the period July 15, 2008 to December 31, 2008 and $10,114,083 for the Predecessor Companies for the period January 1, 2008 to July 14, 2008 for a combined total of $25,120,031 for 2008 compared to $17,039,417 for 2007 for the Predecessor Companies.

Net cash flow from financing activities totaled $1,320,464 for the Successor Company for the period July 15, 2008 to December 31, 2008 and net cash flow used in financing activities for the Predecessor Companies for the period January 1, 2008 to July 14, 2008 was $6,043,276 for a combined total used in financing activities of $4,722,812 during 2008, primarily from distributions made to the principal owners of the Predecessor Companies and repayments of debt. Net cash used in investing activities was $10,675,277 for the Successor Company for the period July 15, 2008 to December 31, 2008 and $5,214,956 for the Predecessor Companies for the period January 1, 2008 to July 14, 2008 for a combined total of $15,890,233 during 2008, primarily relating to the payment for the acquisitions and additions to the oil and gas properties.

We have 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, 2008, we had $108.7 million of indebtedness outstanding, consisting of $95.8 million (includes debt discount of $1.7 million) under the Wayzata Credit Agreement, $12.5 million under the Revolving Credit Agreement and $0.7 million under shareholder loans.

We believe that our cash flows from operations and cash on hand are sufficient to support our liquidity needs for 2009 and beyond. However, with the steep drop in oil and natural gas prices during the second half of 2008 and the unavailability of borrowings under our Revolving Credit Facility, we do not believe that our operations and available resources will support our planned exploration, development and acquisition activities during 2009 and, accordingly, we plan to defer our planned activities in that regard until market conditions improve and are undertaking cost cutting efforts to improve profitability and cash flow. Further, while we believe that our current operating cash flows will be adequate to support existing operations and service existing indebtedness, reduced revenues and profitability resulting from lower oil and natural gas prices have resulted in our lenders providing the previously described notices of noncompliance with certain financial covenants under our existing credit facilities. While we are attempting to restructure or refinance our debt under our Chapter 11 case, there is no assurance that we will be able to arrive at a satisfactory arrangement to restructure our current debt in which case we may be required to seek additional financing to refinance that debt or risk liquidation of our assets on terms that will likely not be in the best interests of our shareholders. We have no commitments to provide 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.

Debt

Outstanding debt at December 31, 2008, totaling $108.7 million, consisted of (1) $97.5 million less debt discount of $1.7 million owing to Wayzata under the Wayzata Credit Agreement, (2) $12.5 million owing to Macquarie under the Revolving Credit Agreement and (3) $0.7 million owed to affiliates under promissory notes.

As part of the Harvest Acquisitions, we assumed and amended the existing credit facilities of the Harvest Companies with Macquarie, entered into the Wayzata Credit Agreement pursuant to which we borrowed $97.5 million and borrowed $12.5 million under the Revolving Credit Agreement. The amounts owing under the prior credit facilities of the Harvest Companies with Macquarie were repaid in full from proceeds of the Harvest Acquisitions.

The Revolving Credit Agreement provides for reserve-based loans of up to $25 million (including up to $13 million which will be available toward outstanding letters of credit), 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.

Letters of credit totaling approximately $11.5 million were outstanding at December 31, 2008 and reduce amounts available to be drawn under the Revolving Credit Agreement.

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.

Capital Expenditures and Commitments

Our capital spending for 2008 was $116,358,276 which included the acquisition of the Harvest Companies for $103,652,560 in net cash. The balance of our capital spending during 2008 related principally to our drilling, development, recompletion and workover budget.

During 2008, our capital expenditures for drilling, development, recompletion and workover projects totaled $12.2 million.

In light of the our pending Chapter 11 case, the current economic outlook and commodity prices, we intend to limit our 2009 capital expenditures to a level that can be funded with cash flow from operations. Subject to the availability of DIP financing, we may, however, expand our capital expenditures based on improvements in commodity prices and the general economic outlook. Our 2009 capital budget, which at this time is expected to be approximately $9.2 million, 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.

The following table details our long-term debt and contractual obligations as of December 31, 2008:


	Payments due by period
	Total		2009		2010 – 2011		2012 – 2013		Thereafter
Debt (includes discount of $1,740,250)	$	-	$	-	$	110,028,878	$	-	$	-
Debt – related parties (includes current portion)		-		276,718		410,826		-		-
Operating leases		795,200		217,275		428,543		149,382		-
Capital leases		-		-		-		-		-
Asset retirement obligations		-		-		1,980,000		1,220,000		26,388,000
Performance bonds		-		-		-		-		-
Total	$	795,200	$	493,993	$	112,848,247	$	1,369,382	$	26,388,000

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, 2008, commodity derivative instruments were in place covering approximately 53% 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.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements or guarantees of third party obligations at December 31, 2008.

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.

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. Following the Harvest Acquisitions, we put in place additional commodity derivative instruments to comply with the terms of our Revolving Credit Agreement bringing our derivative position at December 31, 2008 to approximately 76% of crude oil volumes and 51% of natural gas volumes. Please refer to Note 6 “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, 2008, we had entered into the following natural gas derivative instruments:


	NYMEX Contract Price Per MMBtu
	Fixed-Price Swaps			Put Options			Call Options
	MMBtu	Weighted Average Fixed Price		Volume in MMBtus	Weighted Average Stike Price		Volume in MMBtus	Weighted Average Strike Price

Period
2009	101,375	$	7.14	76,820	$	6.93	-	-
2010	732,690	$	7.50	143,100	$	6.50
2011	321,385	$	6.85	143,100	$	6.50	-	-
2012	265,717	$	6.85	143,100	$	6.50	-	-

As of December 31, 2008, we had entered into the following crude oil derivative instruments:


	NYMEX Contract Price Per Bbl
	Fixed-Price Swaps			Put Options			Call Options
	MMBtu	Weighted Average Fixed Price		Volume in MMBtus	Weighted Average Stike Price		Volume in MMBtus	Weighted Average Strike Price

Period
2009	17,784	$	58.50	3,294	$	50.00	-	-
2010	141,398	$	58.51	49,335	$	54.63	45,701	75.00
2011	294,959	$	92.05	26,484	$	50.00	-	-
2012	68,461	$	56.19	26,484	$	50.00	-	-

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, 2008, total debt included approximately $12.5 million of floating-rate debt. As a result, our annual interest cost in 2009 will fluctuate based on short-term interest rates on what is presently approximately ten percent of our total debt outstanding at December 31, 2008.

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 56 of this report.

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Previously disclosed. See Form 8-K/A Amendment No. 1, filed October 16, 2007.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation as of December 31, 2008 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.

Our chief executive officer and our principal financial officer reviewed whether the restatement of our financial results for the fiscal year ended December 31, 2008 affected their conclusions that our disclosure controls and procedures, as of December 31, 2008, were effective in timely alerting them to material company information required to be included in our periodic filings with the SEC. In connection with their review, our chief executive officer and chief financial officer noted that our decision to restate our financial results did not call into question whether the relevant information was recorded, processed, summarized or reported within the time periods specified in the SEC's rules and forms. It also did not involve any issue about whether information required to be disclosed was accumulated and communicated to our chief executive officer and chief financial officer to allow timely decisions regarding required disclosure. Rather, the restatements resulted from changes to preliminary estimates and allocations relating to the acquisition of the Harvest Companies. Therefore, based on that review, our chief executive officer and our principal financial officer determined that their prior conclusions, that our disclosure controls and procedures were effective as of December 31, 2008, had not changed.

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, 2008, 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. In conducting its assessment, as noted regarding the effectiveness of disclosure controls and procedures, management determined that the restatement of our financial statements as a result of changes to preliminary estimates and allocations relating to the acquisition of the Harvest Companies did not arise from, or reflect, any material weakness any internal control over financial reporting. Based on our assessment, management has concluded that our internal control over financial reporting at December 31, 2008, were 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 2008 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	60	Chief Executive Officer and Chairman
Andrew Clifford	54	President and Director
Edward Hebert	36	Vice President – Finance
Kevin Smith	64	Director
Rex White	76	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.

Marvin Chronister, a prior director, submitted his resignation as a director effective April 1, 2009.

Advisory Director

On October 8, 2007, we appointed J.W. “Bill” Rhea 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 the President and Chief Executive Officer of privately-held Gulf Energy Exploration Corp. of Austin, Texas.

Key Employees

In connection with the Harvest Acquisitions, we retained the following key operating personnel of the Harvest Companies:

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 Alternext US and SEC rules. Each of the committees has a written charter approved by the board.

Audit Committee

The audit committee is composed of two directors, Messrs. Smith and White, each of whom meets the independence and financial literacy requirements as defined by applicable NYSE Alternext US 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, which is appointed by the Board, is composed of two non-employee, independent directors as defined by applicable NYSE Alternext US 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 Alternext US 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. 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.

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 2008. To our knowledge, all of the filing requirements were satisfied on a timely basis in fiscal year 2008. 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 2008 and 2007 by our named executive officers. There was no compensation paid in 2006 to our Chief Executive Officer or any other officers or employees of the company:


Name and Principal Position	Year	Salary ($)		Bonus ($)	Stock Awards ($)		Option Awards ($)	Non-Equity Incentive Plan Compensation ($)	Change in PensionValue and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)	Total ($)
Thomas Cooke, CEO	2008	180,000	⁽²⁾	—	—		—	—	—	—	180,000
	2007	64,590	⁽¹⁾	—	—		—	—	—	—	64,590
	2006	—		—	—		—	—	—	—	—
Andy Clifford, President	2008	180,000	⁽²⁾	—	—		—	—	—	—	180,000
	2007	62,437	⁽¹⁾	—	300,000	⁽³⁾	—	—	—	—	362,437
	2006	—		—	—		—	—	—	—	—
Edward Hebert, Vice President – Finance ⁽⁴⁾	2008	41,523		—	—		—	—	—	—	41,523
	2007	—		—	—		—	—	—	—	—
	2006	—		—	—		—	—	—	—	—

(1)

Represents accrued but unpaid compensation as of December 31, 2007, pursuant to employment agreements effective in September 2007. Upon closing of the Harvest Acquisitions, we delivered a promissory note evidencing the accrued but unpaid compensation, along with other amounts owing, which note is repayable, with interest accruing at 10% per annum, in equal monthly installments over three years.

(2)

Includes $112,500 of salary accrued and owing to each of Mr. Cooke and Mr. Clifford on the closing of the Harvest Acquisitions, which amounts are included in the promissory notes described in note 1 above.

(3)

Represents the fair value of common stock issued to Mr. Clifford pursuant to an Employment Agreement and a Stock Grant Agreement. Mr. Clifford was granted 2.5 million shares of common 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) we 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 our President on the first anniversary of the commencement of his employment.

(4)

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, the Company’s 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, 2008, no awards had been made under the 2008 Plan.

Directors

The following table sets forth the compensation paid to directors during 2008:


	Fees Earned or Paid in Cash ($)	Stock Awards ($) (1)	Option Awards ($)	Non-Equity incentive Plan Compensation ($)	All other Compensation ($)	Total ($)
Kevin Smith	—	—	—	—	—	—
Rex White	—	—	—	—	—	—
Marvin Chronister ⁽²⁾	—	30,000	—	—	—	30,000

(1)

Represents the fair value of common stock issued to Mr. Chronister. During 2008, Mr. Chronister was issued 30,000 shares of common stock as compensation for his service as Chairman of the Audit Committee of the Board of Directors and 10,000 shares for extraordinary services to the Board.

(2)

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 April 1, 2009, 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 ⁽³⁾⁽⁴⁾	6,145,422	36.4%
Andrew C. Clifford ⁽⁴⁾⁽⁵⁾	2,638,598	15.6%
Kevin Smith ⁽⁶⁾	253,643	1.5%
Rex H. White	52,500	*
Edward Hebert	--	*
Macquarie Americas Corp. ⁽⁷⁾	3,300,000	19.5%
All directors and officers as a group (5 persons)	9,090,163	53.8%

_________

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 April 1, 2009.

(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 109,148 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.

(7)

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 and Stock Purchases

Thomas F. Cooke, our principal shareholder and Chairman and Chief Executive Officer has, from time to time, loaned funds to the company and purchased shares of common stock to support our operations.

Amounts loaned by Mr. Cooke initially accrued interest at 12.5% and were repayable from operations when they become available. Loans payable to Mr. Cooke totaled $474,513 at December 31, 2007 and $563,412 at July 14, 2008, the date of the Harvest Acquisitions. We repaid $100,000 owing to Mr. Cooke at the time of the Harvest Acquisitions and delivered a Subordinated Promissory Note evidencing the balance of the amounts owing to Mr. Cooke, totaling $463,412, plus accrued salary of $157,500. The Subordinated Promissory Note is payable, with interest accruing at 10%, in equal monthly installments of $17,247.55 over three years. At December 31, 2008, the principal balance owing to Mr. Cooke pursuant to the Subordinated Promissory Note totaled $551,920.

In December 2007, Andy Clifford, our President, purchased from the company 100,000 shares of common stock for $100,000.

At July 14, 2008, the date of the Harvest Acquisitions, we delivered a Subordinated Promissory Note to Andy Clifford in the amount of $157,500 evidencing accrued salary owed to Mr. Clifford. The Subordinated Promissory Note to Mr. Clifford is payable, with interest accruing at 10%, in equal monthly installments of $4,375 over three years. At December 31, 2008, the principal balance owing to Mr. Clifford pursuant to the Subordinated Promissory Note totaled $135,625.

Transactions with Harvest Holdings

Harvest Holdings, LLC is the lessor under an office lease for the Harvest Companies’ principal offices located in Covington, Louisiana. The lease was originally executed November 28, 2005 for a term of three years, with options to renew the lease up to three times for successive three-year periods. The base monthly rental for the office lease is $11,000. Additionally, the Harvest Companies pay their allocable share of property taxes, insurance and common area maintenance. Harvest Holdings, LLC is controlled by certain former members of the Harvest Companies, including Barry Salsbury who served as a principal officer of our company from the closing of the Harvest Acquisition until his retirement in January 2009. Lease payments to Harvest Holdings during 2008 totaled $58,098.

Harvest Holdings, LLC is also a party to a Bareboat Charter Agreement with the Harvest Group originally executed December 28, 2006, pursuant which the Harvest Group agreed to charter a vessel for a period of three years. Pursuant to the charter agreement, the Harvest Group pays a monthly fee equal to $10,000 and additional fees and expenses related to maintenance, repair, taxes and permits. Fees payable to Harvest Holdings under the Bareboat Charter Agreement during 2008 totaled $60,000.

Transactions with Macquarie and Affiliates

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 5.3% during 2008. Interest paid to Macquarie Bank Limited totaled approximately $9,060,000 during 2008. At December 31, 2008, we owed a total of $12,528,878 to Macquarie Bank Limited under the Revolving Credit Agreement.

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, 2008 and 2007 and fees billed for other services rendered by that firm during those periods.


	2007		2008
Audit fees ⁽¹⁾	$	31,610	$	71,990
Audit related fees		-		-
Tax fees		-		-
All other fees		-		-
Total	$	31,610	$	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 54 of this report.

Exhibits


		Incorporated by Reference
Exhibit Number		Incorporated by Reference			Filed Herewith
Exhibit Number	Exhibit Description	Form	Date Filed	Number	Filed Herewith
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
23.1	Consent of Malone & Bailey, P.C.				X
23.2	Consent of LaPorte Sehrt Romig Hand				X
31.1	Section 302 Certification of CEO				X
31.2	Section 302 Certification of CFO				X
32.1	Section 906 Certification of CEO				X
32.2	Section 906 Certification of CFO				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: May 20, 2009	By:	/s/ Thomas F. Cooke
		Thomas F. Cooke
		Chairman and Chief Executive Officer

SARATOGA RESOURCES, INC.

INDEX TO FINANCIAL STATEMENTS


Reports of Independent Registered Public Accounting Firms	F-1

Consolidated and Combined Balance Sheets as of December 31, 2008 (Successor) and December 31, 2007 (Predecessor)	F-4

Consolidated and Combined Statement of Operations for the period July 15, 2008 through December 31, 2008 (Successor), and the period January 1, 2008 through July 14, 2008 (Predecessor), and for the year ended December 31, 2007 (Predecessor)	F-5

Consolidated and Combined Statements of Members’ Capital (Deficit) for the year ended December 31, 2007 (Predecessor) and for the period January 1, 2008 through July 14, 2008 (Predecessor) and Consolidated Statements of Equity for the year ended December 31, 2008 (Successor)	F-6

Consolidated and Combined Statement of Cash Flows for the period July 15, 2008 through December 31, 2008 (Successor), and the period January 1, 2008 through July 14, 2008 (Predecessor), and for the year ended December 31, 2007 (Predecessor)	F-7

Notes to Consolidated and Combined Financial Statements	F-8

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, 2008, and the related consolidated statements of operations, shareholders’ equity, and cash flows 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 and financial statement schedules based on our audit.

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, 2008, and the results of their operations and their cash flows for the period 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, the accompanying consolidated financial statements have been restated.

As discussed in Note 5 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 successor period ended 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 4 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/MALONE & BAILEY, PC

www.malone-bailey.com

Houston, Texas

April 15, 2009, except for Note 3 as to which the date is May 20, 2009

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 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 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 audits 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 their operations and their 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

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To the Members

THE HARVEST GROUP, LLC

HARVEST OIL & GAS, LLC

Report of Independent Registered Public Accounting Firm

We have audited the accompanying combined balance sheet of THE HARVEST GROUP, LLC and HARVEST OIL & GAS, LLC (the Companies) as of December 31, 2007, and the related combined statement of operations, changes in members’ deficit and cash flows for year then ended. These financial statements are the responsibility of the Companies’ management. Our responsibility is to express an opinion on these 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of THE HARVEST GROUP, LLC and HARVEST OIL & GAS, LLC as of December 31, 2007, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

[f10ka123108003.gif]

A Professional Accounting Corporation

Metairie, LA

February 11, 2008

F-3

Saratoga Resources, Inc.

(DEBTOR AND DEBTOR-IN-POSSESSION)

BALANCE SHEETS


	December 31,		December 31,
	2008		2007
	(Successor)		(Predecessor)
	(Consolidated)		(Combined)
ASSETS	(Restated)
Current assets:
Cash and cash equivalents	$	5,677,994	$	4,207,149
Accounts receivable		7,392,887		13,272,988
Prepaid expenses and other		1,186,090		1,019,123
Due from related parties		-		59,285
Derivative asset		346,058		-
Total current assets		14,603,029		18,558,545

Property and equipment:
Oil and gas properties - proved (successful efforts method)		154,449,346		40,756,840
Other		504,470		251,888
		154,953,816		41,008,728
Less: Accumulated depreciation, depletion and amortization		(7,018,203)		(12,022,256)
Total property and equipment, net		147,935,613		28,986,472

Derivative asset		9,795,194		-
Other assets, net		4,078,889		1,570,604
Total assets	$	176,412,725	$	49,115,621

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	11,869,017	$	3,776,923
Revenue and severance tax payable		783,459		-
Accrued liabilities		1,705,408		2,022,490
Short-term notes payable		581,836		28,878,289
Current portion of long-term debt – related parties		259,488		339,460
Deferred taxes		9,932,348		-
Derivative liabilities		-		14,107,740
Total current liabilities		25,131,556		49,124,902

Long-term liabilities
Asset retirement obligation		9,124,717		12,375,931
Long-term debt, net of discount of $1,740,250		108,288,628		-
Long-term debt – related parties		428,057		-
Total long-term liabilities		117,841,402		12,375,931

Commitment and contingencies (see notes)

Stockholders' equity (deficit):
Common stock, $0.001 par value; 100,000,000 shares authorized 16,877,792 shares issued and outstanding at December 31, 2008		16,878		-
Additional paid-in capital		19,309,658		-
Members’ deficit		-		(12,385,212)
Retained earnings		14,113,231		-

Total stockholders' equity (deficit)		33,439,767		(12,385,212)

Total liabilities and stockholders' equity	$	176,412,725	$	49,115,621

See notes to consolidated and combined financial statements.

F-4

Saratoga Resources, Inc.

(DEBTOR AND DEBTOR-IN-POSSESSION)

STATEMENTS OF OPERATIONS


	For the Periods
	July 15, 2008 - December 31, 2008 (Successor)		January 1, 2008 - July 14, 2008 (Predecessor)		For the Year Ended December 31, 2007 (Predecessor)
	(Consolidated)		(Combined)		(Combined)
	(Restated)
Revenues:
Oil and gas revenues	$	22,423,746	$	46,475,559	$	57,414,900
Other revenues		1,419,707		1,116,318		339,778

Total revenues		23,843,453		47,591,877		57,754,678

Operating Expense:
Lease operating expense		10,666,669		17,356,190		25,180,731
Depreciation, depletion and amortization		5,324,763		2,521,020		7,402,479
Accretion expense		534,168		837,094		1,226,443
General and administrative		3,865,046		3,992,925		2,172,332
Impairments		1,693,440		-		-
Taxes other than income		2,510,548		5,609,040		5,769,828

Total operating expenses		24,594,634		30,316,269		41,751,813

Operating income (loss)		(751,181)		17,275,608		16,002,865

Other income (expense):
Commodity derivative income (expense), net		39,133,737		(19,060,603)		(12,019,439)
Interest income		67,578		47,836		181,304
Interest expense		(10,350,918)		(4,971,970)		(11,138,562)

Total other income (expense)		28,850,397		(23,984,737)		(22,976,697)

Net income (loss) before income taxes		28,099,216		(6,709,129)		(6,973,832)

Income tax provision (benefit)
Current		(3,386,272)		-		-
Deferred		13,698,226		-		-

Net income (loss)	$	17,787,262	$	(6,709,129)	$	(6,973,832)

Net income per share:
Basic	$	1.35	$	-	$	-

Diluted	$	1.24	$	-	$	-

Weighted average number of common shares outstanding:
Basic		13,205,945		-		-

Diluted		14,334,725		-		-

See notes to consolidated and combined financial statements.

F-5

Saratoga Resources, Inc.

(DEBTOR AND 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, 2006	-	$	-	$	-	$	-	$	(2,497,451)	$	-

Members’ distribution	-		-		-		-		(2,913,929)		-

Net loss	-		-		-		-		(6,973,832)		-

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) (Restated)
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

See notes to consolidated and combined financial statements.

F-6

Saratoga Resources, Inc.

(DEBTOR AND DEBTOR-IN-POSSESSION)

STATEMENTS OF CASH FLOWS


	For the Periods
	July 15, 2008 - December 31, 2008 (Successor)		January 1, 2008 - July 14, 2008 (Predecessor)		For the Year Ended December 31, 2007 (Predecessor)
	(Consolidated)		(Combined)		(Combined)
	(Restated)
Cash flows from operating activities:
Net income (loss)	$	17,787,262	$	(6,709,129)	$	(6,973,832)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		5,324,763		2,521,020		7,402,479
Accretion expense		534,168		837,094		1,226,443
Impairments		1,693,440
Amortization of debt issuance costs		440,130		-		303,833
Amortization of debt discount		313,816		2,762,698		6,162,632
Commodity derivative income		(39,404,983)		15,155,991		11,186,596
Stock-based compensation		1,547,763		-		-
Deferred taxes		9,838,829		-		-
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		10,567,925		(5,252,765)		(2,630,233)
(Increase) decrease in prepaids and other		722,446		(1,214,106)		772,222
Increase (decrease) in accounts payable		8,089,827		(596,719)		1,214,309
Increase (decrease) in revenue and severance tax payable		(2,886,879)		3,670,338		-
Increase (decrease) in accrued liabilities		437,441		(1,116,005)		(1,905,208)
Increase (decrease) in due to related parties		-		55,666		280,176
Net cash provided by operating activities		15,005,948		10,114,083		17,039,417

Cash flows from investing activities:
Additions to oil and gas property		(12,236,991)		(4,957,082)		(8,072,906)
Proceeds from escrow held on purchase of oil and gas property		-		-		5,182,321
Acquisition of Harvest Companies		2,030,440		-		-
Additions to other property and equipment		(211,532)		(14,362)		(12,793)
Additions to other assets		(257,194)		(243,512)		(411,544)
Net cash used in investing activities		(10,675,277)		(5,214,956)		(3,314,922)

Cash flows from financing activities:
Distributed capital		-		(3,811,194)		(2,913,929)
Repayment of short-term notes payable		(1,122,267)		(2,232,082)		(7,094,615)
Proceeds from debt borrowings		4,345,878		-		-
Proceeds from debt borrowings - related party		687,545		-		-
Repayment of debt borrowings - related party		(482,942)		-		-
Debt issuance cost		(2,107,750)		-		(303,833)
Net cash provided (used) in financing activities		1,320,464		(6,043,276)		(10,312,377)

Net increase (decrease) in cash and cash equivalents		5,651,135		(1,144,149)		3,412,118

Cash and cash equivalents - beginning of period		26,859		4,207,149		795,031

Cash and cash equivalents - end of period	$	5,677,994	$	3,063,000	$	4,207,149

Supplemental disclosures of cash flow information:
Cash paid for interest	$	9,567,516	$	2,209,272	$	5,049,657

Non-cash investing and financing activities:
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-7

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, the Company’s 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 160 acre leasehold, running through October 2009, in Dawson County, Texas, adjoining the Adcock Farms No. 1 well site.

Restructuring and Basis of Presentation

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.

The Harvest Acquisition was accounted for under the purchase method of accounting pursuant to Statements of Financial Accounting Standards (SFAS) 141, 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, 2008, and for the 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 and 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 at December 31, 2007, and for the period January 1, 2008 to July 14, 2008, include the financial statements of Harvest Oil and Gas, LLC and The Harvest Group, LLC. All significant intercompany balances and transactions have been eliminated.

F-8

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.

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 do not designate any future price risk management activities as accounting hedges under SFAS No. 133, 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).”

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

F-9

Concentration of Credit Risk

The Company’s 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.

During the year ended December 31, 2008, the Company sold 100% of its products to one customer. At December 31, 2008, amounts due from that customer totaled $3,420,295.

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, 2008, the Company 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, the Company considers 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, 2008, 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

Development Costs

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

F-10

Depletion and Amortization

Depreciation of Other Property and Equipment

Impairment of Properties, Plants and Equipment

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.

Recently Issued Accounting Standards and Developments

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include changes to the pricing used to estimate reserves utilizing a 12-month average price rather than a single day spot price which eliminates the ability to utilize subsequent prices to the end of a reporting period when the full cost ceiling was exceeded and subsequent pricing exceeds pricing at the end of a reporting period, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, and permitting disclosure of probable and possible reserves. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports on Form 10-K for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. The Company is currently assessing the impact that the adoption will have on the Company’s disclosures, operating results, financial position and cash flows.

F-12

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles”, (SFAS 162), which identifies a consistent framework for selecting accounting principles to be used in preparing financial statements for nongovernmental entities that are presented in conformity with United States generally accepted accounting principles (GAAP). The current GAAP hierarchy was criticized due to its complexity, ranking position of FASB Statements of Financial Accounting Concepts and the fact that it is directed at auditors rather than entities. SFAS 162 will be effective 60 days following the United States Securities and Exchange Commission’s (SEC’s) approval of the Public Company Accounting Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. The FASB does not expect that SFAS 162 will have a change in current practice, and the Company does not believe that SFAS 162 will have an impact on operating results, financial position or cash flows.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS 161”), an amendment of FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). SFAS 161 is effective beginning January 1, 2009 and required entities to provide expanded disclosures about derivative instruments and hedging activities including (1) the ways in which an entity uses derivatives, (2) the accounting for derivatives and hedging activities, and (3) the impact that derivatives have (or could have) on an entity’s financial position, financial performance, and cash flows. SFAS 161 requires expanded disclosures and does not change the accounting for derivatives. The Company is currently evaluating the impact of SFAS 161, but we do not expect the adoption of this standard to have a material impact on our financial results.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”). SFAS 141(R) replaces SFAS 141, “Business Combinations”, however it retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS 141(R) requires an acquirer to recognize the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, be measured at their fair values as of that date, with specified limited exceptions. Changes subsequent to that date are to be recognized in earnings, not goodwill. Additionally, SFAS 141 (R) requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the noncontrolling interests in the acquiree, at the full amounts of their fair values. SFAS 141(R) is effective for business combinations occurring in fiscal years beginning on or after December 15, 2008. The Company will apply the requirements of SFAS 141(R) upon its adoption on January 1, 2009 and is currently evaluating whether SFAS 141(R) will have an impact on its financial position and results of operations.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits companies to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS 159, a company may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at initial recognition of the asset or liability or upon a remeasurement event that gives rise to new-basis accounting. The decision about whether to elect the fair value option is applied on an instrument-by-instrument basis, is irrevocable and is applied only to an entire instrument and not only to specified risks, cash flows or portions of that instrument. SFAS No. 159 does not affect any existing accounting standards that require certain assets and liabilities to be carried at fair value nor does it eliminate disclosure requirements included in other accounting standards. The Company adopted SFAS No. 159 effective January 1, 2008 and did not elect the fair value option for any existing eligible items.

F-13

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not impose fair value measurements on items not already accounted for at fair value; rather it applies, with certain exceptions, to other accounting pronouncements that either require or permit fair value measurements. Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal or most advantageous market. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In February 2008, the FASB issued FASB Staff Position No. 157-2, Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”), which delays the effective date of SFAS 157 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, until fiscal years beginning after November 15, 2008. These non-financial items include assets and liabilities such as non-financial assets and liabilities assumed in a business combination, reporting units measured at fair value in a goodwill impairment test and asset retirement obligations initially measured at fair value. Effective January 1, 2008, the Company adopted SFAS 157 for fair value measurements not delayed by FSP FAS No. 157-2. The adoption resulted in additional disclosures as required by the pronouncement (See Note 13 “ Fair Value Measurements”) related to our fair value measurements for oil and gas derivatives and marketable securities but no change in our fair value calculation methodologies. Accordingly, the adoption had no impact on our financial condition or results of operations.

NOTE 3. RESTATEMENT OF FINANCIAL STATEMENTS

On May 19, 2009, management of Saratoga Resources, Inc. concluded that the previously filed consolidated financial statements of the Company as of and for the year ended December 31, 2008 needed to be restated.

The restatement results from errors in accounting for the acquisition (the “Harvest Acquisition”) of Harvest Oil & Gas, LLC and The Harvest Group, LLC. The Company, in reporting the Harvest Acquisition in its Form 10-K for the year ended December 31, 2008, made certain estimates as permitted by SFAS No. 141 “Business Combinations.” Subsequent to filing the Form 10-K, the Company reassessed those estimates including the application of SFAS 109, Accounting for Income Taxes related to the Harvest Acquisition. During this reassessment, the Company identified an error whereby the tax basis of its oil and gas properties was not properly adjusted resulting in an error in tax depletion, which caused the deferred tax assets to be overstated by $3,663,471. In addition, the Company identified an error in the purchase price allocation related to the Harvest Acquisition. This error resulted in an overstatement of depletion and impairment expense by $4,015,067 and $978,221, respectively, which resulted in a corresponding understatement of net oil and gas properties of $4,993,288, a $3,865,729 overstatement of deferred tax liabilities and an overstatement of income tax expense of $202,258. In addition, the revised statements of operations and cash flows will reflect a reclassification of accretion expense from depletion, where it was previously reported.

F-14

The following is the restated consolidated balance sheet as of December 31, 2008, and the restated consolidated statements of operations, shareholders’ equity, and cash flows for the period from July 14, 2008 through December 31, 2008 compared to the previously reported amounts:

RESTATED
CONSOLIDATED BALANCE SHEET
AS OF DECEMBER 31, 2008
(SUCCESSOR)


	As Reported		Adjustments		Restated
ASSETS
Property and equipment:
Oil and gas properties - proved (successful efforts method)	$	151,047,857	$	3,401,489	$	154,449,346
Total property and equipment		151,552,327		3,401,489		154,953,816
Less: Accumulated depreciation, depletion and amortization		(8,610,002)		1,591,799		(7,018,203)
Total property and equipment, net		142,942,325		4,993,288		147,935,613

Other assets, net		7,742,360		(3,663,471)		4,078,889

Total assets	$	175,082,908	$	1,329,817	$	176,412,725

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Deferred taxes	$	13,798,077	$	(3,865,729)	$	9,932,348

Total current liabilities		28,997,285		(3,865,729)		25,131,556

Stockholders' equity (deficit):
Retained earnings		8,917,685		5,195,546		14,113,231

Total stockholders' equity		28,244,221		5,195,546		33,439,767

Total liabilities and stockholders' equity	$	175,082,908	$	1,329,817	$	176,412,725

F-15

RESTATED
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE PERIOD JULY 15, 2008 TO DECEMBER 31, 2008
(SUCCESSOR)


	As Reported		Adjustments		Restated
Operating Expense:
Depreciation, depletion and amortization	$	9,873,998	$	(4,549,235)	$	5,324,763
Accretion expense		-		534,168		534,168
Impairments		2,671,661		(978,221)		1,693,440

Total operating expenses		29,587,922		(4,993,288)		24,594,634

Operating income (loss)		(5,744,469)		4,993,288		(751,181)

Net income (loss) before income taxes		23,105,928		4,993,288		28,099,216

Income tax provision (benefit):
Current		473,125		(3,859,397)		(3,386,272)
Deferred		10,041,087		3,657,139		13,698,226

Net income	$	12,591,716	$	5,195,546	$	17,787,262

Net Income per share:
Basic	$	0.95	$	0.39	$	1.35

Diluted	$	0.88	$	0.36	$	1.24

RESTATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE PERIOD JULY 15, 2008 TO DECEMBER 31, 2008
(SUCCESSOR)


	As Reported		Adjustments		Restated
Cash flows from operating activities:
Net income (loss)	$	12,591,716	$	5,195,546	$	17,787,262
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		9,873,998		(4,549,235)		5,324,763
Accretion expense		-		534,168		534,168
Impairments		2,671,661		(978,221)		1,693,440
Deferred taxes		10,041,087		(202,258)		9,838,829

Net cash provided by operating activities	$	15,005,948	$	-	$	15,005,948

F-16

NOTE 4. GOING CONCERN

As shown in the accompanying financial statements, the Company had net income of $17.8 million for the period from July 15, 2008 to December 31, 2008, has retained earnings of $14.1 million and a working capital deficit of $10.5 million as of December 31, 2008 and has several significant future financial obligations. These conditions raise substantial doubt as to the Company’s ability to continue as a going concern. The financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.

The accompanying consolidated and combined financial statements do not reflect or provide for the consequences of our 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; and (4) as to operations, the effect of any changes that may be made to our business.

NOTE 5. HARVEST ACQUISITION

On July 14, 2008, the Company 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, the Company 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, the Company 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 the Company 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 the Company 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-17

The acquisition has been accounted for in accordance with the provisions of Statement of Financial Standards (“SFAS”) No. 141, “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 preliminary allocation of the purchase price was based upon valuation data as of July 14, 2008 and the estimates and assumptions are subject to change. The initial purchase price allocation may be adjusted within one year of the effective date of the acquisition for changes in estimates of the fair value of assets acquired and liabilities assumed based on the results of the purchase price allocation process. The preliminary allocation of the purchase price is as follows:


Current assets, including acquired cash of $3,063,000	$	22,932,346
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 and December 31, 2007 as if the Harvest Acquisition had occurred at the beginning of the periods.


Pro-Forma Information	Year Ended December 31,
	2008		2007
	(Restated)
Oil and gas revenue	$	68,899,305	$	57,414,900
Income from operations		16,524,427		16,002,865
Net income (loss)	$	11,078,133	$	(6,973,832)

Basic income (loss) per share	$	0.84	$	(0.53)
Diluted Income (loss) per share	$	0.77	$	(0.53)

Wayzata Credit Agreement

In conjunction with the acquisition of Harvest Oil and Harvest Group, on July 14, 2008, the Company 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, the Company granted to the Wayzata Lenders a second lien on substantially all of the Company’s 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, 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 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 the Company and Macquarie Bank Limited.

See “NOTE 15. SUBSEQUENT EVENTS” regarding certain notices of default given with respect to the Wayzata Credit Agreement.

F-18

Macquarie Credit Agreement

In conjunction with the acquisition of Harvest Oil and Harvest Group, on July 14, 2008, the Company entered into a Credit Agreement (the “Revolving Credit Agreement”) with Macquarie pursuant to which the Company 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, the Company 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, the Company granted to the Revolving Credit Lenders a first lien on substantially all of the Company’s assets, and each of its subsidiaries, including the Harvest Companies, agreed to guaranty all amounts owing under the Revolving Credit Agreement.

Pursuant to the terms of the Revolving Credit Agreement, the Company 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 the Company and the Wayzata Lenders.

See “NOTE 15. SUBSEQUENT EVENTS” regarding certain notices of default given with respect 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, the Company repaid $100,000 of advances from Thomas Cooke, the Company’s 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, the Company’s 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.

Employment Agreement and Stock Grant

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

F-19

The Company 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 the Company’s 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 cancelled.

NOTE 6. DEBT

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


	December 31,
	2008 (Successor)		2007 (Predecessor)
Senior secured revolving credit facility due 2010	$	-	$	28,224,169
Senior secured revolving credit facility due 2008		-		504,320
Senior secured revolving credit facility due 2011		12,528,878		-
20% subordinated secured note due 2011		95,759,750		-
Unsecured line of credit with a bank		-		149,800
Other		581,836
	$	108,870,464	$	28,878,289

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, 2008, the Company owed $12,528,878 under the Revolving Credit Agreement.

Letters of credit totaling approximately $11,502,768 million were outstanding at December 31, 2008 and reduce amounts available to be drawn under the Revolving Credit Agreement.

See “NOTE 15. SUBSEQUENT EVENTS” regarding notices of default giving regarding the Revolving Credit Agreement.

Subordinated secured note

F-20

The Company is 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 the Company’s 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.

See “NOTE 15. SUBSEQUENT EVENTS” regarding notices of default giving regarding the Wayzata Credit Agreement

NOTE 7. COMMODITY DERIVATIVE INSTRUMENTS

The Company periodically uses 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, 2008, the Successor Company recognized a realized loss of $271,246 in the Statement of Operations and the Predecessor Company recognized a realized loss of $3,904,613 for a combined realized loss of $4,175,859. During the year ended December 31, 2008, the Successor Company had an unrecognized gain of $39,404,983 and the Predecessor Company had an unrealized loss of $15,155,991 for a combined unrealized gain of 24,248,992 as the result of market-to-market valuations.

As of December 31, 2008, the Company 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	Stike Price		MMBtus	Strike Price
2009	101,375	$	7.14	76,820	$	6.93	-	-
2010	732,690	$	7.50	143,100	$	6.50
2011	321,385	$	6.85	143,100	$	6.50	-	-
2012	265,717	$	6.85	143,100	$	6.50	-	-

As of December 31, 2008, the Company 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	MBls	Fixed Price		MMBls	Stike Price		MBls	Strike Price
2009	17,784	$	58.50	3,294	$	50.00	-	-
2010	141,398	$	58.51	49,335	$	54.63	45,701	75.00
2011	284,746	$	91.56	26,484	$	50.00	-	-
2012	68,461	$	56.19	26,484	$	50.00	-	-

At December 31, 2008, the Company recognized an asset of $11,178,724 related to the estimated fair value of these derivative instruments.

F-21

NOTE 8. OIL AND GAS ASSETS:

Property and equipment consisted of the following at:


	December 31,
	2008 (Successor)		2007 (Predecessor)
	(Restated)
Oil and gas properties (proved):
Subject to amortization	$	154,449,346	$	40,756,840
Not subject to amortization
Development in progress		-		-
Total not subject to amortization		-		-
Gross oil and gas properties (proved)		154,449,346		40,756,840
Accumulated depreciation, depletion and amortization		(6,939,036)		(11,963,126)
Net oil and gas properties (proved)		147,510,310		28,793,714
Other property and equipment		504,470		251,888
Accumulated depreciation and amortization		(79,167)		(59,130)
Net other property and equipment		425,303		192,758
Net property and equipment	$	147,935,613	$	28,986,472

NOTE 9. ASSET RETIREMENT OBLIGATIONS

The Company accounts for plugging and abandonment costs in accordance with SFAS 143, Accounting for Asset Retirement Obligations.

The Company maintains 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 by the Company in the acquisition of oil and gas properties from the Predecessor Companies over certain fields.

At December 31, 2008 and 2007, the amount of the escrow account totaled $1,580,198 for the Successor Company and $945,604 for the Predecessor Companies, 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 January 1, 2007 (Predecessor)	$	11,149,488
Accretion expense		1,226,443
Additions		-
Revisions		-
Settlements		-
Balance at December 31, 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

F-22

NOTE 10. RELATED PARTY TRANSACTIONS

During the year ended December 31, 2008, the Company’s principal officers advanced funds, provided services and paid costs on behalf of the Company. As of December 31, 2008, the Company owed Thomas Cooke, the Company’s Chairman, Chief Executive Officer and principal shareholder, $551,920 and owed Andy Clifford, the Company’s President, $135,625 for their funding of acquisition expenses and deferred salary. The indebtedness to the principle shareholder bears interest at 10%.

NOTE 11. COMMITMENTS AND CONTINGENCIES

The Company has commitments under non-cancellable operating lease agreements for its office spaces located in Covington, Louisiana and Houston, Texas. Future minimum payments required under these leases as of December 31, 2008 were as follows:


Year ending December 31,
2009	$	217,275
2010		219,108
2011		209,435
2012		84,771
2013		64,611
Total minimum lease payments	$	795,200

Rent expense with respect to our lease commitments for office space 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. Rent expense for the year ended December 31, 2007 as predecessor was $127,475.

The Company is involved in litigation with a former customer of the Harvest Companies regarding payment for oil and gas products marketed by that customer. The Company has fully reserved for amounts owed by the customer and any outcome regarding this matter will not have an adverse effect on the Company’s financial position or results of operations.

In connection with the acquisition of the Harvest Companies, the Company, by agreement, assumed certain plugging and abandonment, reclamation, restoration, and clean up liabilities and obligations related thereto. To secure these liabilities, the Company maintains $11,502,768 million at December 31, 2008 in letters of credit with Macquarie. The letters of credit are secured by the various oil and gas properties maintained by the Company.

NOTE 12. COMMON STOCK

The following information relates to the common stock of the Successor Company.

F-23

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, 2008
	Income (Loss)		Weighted Average Common Shares Outstanding	Per Share




	(Restated)				(Restated)
Basic:
Income (loss) attributable to common stock	$	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	$	17,787,262	14,334,725	$	1.24

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 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.

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 2008 was $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.

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 2008 was $619,650. The unamortized stock-based compensation at December 31, 2008 was $757,350 and will be recorded over the requisite service period.

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.

F-24

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.

The following table summarizes information about restricted share activity for the year ended December 31, 2008 as previously described:


	Number of Restricted Shares	Weighted Average Grant Date Fair Value per Share
Outstanding at December 31, 2006	-	$	-
Granted	2,000,000		0.12
Forfeited	-		-
Vested	-		-
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

Stock-Based Compensation

In January 2006, the Company’s 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.

During 2008, the Company recorded stock-based compensation expense of $3,671,483 of which $69,653 was capitalized financing costs and $2,054,066 was recorded as a debt discount. The unamortized amount of stock-based compensation that has not been recorded as of December 31, 2008 was $1,139,850.

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 stock-based compensation expense recorded for this grant was $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 stock-based compensation expense recorded for this grant was $62,456 and was recorded as acquisition costs relating to the Harvest Acquisitions.

F-25

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 with a fair value of $2.55 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 stock-based compensation expense recorded at grant date was $2,054,066 and was recorded as a discount to the debt payable.

The following table presents the warrants outstanding at December 31, 2008:


	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, 2006		-		-		-	-		-
Granted		-		-		-	-		-
Exercised		-		-		-	-		-
Forfeited		-		-		-	-		-
Outstanding at December 31, 2007		-		-		-	-		-
Granted		1,085,516	$	0.07	$	1.96	4.5	$	2,855,238
Exercised		-		-		-	-		-
Forfeited		-		-		-	-		-
Outstanding at December 31, 2008		1,085,516	$	0.07	$	1.96	4.5	$	2,855,238
Exercisable at December 31, 2008		1,085,516	$	0.07	$	1.96	4.5	$	2,855,238

(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, 2008, the last reported sales price of our common stock on the OTC:BB was $2.70 per share.

The following table summarizes information about stock warrants outstanding and exercisable at December 31, 2008:


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	4.5	4.5
0.17	30,000	4.4	-
0.25	250,000	4.4	-
0.07	1,085,516	4.4	4.5

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-26

Our provision for income taxes at December 31, 2008 consisted of the following:


Current:
Federal	$	(3,859,397)
State		473,125
	$	(3,386,272)

Deferred:
Federal	$	13,698,226
State		-
	$	13,698,226

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


Income tax expense at U.S. federal statutory rate		35.0%
State and local income taxes, net of federal income tax benefit		1.1%
Temporary differences		0.6%
Provision for income taxes		36.7%

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


Deferred tax asset
Stock-based compensation	$	356,076
Debt issuance cost (amortization)		205,618
Impairment		592,704
Accretion		196,229
Deferred tax liability
Property and equipment (depletion)		(1,250,777)
Derivative hedging		(13,791,744)
Property and equipment (depreciation)		(6,332)
Deferred tax liability	$	(13,698,226)

At December 31, 2008, the Company had $11.0 million of federal net operating loss, or NOL, carryforwards; the federal NOL carryforwards have expiration dates through the year 2028.

At this time, the Company has not established a valuation allowance for uncertainties in realizing the benefit of tax loss and credit carryforwards, and other deferred tax assets; while the Company expects to realize the deferred tax assets at December 31, 2008, changes in estimates of future taxable income or in tax laws may alter this expectation.

NOTE 14. FAIR VALUE MEASUREMENTS

Certain of the Company's financial and nonfinancial assets and liabilities are reported at fair value in the accompanying balance sheets. Effective January 1, 2008, the Company adopted the provisions of SFAS No. 157 for its financial assets and liabilities. SFAS No. 157 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, SFAS No. 157 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. SFAS No. 157 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, Saratoga has not applied the provisions of SFAS No. 157 to its asset retirement obligations.

F-27

The following table provides fair value measurement information within the hierarchy for Saratoga's financial assets and liabilities at December 31, 2008:


	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	$	-	$	1,380,259	$	-	$	1,380,259
Oil and gas derivative swap contracts		-		8,760,993		-		8,760,993
Total	$	-	$	10,141,252	$	-	$	10,141,252

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

Notices of Default

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 the Macquarie Credit Agreement defining an event of default as an event or condition occurring which permits the holder of any material debt of to accelerate that obligation. Macquarie states in its notice of default that it is not initiating any action to exercise its rights and remedies available, though its right to do so is 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.

Chapter 11 Bankruptcy Filing

F-28

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.

The following summarizes the Company’s estimated total net proved reserves for the years in the three-year period ended December 31, 2008:


	Gas (Mef)	Oil (Bbls)	Mcfe
Estimated at December 31, 2005 (Predecessor)	10,414,000	1,888,000	21,742,000
Purchase, discoveries, extensions, and improved recovery, net of revisions of previous estimates	11,604,000	1,861,000	22,774,000
Production	(1,905,000)	(403,000)	(4,325,000)
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

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, 2008:


	2008 (Successor)		2007 (Predecessor)		2006 (Predecessor)
	(Restated)
Proved properties	$	154,449,346	$	40,756,840	$	37,990,764
Unproved properties		-		-		-
		154,449,346		40,756,840		37,990,764
Accumulated depreciation, depletion and amortization		(6,939,036)		(11,963,125)		(4,589,260)
Net capitalized costs	$	147,510,310	$	28,793,715	$	33,401,504

F-29

Costs incurred for oil and gas property acquisitions, exploration and development for each of the years in the three-year period ended December 31, 2008 are as follows:


	2008 (Successor)		2007 (Predecessor)		2006 (Predecessor)
	(Restated)
Acquisitions	$	146,861,318	$	-	$	11,975,518
Reimbursement of escrow held in acquisition		-		(5,182,321)		-
Overriding royalty interest given up to lender		-		-		(3,425,374)
Capitalized asset retirement obligation		-		-		7,598,408
Revisions to asset retirement obligation		(4,648,962)
Impairments		-		-		-
Exploration		-		-		-
Development		12,236,990		7,948,397		12,317,832
	$	154,449,346	$	2,766,076	$	28,466,384

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


	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)
	(Restated)				(Restated)
Oil and gas sales	$	22,423,746	$	46,475,559	$	68,899,305	$	57,414,900
Production costs		(10,666,669)		(17,356,190)		(28,022,859)		(25,180,731)
Exploration expenses		-		-		-		-
Depreciation, depletion and amortization		(5,245,596)		(2,507,086)		(7,752,682)		(7,373,867)
Impairments		(1,693,440)		-		(1,693,440)		-
Taxes other than income		(2,510,548)		(5,609,040)		(8,119,588)		(5,769,828)
Income before income taxes		2,307,493		21,003,243		23,310,736		19,090,474
Income tax provision*		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)	$	1,460,681	$	13,295,395	$	14,756,076	$	12,084,581

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

*Income tax provision for predecessor represents pro forma data using the Company’s 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 SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.” The information is based on estimates prepared by our petroleum engineering staff. 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

F-30

•

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 SFAS No. 69.

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.

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


(dollars in thousands)	2008 (Successor)		2007 (Predecessor)		2006 (Predecessor)
Future cash flows	$	402,022	$	608,792	$	318,731
Future production costs		(79,702)		(109,168)		(97,460)
Future development costs		(102,416)		(84,420)		(45,885)
Future net cash flows before income taxes		219,904		415,204		175,386
Future income tax expense		(76,967)		-		-
Future net cash flows before 10% discount		142,937		415,204		175,386
10% annual discount for estimating timing of cash flows		(44,943)		(115,137)		(29,962)
Standardized measure of discounted future net cash flows	$	97,994	$	300,067	$	145,424

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, 2008:


(dollars in thousands)	2008 (Successor)		2007 (Predecessor)		2006 (Predecessor)
Beginning of year	$	300,067	$	145,424	$	141,267
Sales of oil and gas produced, net of production costs		(36,956)		(26,463)		(12,789)
Net change in prices and production costs		(190,296)		77,932		(17,046)
Extension, discoveries, and improved recovery, less related costs		107,522		154,076		35,784
Development costs incurred during the year		12,942		2,305		6,302
Net change in estimated future development costs		(30,937)		(40,841)		(11,169)
Revisions of previous quantity estimates		(25,355)		(8,756)		(8,494)
Net change from purchases and sales of minerals in place		-		-		3,048
Net change in income taxes		(50,485)		-		-
Accretion of discount		2,530		1,608		1,014
Other		8,962		(5,218)		7,507
End of year	$	97,994	$	300,067	$	145,424

F-31