Pegasi Energy Resources Corporation. - FORM 10-K/A

Attached files

file	filename
EX-99.1 - EXHIBIT 99.1 - Pegasi Energy Resources Corporation.	ex991.htm
EX-31.01 - EXHIBIT 31.01 - Pegasi Energy Resources Corporation.	ex3101.htm
EX-31.02 - EXHIBIT 31.02 - Pegasi Energy Resources Corporation.	ex3102.htm
EX-23.02 - EXHIBIT 23.02 - Pegasi Energy Resources Corporation.	ex2302.htm
EX-32.01 - EXHIBIT 32.01 - Pegasi Energy Resources Corporation.	ex3201.htm
EX-23.01 - EXHIBIT 23.01 - Pegasi Energy Resources Corporation.	ex2301.htm
EX-32.02 - EXHIBIT 32.02 - Pegasi Energy Resources Corporation.	ex3202.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K/A

(Amendment No. 2 )

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

For the Fiscal Year Ended December 31, 2010

Commission File Number 333-134568

PEGASI ENERGY RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

Nevada	20-4711443
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
218 N. Broadway, Suite 204 Tyler, Texas	75702	(903) 595-4139
(Address of principal executive office)	(Zip Code)	(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None.

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. Yeso Nox

Indicate by checkmark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yeso Nox

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 x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  No 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the 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. o

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer 	Accelerated filer 
Non-accelerated filer 	Smaller reporting company x
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act.) Yeso Nox

The aggregate market value of the voting common equity held by non-affiliates as of June 30, 2010, based on the closing sales price of the Common Stock as quoted on the Over-the-Counter Bulletin Board was $4,326,250. For purposes of this computation, all officers, directors, and 5 percent beneficial owners of the registrant are deemed to be affiliates. Such determination should not be deemed an admission that such directors, officers, or 5 percent beneficial owners are, in fact, affiliates of the registrant.

As of March 25, 2011, there were 33,660,801 shares of registrant’s common stock outstanding.

EXPLANATORY NOTE

The Company is filing this Amendment No. 2 on Form 10-K/A (the “Second Amended Filing”) to the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 (the “Original Filing”) filed with the Securities and Exchange Commission (“SEC”) on March 31, 2011, as amended by the Annual Report on Form 10-K/A filed with the SEC on August 22, 2011 (the “First Amended Filing”), in order to:

file the reserve report from the Company’s independent petroleum engineer as exhibit 99.1, which was omitted from the Original Filing and

1)	First Amended Filing;

2)	file the consent from the Company’s independent petroleum engineer as exhibit 23.1, relating to the reserve report;

3)	revise the summary of oil and gas reserves table in the description of business section to disclose reserves per MBoe, to show the quantity of production per MBoe for each period, and include our 2009 reserve information;

revise the proved undeveloped reserves disclosure in the description of business section to clarify for each period the extent to which the Company converted proved undeveloped reserves into proved developed reserves and made investments in acquiring undeveloped reserves or investments constituting progress towards converting proved undeveloped reserves to proved developed reserves;

5)	describe the internal controls the Company uses in its reserves estimation effort, the qualifications of all individuals involved, and the procedures used to ensure compliance of its proved reserves, which disclosure is in the description of business section;

6)	include disclosure regarding the minimum remaining terms of their leases and concessions, which disclosure is in the properties section;

disclose the net quantities of its proved developed reserves and proved undeveloped reserves as of the beginning of the year as well as the proved undeveloped reserves as of the end of the year, which disclosure is in the unaudited Supplemental Oil and Gas Disclosures section of the financial statements; and

8)	disclose the reason for the revision of previous reserve quantity estimates, which disclosure is also in the unaudited Supplemental Oil and Gas Disclosures section of the financial statements.

For the convenience of the reader, this Second Amended Filing sets forth the Original Filing in its entirety. However, this Second Amended Filing only amends the information disclosed above. No other information in the Original Filing is amended hereby. In addition, pursuant to the rules of the SEC, Item 15 of Part IV to the Original Filing has been amended to contain currently dated certifications from our Principal Executive Officer and Principal Financial Officer, as required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002. The certifications of our Principal Executive Officer and Principal Financial Officer are attached to this Second Amended Filing as

Exhibits 31.01, 31.02 and 32.01.

Table of Contents

	Part I	Page

Item 1.	Business	4

Item 1A.	Risk Factors	11

Item 1B.	Unresolved Staff Comments	19

Item 2.	Properties	19

Item 3.	Legal Proceedings	20

Item 4.	(Removed and Reserved)	20


	Part II	Page

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21

Item 6.	Selected Financial Data	22

Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	23

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	27

Item 8.	Financial Statements and Supplementary Data	F-1

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	27

Item 9A.	Controls and Procedures	27

Item 9B.	Other Information	28


	Part III	Page

Item 10.	Directors, Executive Officers and Corporate Governance	29

Item 11.	Executive Compensation	31

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	33

Item 13.	Certain Relationships and Related Transactions, and Director Independence	34

Item 14.	Principal Accounting Fees and Services	35

	Part IV	Page

Item 15.	Exhibits, Financial Statement Schedules	36

	Signatures.	38

PART I

FORWARD-LOOKING INFORMATION

This Amended Annual Report of Pegasi Energy Resources Corporation (“PERC,” or the “Company”) on Form 10-K contains forward-looking statements, particularly those identified with the words, "anticipates," "believes," "expects," "plans," “intends”, “objectives” and similar expressions. These statements reflect management's best judgment based on factors known at the time of such statements. The reader may find discussions containing such forward-looking statements in the material set forth under "Legal Proceedings" and "Management's Discussion and Analysis of Financial Condition and Results of Operations," generally, and specifically therein under the captions "Liquidity and Capital Resources" as well as elsewhere in this Annual Report on Form 10-K. Actual events or results may differ materially from those discussed herein.

ITEM 1. BUSINESS.

Overview of Business

We are an independent energy company engaged in the exploration and production of natural gas and oil through the development of a repeatable, low-geological risk, high-potential project in the active East Texas oil and gas region. We currently hold interests in properties located in Marion and Cass County, Texas, home to the Rodessa oil field. The field has historically been the domain of small independent operators and is not a legacy field for any major oil company.

Our business strategy, which we designated as the “Cornerstone Project”, is to identify and exploit resources in and adjacent to existing or indicated producing areas within the Rodessa field area. We intend to quickly develop and produce reserves at a low cost and will take an aggressive approach to exploiting our contiguous acreage position through utilization of “best in class” drilling, (i.e. using the latest drilling techniques available and seismic technology). We believe that we are uniquely familiar with the history and geology of the Cornerstone Project area based on our collective experience in the region as well as through our ownership of a large proprietary database which details the drilling history of the Cornerstone Project area since 1980. We believe implementing our drilling strategy and using new drilling and completion techniques will enable us to find significant gas and oil reserves in the Cornerstone Project area.

Corporate History

We previously operated under the name Maple Mountain Explorations, Inc. (“Maple Mountain”), a Nevada corporation. On December 12, 2007, Maple Mountain entered into a Share Exchange Agreement (the “Share Exchange”) with the shareholders of PERC, a Texas corporation, pursuant to which Maple Mountain purchased from PERC’s shareholders all issued and outstanding shares of PERC’s common stock in consideration for the issuance of 17,500,000 shares of Maple Mountain’s common stock. Effective January 23, 2008, we changed our name to Pegasi Energy Resources Corporation.

Principal Operations

We began our leasing and farm-in activities in the Rodessa field area of the East Texas oil and gas basin in 2000. Our initial leasehold purchase was comprised of approximately 1,500 gross acres, which has grown to approximately 25,300 gross acres (approximately 16,700 net acres) as of December 2010. We serve as operator of the Cornerstone Project with a working interest partner, TR Energy Inc. (“TR Energy”), a related party, to develop our acreage position in the Cornerstone Project. We hold an 80% working interest in the majority of our leases with TR Energy holding 20% working interest in those leases. We have a few leases in which we hold smaller interests ranging from 25% - 50% with TR Energy and other minority investors holding the remaining working interests. Since initiating operations in 2000, we have drilled 10 productive wells.

We have been aggressively acquiring oil and gas leases to add to our existing lease inventory. Based on detailed log analysis of thousands of wells from our database and information derived from our drilling experience in the area, over a hundred drilling locations have been identified on our present leased acreage. We are currently focusing on an initial well drilling program.

If we are able to obtain funding, our initial 12-month drilling program will be to drill horizontal oil wells in the depth range of 9,500 feet to 10,500 feet. We obtained partial funding last year enabling us to drill the Norbord #1 and the Swamp Fox #1 in addition to funding for lease acquisitions. With further funding, we plan on developing gas reserves in the Cotton Valley, Travis Peak, and Pettit geologic formations at depths ranging from 6,500-10,500 feet.

Other Operations

We conduct our main exploration and production operations through our wholly-owned subsidiary, Pegasi Operating Inc. (“POI”). We conduct additional operations through two other wholly-owned subsidiaries: (i) TR Rodessa, Inc. ("TR Rodessa"). and (ii) 59 Disposal, Inc. ("59 Disposal").

TR Rodessa owns an 80% undivided interest in and operates a 40-mile natural gas pipeline and gathering system which we currently use to transport our hydrocarbons to market. Excess capacity on this system is used to transport third-party hydrocarbons.

59 Disposal owns an 80% undivided interest in and operates a saltwater disposal facility which disposes saltwater and flow-back waste into subsurface storage. We are currently in negotiations to sell 59 Disposal. We have a letter of intent from a potential buyer for the purchase price of $1.3 million. The letter of intent is valid for thirty days after its signing on March 1, 2011. We expect to complete this sale by the end of April 2011.

We intend to continue to use our competitive strengths to advance our corporate strategy. The following are key elements of that strategy:

●	Develop the Cornerstone Project in East Texas through a lease renewal and lease acquisition program along with a drilling program. We will focus our near-term efforts on our leasing program and development drilling on existing acreage. We expect this drilling program to increase our proved reserve and cash flow profile. In late 2010, we completed drilling the Norbord #1 well to 7,005 feet in the Travis Peak formation. The deliverability rate is estimated at 3,381 MCF (a thousand cubic feet) per day and 55.2 BBLSPD (barrels per day). Based on the success of this well, we will begin a developmental drilling program in midyear 2011. We have a gross working interest of 25% in the well as we have been carried for the cost of the well. The Swamp Fox #1 test well was drilled to a total depth of 7,000 foot in December 2010. The well is presently waiting on fracture stimulation after testing oil in the Pettit formation.
●	Apply management expertise in the Cornerstone Project area and recent developments in drilling and completion technology to identify new drilling opportunities and enhance production. We plan to maximize the present value of our vertical wells by utilizing a shotgun-dual or sawtooth production technique. We will also implement the latest drilling, fracturing and completion techniques including shotgun duals to develop our properties as well as horizontal drilling. These horizontal wells will primarily target the Bossier formation and we anticipate these wells will yield significantly higher hydrocarbon flow rates than our vertical wells. We plan to begin our horizontal drilling programs in the second half of 2011.
●	Continue to lease underdeveloped acreage in the Cornerstone Project area. We are continuing our leasing program to support our present and future drilling plans with existing funding. The program includes renewing existing leasehold and acquiring new leaseholds. We are using our extensive proprietary database to help optimize additional drilling locations and to acquire additional acreage. We intend to target acreage with exploitation and technology upside within the Cornerstone Project area. Most properties in the Cornerstone Project area are held by smaller independent companies that lack the resources to exploit them to the fullest extent. We intend to pursue these opportunities to selectively expand our portfolio of properties. These acreage additions will complement our existing substantial acreage position in the area and provide us with significant additional drilling inventory.
●	Maintain a conservative and flexible financial strategy. We intend to continue focusing on maintaining a low level of corporate overhead expense in addition to continued utilization of outsourcing, when appropriate, to maximize cash flow. We believe this internally-generated cash flow, coupled with reserve-based debt financing when appropriate, will provide the optimal capital structure to fund our future drilling activity.

Well Economics

In order to develop the P1 reserves, we plan to initially drill vertical wells to approximately 10,500 feet targeting the lower Cotton Valley formation (primarily gas) and continue developing the Travis Peak formation based on the success of the Norbord well. The estimated future development cost expected to be incurred relative to the proved reserves in this formation totals approximately $1.52 million. The estimated future development cost is a component of the amounts disclosed in the supplemental oil and gas disclosures required by Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic No. 932, Extractive Activities—Oil and Gas. The estimated ultimate recovery includes all proved reserves except those that are currently producing. Proved developed and undeveloped oil and gas in this formation include 1.3 billion cubic feet (“bcf”) and .03 million barrels of oil (“MMBO”) of proved behind-pipe reserves, 0.05 bcf and 0.04 MMBO of proved developed non-producing reserves and 0.2 bcf and 0.005 MMBO proved producing reserves. We emphasize that reserve estimates are inherently imprecise and that estimates of reserves related to new discoveries are more imprecise than those for producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared with the assistance of James E. Smith and Associates, an independent petroleum reservoir engineering firm. The finding and development cost is the ratio of estimated future development costs to the estimated ultimate recovery. We use this ratio, with the commodity price factored in, to determine the viability of drilling a well. The limitation of this measure is that it is based on estimates that are inherently imprecise. The manner in which we have calculated the finding and development costs may differ from how other companies calculate a like measure. We estimate the well economics of drilling a lower Cotton Valley well on our acreage as seen below.

Cotton Valley Vertical Well Economics
Estimated Future Development Costs ~$1.52 mil	Estimated Ultimate Recovery: ~1.8 bcfe
Finding and Development Costs: ~$0.83 / mcfe	% Gas: ~77%

In order to maximize our rate of return on our vertical wells, we plan on implementing a shotgun-dual or sawtooth production technique. Under this technique, we will drill and complete multiple geologic horizons in a sequential manner as follows:

●	We will initially complete and produce the lower Cotton Valley pay zone (~10,500 ft.);
●	After producing the lower Cotton Valley zone for a period of time, we will move uphole to recomplete the upper Cotton Valley (~8,200 ft.), Travis Peak Zone (~7,500 ft.) and/or Pettit Zone (~6,500 ft.); and
●	After producing the upper Cotton Valley, Travis Peak and/or Pettit Zones for a period of time, we will co-mingle all zones and produce through the end of the wells’ lives.

The estimated future development costs expected to be incurred relative to the proved reserves in the upper Cotton Valley, Travis Peak, Pettit, and co-mingled formations total approximately $8.9 million. The estimated future development cost is a component of the amounts disclosed in the supplemental oil and gas disclosures required by FASB ASC Topic No. 932. The estimated ultimate recovery includes all proved reserves except those that are currently producing. Proved developed and undeveloped oil and gas in these formations include 4.7 bcf and 0.11 MMBO of proved undeveloped reserves, 6.9 bcf and 0.26 MMBO of proved behind-pipe reserves, 0.4 bcf and 0.004 MMBO of proved developed non-producing reserves and 0.22 bcf and 0.006 MMBO of proved producing reserves. We emphasize that reserve estimates are inherently imprecise and that estimates of reserves related to new discoveries are more imprecise than those for producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared with the assistance of James E. Smith and Associates, an independent petroleum reservoir engineering firm. The production technique is expected to result in improved well economics as indicated below.

Shotgun-dual or Sawtooth Vertical Well Economics
Estimated Future Development Costs ~$8.9 mil	Estimated Ultimate Recovery: ~14.3 bcfe
Finding and Development Costs: ~$0.62 / mcfe	% Gas: ~84%

The following table summarizes our oil and gas production revenue and costs, our productive wells and acreage, undeveloped acreage and drilling activities for each of the last two years ended December 31.

	2010		2009		2008
Production
Net oil production (Bbls)		4,346		5,719		7,515
Net gas production (Mcf)		61,678		64,003		62,708
Total production (MBoe) (1)		14,626		16,386		17,966
Average sales price per Bbl of oil	$	76.11	$	56.62	$	100.76
Average sales price per Mcf of gas	$	3.91	$	3.25	$	7.95
Average sales price per Boe	$	39.53	$	32.80	$	70.02
Average production cost per mcfe	$	3.56	$	3.95	$	2.84

(1)	Oil and gas were combined by converting gas to a Boe equivalent on the basis of 6 Mcf of gas to 1 Bbl of oil

The following tables summarize by geographic area the Company’s gross and net interests in producing oil and gas wells and developed and undeveloped acreage as of December 31, 2010 and 2009.

Productive Wells

	Gross Wells				Net Wells
Geographic Area:	Oil		Gas		Oil		Gas

Texas 2010		2		4		2		3
Texas 2009		2		3		2		2

Developed and Undeveloped Acreage

	Developed Acreage				Undeveloped Acreage
Geographic Area:	Gross		Net		Gross		Net

Texas 2010		2,767		22,543		2,760		13,908
Texas 2009		2,767		18,268		2,760		11,580

Drilling Activity

	2010		2009
Drilling activity
Net productive exploratory wells drilled		1		-
Net dry exploratory wells drilled		-		-

We are not obligated to provide oil or gas in fixed quantities or at fixed prices under existing contracts.

Summary of Oil and Gas Reserves as of December 31, 2010 and 2009

	12/31/10 Reserves						12/31/09 Reserves
	Oil		Natural Gas		Total		Oil		Natural Gas		Total
Reserves category	(bbls)		(mcf)		(MBOE)		(bbls)		(mcf)		(MBOE)
PROVED
Developed
United States		52,866		799,696		186,149		45,656		772,470		174,401
Undeveloped
United States		405,420		13,014,744		2,574,544		963,243		25,537,685		5,219,524
TOTAL PROVED		458,286		13,814,440		2,760,693		1,008,899		26,310,155		5,393,925

Proved Undeveloped Reserves

Our total proved undeveloped (“PUD”) reserves as of December 31, 2010 were15.4 Bcfe, or 93% of our total proved reserves. Our PUD reserves as of December 31, 2009 were 31.3 Bcfe, or 97% of our total proved reserves. The decrease in our year end 2010 PUD reserves is attributable to the removal of various proved undeveloped reserves associated with drilling locations no longer anticipated to be developed within the next five years. As a result of the success of the Norbord well, the Company has decided to focus its attention on the Travis Peak area, which was previously included in the PUD classification. In addition, the change in our drilling program from drilling vertical to drilling horizontal wells takes more acreage and therefore reduces the number of our PUD’s. During the year ended December 31, 2010, the Company continued to focus its capital program on development projects and did not incur any capital expenditures or make any significant progress to convert any of our proved undeveloped reserves to proved developed reserves. As of December 31, 2010, no undeveloped reserves that were identified more than 5 years ago remain in our proved reserve portfolio.

The technical person in charge of the preparation and oversight of our reserve estimates is James E. Smith, a petroleum engineer who founded and is the president of a multi-disciplined engineering firm that offers a total package of services to the oil and gas industry in East Texas and other areas in the southwestern United States. He has over 40 years of experience in the oil and gas industry. A graduate of Texas A&M University, he worked 18 years for the Texas Railroad Commission serving as Field Operations Director, Hearing Examiner, Special Project Engineer in Austin, and as the District Director of both the Kilgore and Abilene District Offices. He is a member of Society of Petroleum Engineers, Society of Petroleum Evaluation Engineers, and SPE Technical Information Group for economics and evaluations. He is a registered petroleum engineer in the state of Texas. He has extensive experience in economic and reservoir evaluation for acquisitions, producing properties and undeveloped prospects. He also planned and supervised the drilling of wells that we drilled in the East Texas project. He is not an employee of ours and does not have an equity position in our oil and gas development. We believe his independence allows him to be objective in the preparation and oversight of our reserve estimates.

The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data provided for the report and review of the independent third party reserves report. The technical employee responsible for overseeing the process for preparation of the reserves estimates is Michael H. Neufeld. Michael H. Neufeld holds a B.S. Degree in Geology from Louisiana State University, has worked in the oil and gas industry for over 38 years, including roles as Senior Exploration Geologist and Vice President of Exploration at various oil & gas companies including Penzoil and Hunt Oil Company. He is the sole person in the Company that reviews and approves the reserve estimates.

Title to Properties

As is customary in the oil and gas industry, only a preliminary title examination is conducted at the time we acquire leases or enter into other agreements to obtain control over interests in acreage believed to be suitable for drilling operations. In many instances, our partners have acquired rights to the prospective acreage and we have a contractual right to have our interests in that acreage assigned to us. In some cases, we are in the process of having those interests so assigned. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted by independent attorneys. Once production from a given well is established, the operator will prepare a division order title report indicating the proper parties and percentages for payment of production proceeds, including royalties. We believe that titles to our leasehold properties are good and defensible in accordance with standards generally acceptable in the oil and gas industry.

Markets and Customers

The revenue generated by our operations is highly dependent upon the prices of, and demand for, natural gas and crude oil. Historically, the markets for natural gas and crude oil have been volatile and are likely to continue to be volatile in the future. The prices we receive for our natural gas and crude oil production are subject to wide fluctuations and depend on numerous factors beyond our control including seasonality, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other crude oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic regulation, legislation, and policies. Decreases in the prices of natural gas and crude oil have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenue, profitability, and cash flow from operations.

We currently have access to several interstate pipelines as well as local end users, however the market for oil and natural gas that we expect to produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial, and individual consumers.

Our oil production is expected to be sold at prices tied to the spot oil markets. Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices.

Regulations

General

Our business is affected by numerous laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the energy industry. Most of our drilling operations will require permit or authorizations from federal, state or local agencies. Changes in any of these laws and regulations or the denial or vacating of permits could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

We believe that our operations comply in all material respects with applicable laws and regulations. There are no pending or threatened enforcement actions related to any such laws or regulations. We further believe that the existence and enforcement of such laws and regulations will have no more restrictive an effect on our operations than on other similar companies in the energy industry.

Proposals and proceedings that might affect the oil and gas industry are pending before Congress, the Federal Energy Regulatory Commission (“FERC”), state legislatures and commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material adverse effect upon our capital expenditures, earnings, or competitive position.

Federal Regulation of Sales and Transportation of Natural Gas

Historically, the transportation and sale of natural gas and its component parts in interstate commerce has been regulated under several laws enacted by Congress and the regulations passed under these laws by FERC. Our sales of natural gas, including condensate and liquids, may be affected by the availability, terms, and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and FERC that affect the economics of natural gas production, transportation and sales. In addition, FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry.

The ultimate impact of the complex rules and regulations issued by FERC cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial and final FERC decisions. We cannot predict what further action FERC will take on these matters. Some of FERC’s more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with whom we compete.

State Regulation

Our operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandonment of wells, and the disposal of fluids used and produced in connection with operations. Our operations are also subject to various conservation laws and regulations pertaining to the size of drilling and spacing units or proration units and the unitization or pooling of oil and gas properties.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but, except as noted above, does not generally entail rate regulation. These regulatory burdens may affect profitability, but we are unable to predict the future cost or impact of complying with such regulations.

Environmental Matters

Our operations are subject to numerous federal, state and local laws and regulations controlling the generation, use, storage, and discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences; restrict the types, quantities, and concentrations of various substances that can be released into the environment in connection with drilling, production, and natural gas processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, and other protected areas; require remedial measures to mitigate pollution from historical and on-going operations such as use of pits and plugging of abandoned wells; restrict injection of liquids into subsurface strata that may contaminate groundwater; and impose substantial liabilities for pollution resulting from our operations. Environmental permits required for our operations may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations and permits, and violations are subject to injunction, civil fines, and even criminal penalties. We believe that we are in substantial compliance with current environmental laws and regulations, and that we will not be required to make material capital expenditures to comply with existing laws.

Nevertheless, changes in existing environmental laws and regulations or interpretations thereof could have a significant impact on us as well as the natural gas and crude oil industry in general, and thus we are unable to predict the ultimate cost and effects of future changes in environmental laws and regulations.

We are not currently involved in any administrative, judicial or legal proceedings arising under domestic or foreign federal, state, or local environmental protection laws and regulations, or under federal or state common law, which would have a material adverse effect on our consolidated financial position or results of operations. Moreover, we maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. A serious incident of pollution may result in the suspension or cessation of operations in the affected area.

Superfund

The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as "Superfund," and comparable state statutes impose strict, joint, and several liability on certain classes of persons who are considered to have contributed to the release of a “hazardous substance" into the environment. These persons include the owner or operator of a disposal site or sites where a release occurred and companies that generated, disposed, or arranged for the disposal of the hazardous substances released at the site. Under CERCLA, such persons or companies may be retroactively liable for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is common for neighboring land owners and other third parties to file claims for personal injury, property damage, and recovery of response costs allegedly caused by the hazardous substances released into the environment. In the course of our operations, we may generate waste that may fall within CERCLA's definition of a "hazardous substance." We may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed. Although CERCLA currently contains a "petroleum exclusion" from the definition of “hazardous,” state laws affecting our operations impose cleanup liability relating to petroleum related products, including crude oil cleanups. In addition, although RCRA regulations currently classify certain wastes which are uniquely associated with field operations as "non-hazardous," such exploration, development and production wastes could be reclassified by regulation as hazardous wastes thereby administratively making such wastes subject to more stringent handling and disposal requirements.

We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and production of natural gas and crude oil. Although we utilized standard industry operating and disposal practices at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties we owned or leased or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, the Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators; to clean up contaminated property, including contaminated groundwater; or to perform remedial operations to prevent future contamination.

Oil Pollution Act of 1990

United States federal regulations also require certain owners and operators of facilities that store or otherwise handle crude oil, such as us, to prepare and implement spill prevention, control and countermeasure plans and spill response plans relating to possible discharge of crude oil into surface waters. The federal Oil Pollution Act ("OPA") contains numerous requirements relating to prevention of, reporting of, and response to crude oil spills into waters of the United States. For facilities that may affect state waters, OPA requires an operator to demonstrate $10 million in financial responsibility. State laws mandate crude oil cleanup programs with respect to contaminated soil. A failure to comply with OPA's requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA's financial responsibility and other operating requirements will not have a material adverse effect on us.

U.S. Environmental Protection Agency

U.S. Environmental Protection Agency regulations address the disposal of crude oil and natural gas operational wastes under three federal acts more fully discussed in the paragraphs that follow. The RCRA provides a framework for the safe disposal of discarded materials and the management of solid and hazardous wastes. The direct disposal of operational wastes into offshore waters is also limited under the authority of the Clean Water Act. When injected underground, crude oil and natural gas wastes are regulated by the Underground Injection Control program under the Safe Drinking Water Act. If wastes are classified as hazardous, they must be properly transported, using a uniform hazardous waste manifest, documented, and disposed of at an approved hazardous waste facility. We have coverage under the applicable Clean Water Act permitting requirements for discharges associated with exploration and development activities.

Resource Conservation Recovery Act

RCRA is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a "generator" or "transporter" of hazardous waste or an "owner" or "operator" of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most crude oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA's requirements because our operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes crude oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

Clean Water Act

The Clean Water Act imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the crude oil and natural gas industry into certain coastal and offshore waters. Further, the Environmental Protection Agency has adopted regulations requiring certain crude oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for crude oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

Safe Drinking Water Act

Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from crude oil and natural gas production. The Safe Drinking Water Act of 1974, as amended establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. In Texas, no underground injection may take place except as authorized by permit or rule. We currently own and operate various underground injection wells. Failure to abide by our permits could subject us to civil and/or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

Air Pollution Control

The Clean Air Act and state air pollution laws adopted to fulfill its mandate provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.

Naturally Occurring Radioactive Materials ("NORM")

NORM are materials not covered by the Atomic Energy Act, whose radioactivity is enhanced by technological processing such as mineral extraction or processing through exploration and production conducted by the crude oil and natural gas industry. NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the release of NORM contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards established by the State of Texas.

Abandonment Costs

All of our crude oil and natural gas wells will require proper plugging and abandonment when they are no longer producing. We post bonds with most regulatory agencies to ensure compliance with our plugging responsibility. Plugging and abandonment operations and associated reclamation of the surface production site are important components of our environmental management system. We plan accordingly for the ultimate disposition of properties that are no longer producing.

Competition

We operate in a highly competitive environment. The principal resources necessary for the exploration and production of natural gas and crude oil are leasehold prospects under which natural gas and crude oil reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct all phases of natural gas and crude oil operations. We must compete for such resources with both major natural gas and crude oil companies and independent operators. Many of these competitors have financial and other resources substantially greater than ours. Although we believe our current operating and financial resources are adequate to preclude any significant disruption of our operations in the immediate future, we cannot assure you that such materials and resources will be available to us.

Employees

As of March 14, 2011, we had seven full-time employees. None of our employees are represented by a labor union, and we consider our employee relations to be excellent. We seek to use contract workers and anticipate maintaining a small full-time employee base. We have a staff services agreement with Odyssey One Source, Inc. on a month-to-month basis whereby we jointly employ personnel and share employment responsibilities for the staff.

ITEM 1A. RISK FACTORS.

You should carefully consider the following risk factors and all other information contained herein as well as the information included in this Annual Report in evaluating our business and prospects. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties, other than those we describe below, that are not presently known to us or that we currently believe are immaterial, may also impair our business operations. If any of the following risks occur, our business and consolidated financial results could be harmed. You should refer to the other information contained in this Annual Report, including our consolidated financial statements and the related notes.

Risks Related to Our Business

We have a history of losses which may continue, which may negatively impact our ability to achieve our business objectives.

We incurred net losses of $6,491,173 and $2,811,950 for the years ended December 31, 2010 and 2009, respectively. We cannot assure you that we can achieve or sustain profitability on a quarterly or annual basis in the future. Our operations are subject to the risks and competition inherent in the establishment of a business enterprise. There can be no assurance that future operations will be profitable. Revenues and profits, if any, will depend upon various factors, including whether we will be able to continue expansion of our revenue. We may not achieve our business objectives and the failure to achieve such goals would have an adverse impact on us.

We have a limited operating history and if we are not successful in continuing to grow our business, then we may have to scale back or even cease our ongoing business operations.

We have been engaged in the business of oil and gas exploration and development for only a short amount of time, and have limited current oil or natural gas operations. The business of acquiring, exploring for, developing and producing oil and natural gas reserves is inherently risky. As an oil and gas acquisition, exploration and development company with limited operating history, it is difficult for potential investors to evaluate our business. Our proposed operations are therefore subject to all of the risks inherent in light of the expenses, difficulties, complications and delays frequently encountered in connection with the formation of any new business, as well as those risks that are specific to the oil and gas industry. Investors should evaluate us in light of the delays, expenses, problems and uncertainties frequently encountered by companies developing markets for new products, services and technologies. If our business plan is not successful, and we are not able to operate profitably, investors may lose some or all of their investment in our company.

Our lack of diversification will increase the risk of an investment in PERC, and our consolidated financial condition and results of operations may deteriorate if we fail to diversify.

Our business focus is on the oil and gas industry in a limited number of properties, initially in Texas. Larger companies have the ability to manage their risk by geographic diversification. However, we will lack diversification, in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than we would if our business were more diversified, enhancing our risk profile. If we cannot diversify our operations, our financial condition and results of operations could deteriorate.

Because we are small and do not have much capital, we may have to limit our exploration activity which may result in a loss of your investment.

Because we are small and do not have much capital, we must limit our exploration activity. As such we may not be able to complete an exploration program that is as thorough as we would like. In that event, existing reserves may go undiscovered. Without finding reserves, we cannot generate revenues and you will lose your investment.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

Our ability to successfully acquire additional properties, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. These realities are subject to change and may impair our ability to grow.

To develop our business, we will endeavor to use the business relationships of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

Competition in obtaining rights to explore and develop oil and gas reserves and to market our production may impair our business.

The oil and gas industry is highly competitive. Other oil and gas companies may seek to acquire oil and gas leases and other properties and services we will need to operate our business in the areas in which we expect to operate. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger companies, which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. If we are unable to compete effectively or adequately respond to competitive pressures, this inability may materially adversely affect our consolidated results of operations and financial condition.

If we are unable to obtain additional funding our business operations will be harmed and if we do obtain additional financing our then existing shareholders may suffer substantial dilution.

We expect that our current capital and our other existing resources will be sufficient only to provide a limited amount of working capital, and the revenues generated from our properties in Texas alone will not alone be sufficient to fund our operations or planned growth. We anticipate that we will require up to approximately $1.55 million for our anticipated operations for the next twelve months, depending on revenues. We believe that our currently available funds can sustain our current level of operations for approximately one month. We will require additional capital to continue to operate our business beyond the initial phase of our current properties, and to further expand our exploration and development programs. We may be unable to obtain additional capital required. Furthermore, inability to maintain capital may damage our reputation and credibility with industry participants. Our inability to raise additional funds when required may have a negative impact on our consolidated results of operations and financial condition.

Future acquisitions and future exploration, development, production, leasing activities and marketing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) will require a substantial amount of additional capital and cash flow.

We plan to pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in locating suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means.

Any additional capital raised through the sale of equity may dilute your ownership percentage. This could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity. The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of warrants or other derivative securities, and issuances of incentive awards under equity employee incentive plans, which may have a further dilutive effect.

Our ability to obtain needed financing may be impaired by such factors as the capital markets (both generally and in the oil and gas industry in particular), our status as a new enterprise without a significant demonstrated operating history, the location of our oil and natural gas properties and prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and/or the loss of key management. Further, if oil and/or natural gas prices on the commodities markets decrease, then our revenues will likely decrease, and such decreased revenues may increase our requirements for capital. If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we may be required to cease our operations.

We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertible notes and warrants, which may adversely impact our consolidated financial results.

We may not be able to effectively manage our growth, which may harm our profitability.

Our strategy envisions expanding our business. If we fail to effectively manage our growth, our consolidated financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We cannot assure you that we will be able to:

●	meet our capital needs;
●	expand our systems effectively or efficiently or in a timely manner;
●	allocate our human resources optimally;
●	identify and hire qualified employees or retain valued employees; or
●	incorporate effectively the components of any business that we may acquire in our effort to achieve growth.

If we are unable to manage our growth, our operations and our consolidated financial results could be adversely affected by inefficiency, which could diminish our profitability.

If we are unable to retain the services of Messrs. Neufeld, Sudderth or Lindermanis, or if we are unable to successfully recruit qualified managerial and field personnel having experience in oil and gas exploration, we may not be able to continue our operations.

Our success depends to a significant extent upon the continued services of Mr. Michael Neufeld, our President and Chairman, Mr. William Sudderth, our Executive Vice President or Mr. Richard Lindermanis, our Executive Vice President and Chief Financial Officer. The loss of the services of Messrs. Neufeld, Sudderth or Lindermanis could have a material adverse effect on our growth, revenues, and prospective business. We do not have key-man insurance on the lives of Messrs. Neufeld, Sudderth or Lindermanis. In addition, in order to successfully implement and manage our business plan, we will be dependent upon, among other things, successfully recruiting qualified managerial and field personnel having experience in the oil and gas exploration business. Competition for qualified individuals is intense. There can be no assurance that we will be able to find, attract and retain existing employees or that we will be able to find, attract and retain qualified personnel on acceptable terms.

RISKS RELATED TO OUR INDUSTRY

Our exploration for oil and gas is risky and may not be commercially successful, and the 3D seismic data and other advanced technologies we use cannot eliminate exploration risk, which could impair our ability to generate revenues from our operations.

Our future success will depend on the success of our exploratory drilling program. Oil and gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. Our expenditures on exploration may not result in new discoveries of oil or natural gas in commercially viable quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over-pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.

Even when used and properly interpreted, 3D seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. In addition, the use of 3D seismic data becomes less reliable when used at increasing depths. We could incur losses as a result of expenditures on unsuccessful wells. If exploration costs exceed our estimates, or if our exploration efforts do not produce results which meet our expectations, our exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from operations.

We may not be able to develop oil and gas reserves on an economically viable basis and our reserves and production may decline as a result.

To the extent that we succeed in discovering oil and/or natural gas reserves, we cannot assure that these reserves will be capable of production levels we project or in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional oil and natural gas reserves. Without the addition of reserves through acquisition, exploration or development activities, our reserves and production will decline over time as reserves are produced. Our future reserves will depend not only on our ability to develop then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. While we will endeavor to effectively manage these conditions, we cannot be assured of doing so optimally, and we will not be able to eliminate them completely in any case. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

Estimates of oil and natural gas reserves that we make may be inaccurate and our actual revenues may be lower than our financial projections.

We will make estimates of oil and natural gas reserves, upon which we will base our financial projections. We will make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, engineers and other advisors to make accurate assumptions. For example, our total PUD reserves as of December 31, 2010 were 15.4 Bcfe compared to 31.3 Bcfe as of December 31, 2009. This 48% decrease in PUD reserves is a result of various PUD reserves we no longer anticipate developing within the next five years.

In addition, economic factors beyond our control, such as interest rates, will also impact the value of our reserves. The process of estimating oil and natural gas reserves is complex, and will require us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. As a result, our reserve estimates will be inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from those we estimate. If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues and result in the impairment of our oil and natural gas interests.

Drilling new wells could result in new liabilities, which could endanger our interests in our properties and assets.

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills, among others. The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future consolidated operating results. We may become subject to liability for pollution, blow-outs or other hazards. We intend to obtain insurance with respect to these hazards; however, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects.

We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for production of oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We have not yet determined whether we will establish a cash reserve account for these potential costs in respect of any of our properties or facilities, or if we will satisfy such costs of decommissioning from the proceeds of production in accordance with the practice generally employed in onshore and offshore oilfield operations. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, 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 impair our ability to focus capital investment in other areas of our business.

Our inability to obtain necessary facilities could hamper our operations.

Oil and gas exploration and development activities are dependent on the availability of drilling and related equipment, transportation, power and technical support in the particular areas where these activities will be conducted, and our access to these facilities may be limited. To the extent that we conduct our activities in remote areas, needed facilities may not be proximate to our operations, which will increase our expenses. Demand for such limited equipment and other facilities or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. The quality and reliability of necessary facilities may also be unpredictable and we may be required to make efforts to standardize our facilities, which may entail unanticipated costs and delays. Shortages and/or the unavailability of necessary equipment or other facilities will impair our activities, either by delaying our activities, increasing our costs or otherwise.

Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could reduce profitability, growth and the value of our business.

Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond our control. World prices for oil and natural gas have fluctuated widely in recent years. The average price per barrel was $61.95 in 2009 and $79.48 in 2010, and the average wellhead price per thousand cubic feet of natural gas was $3.71 in 2009 and $4.16 in 2010 (source: U.S. Energy Information Administration).We expect that prices will continue to fluctuate in the future. Price fluctuations will have a significant impact upon our revenue, the return from our reserves and on our financial condition generally. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and gas industry. Decreases in the prices of oil and natural gas may have a material adverse effect on our consolidated financial condition, the future results of our operations and quantities of reserves recoverable on an economic basis.

Increases in our operating expenses will impact our operating results and financial condition.

Exploration, development, production, marketing (including distribution costs) and regulatory compliance costs (including taxes) will substantially impact the net revenues and profits we derive from the oil and natural gas that we produce. These costs are subject to fluctuations and variation in different locales in which we will operate, and we may not be able to predict or control these costs. If these costs exceed our expectations, this may adversely affect our consolidated results of operations. In addition, we may not be able to earn net revenue at our predicted levels, which may impact our ability to satisfy our obligations.

Penalties we may incur could impair our business.

Failure to comply with government regulations could subject us to civil and criminal penalties, could require us to forfeit property rights, and may affect the value of our assets. We may also be required to take corrective actions, such as installing additional equipment or taking other actions, each of which could require us to make substantial capital expenditures. We could also be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result, our future business prospects could deteriorate due to regulatory constraints, and our profitability could be impaired by our obligation to provide such indemnification to our employees.

Oil and gas operations are subject to comprehensive regulation which may cause substantial delays or require capital outlays in excess of those anticipated causing an adverse effect on our company.

Oil and gas operations are subject to federal, state, and local laws relating to the protection of the environment, including laws regulating the removal of natural resources from the ground and the discharge of materials into the environment. Oil and gas operations are also subject to federal, state, and local laws and regulations which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. Various permits from government bodies are required for drilling operations to be conducted; no assurance can be given that such permits will be received. Environmental standards imposed by federal, provincial, or local authorities may be changed and any such changes may have material adverse effects on our activities. Moreover, compliance with such laws may cause substantial delays or require capital outlays in excess of those anticipated, thus causing an adverse effect on us. Additionally, we may be subject to liability for pollution or other environmental damages. We generally maintain insurance coverage customary to the industry; however, we are not fully insured against all possible environmental risks. To date we have not been required to spend any material amount on compliance with environmental regulations. However, we may be required to do so in the future and this may affect our ability to expand or maintain our operations.

Exploration activities are subject to certain environmental regulations which may prevent or delay the commencement or continuance of our operations.

In general, our exploration activities are subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. Such laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Compliance with these laws and regulations has not had a material effect on our consolidated results of operations or financial condition to date. Specifically, we are subject to legislation regarding emissions into the environment, water discharges and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. However, such laws and regulations are frequently changed and we are unable to predict the ultimate cost of compliance. Generally, environmental requirements do not appear to affect us any differently or to any greater or lesser extent than other companies in the industry.

We believe that our operations comply, in all material respects, with all applicable environmental regulations. Our operating partners generally maintain insurance coverage customary to the industry; however, we are not fully insured against all possible environmental risks.

Exploratory drilling involves many risks and we may become liable for pollution or other liabilities which may have an adverse effect on our consolidated financial position.

Drilling operations generally involve a high degree of risk. Hazards such as unusual or unexpected geological formations, power outages, labor disruptions, blow-outs, sour gas leakage, fire, inability to obtain suitable or adequate machinery, equipment or labor, and other risks are involved. We may become subject to liability for pollution or hazards against which we cannot adequately insure or for which we may elect not to insure. Incurring any such liability may have a material adverse effect on our consolidated financial position and operations.

Any change in government regulation and/or administrative practices may have a negative impact on our ability to operate and our profitability.

The laws, regulations, policies or current administrative practices of any government body, organization or regulatory agency in the United States or any other jurisdiction, may be changed, applied or interpreted in a manner which will fundamentally alter the ability of our Company to carry on our business.

The actions, policies or regulations, or changes thereto, of any government body or regulatory agency, or other special interest groups, may have a detrimental effect on us. Any or all of these situations may have a negative impact on our ability to operate and/or our profitably.

Our insurance may be inadequate to cover liabilities we may incur.

Our involvement in the exploration for and development of oil and gas properties may result in our becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although we will obtain insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances, be insurable or, in certain circumstances, we may choose not to obtain insurance to protect against specific risks due to the high premiums associated with such insurance or for other reasons. The payment of such uninsured liabilities would reduce the funds available to us. If we suffer a significant event or occurrence that is not fully insured, or if the insurer of such event is not solvent, we could be required to divert funds from capital investment or other uses towards covering our liability for such events.

Our business will suffer if we cannot obtain or maintain the necessary licenses.

Our operations will require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities. Our ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to change in regulations and policies and to the discretion of the applicable governments, among other factors. Our inability to obtain, or our loss of or denial of extension, to any of these licenses or permits could hamper our ability to produce revenues from our operations.

Challenges to our properties may impact our consolidated financial condition.

Title to oil and gas interests is often not capable of conclusive determination without incurring substantial expense. While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate. If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired.

We will rely on technology to conduct our business and our technology could become ineffective or obsolete.

We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration, development and production activities. We will be required to continually enhance and update our technology to maintain its efficacy and to avoid obsolescence. The costs of doing so may be substantial, and may be higher than the costs that we anticipate for technology maintenance and development. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.

RISKS RELATED TO OUR COMMON STOCK

There has been a limited trading market for our common stock.

It is anticipated that there will be a limited trading market for our common stock on the Over-the-Counter Bulletin Board (“OTCBB”). The lack of an active market may impair your ability to sell your shares at the time you wish to sell them or at a price that you consider reasonable. The lack of an active market may also reduce the fair market value of your shares. An inactive market may also impair our ability to raise capital by selling shares of capital stock and may impair our ability to acquire other companies or assets by using common stock as consideration.

You may have difficulty trading and obtaining quotations for our common stock.

The common stock may not be actively traded, and the bid and asked prices for our common stock on the OTCBB may fluctuate widely. As a result, investors may find it difficult to dispose of, or to obtain accurate quotations of the price of, our securities. This severely limits the liquidity of the common stock, and would likely reduce the market price of our common stock and hamper our ability to raise additional capital.

Our common stock is not currently traded at high volume, and you may be unable to sell at or near ask prices or at all if you need to sell or liquidate a substantial number of shares at one time.

Our common stock is currently traded, but with very low, if any, volume, based on quotations on the “Over-the-Counter Bulletin Board”, meaning that the number of persons interested in purchasing our common stock at or near bid prices at any given time may be relatively small or non-existent. This situation is attributable to a number of factors, including the fact that we are a small company which is still relatively unknown to stock analysts, stock brokers, institutional investors and others in the investment community that generate or influence sales volume, and that even if we came to the attention of such persons, they tend to be risk-averse and would be reluctant to follow an unproven company such as ours or purchase or recommend the purchase of our shares until such time as we became more seasoned and viable. As a consequence, there may be periods of several days or more when trading activity in our shares is minimal or non-existent, as compared to a seasoned issuer which has a large and steady volume of trading activity that will generally support continuous sales without an adverse effect on share price. We cannot give you any assurance that a broader or more active public trading market for our common stock will develop or be sustained, or that trading levels will be sustained.

Shareholders should be aware that, according to Commission Release No. 34-29093, the market for “penny stocks” has suffered in recent years from patterns of fraud and abuse. Such patterns include (1) control of the market for the security by one or a few broker-dealers that are often related to the promoter or issuer; (2) manipulation of prices through prearranged matching of purchases and sales and false and misleading press releases; (3) boiler room practices involving high-pressure sales tactics and unrealistic price projections by inexperienced sales persons; (4) excessive and undisclosed bid-ask differential and markups by selling broker-dealers; and (5) the wholesale dumping of the same securities by promoters and broker-dealers after prices have been manipulated to a desired level, along with the resulting inevitable collapse of those prices and with consequent investor losses. Our management is aware of the abuses that have occurred historically in the penny stock market. Although we do not expect to be in a position to dictate the behavior of the market or of broker-dealers who participate in the market, management will strive within the confines of practical limitations to prevent the described patterns from being established with respect to our securities. The occurrence of these patterns or practices could increase the future volatility of our share price.

The market price of our common stock may, and is likely to continue to be, highly volatile and subject to wide fluctuations.

The market price of our common stock is likely to be highly volatile and could be subject to wide fluctuations in response to a number of factors that are beyond our control, including:

●	dilution caused by our issuance of additional shares of common stock and other forms of equity securities in connection with future capital financings to fund our operations and growth, to attract and retain valuable personnel and in connection with future strategic partnerships with other companies;
●	announcements of new acquisitions, reserve discoveries or other business initiatives by our competitors;
●	our ability to take advantage of new acquisitions, reserve discoveries or other business initiatives;
●	fluctuations in revenue from our oil and gas business as new reserves come to market;
●	changes in the market for oil and natural gas commodities and/or in the capital markets generally;
●	changes in the demand for oil and natural gas, including changes resulting from the introduction or expansion of alternative fuels;
●	quarterly variations in our revenues and operating expenses;
●	changes in the valuation of similarly situated companies, both in our industry and in other industries;
●	changes in analysts’ estimates affecting our company, our competitors and/or our industry;
●	changes in the accounting methods used in or otherwise affecting our industry;
●	additions and departures of key personnel;
●	announcements by relevant governments pertaining to incentives for alternative energy development programs;
●	fluctuations in interest rates and the availability of capital in the capital markets; and
●	significant sales of our common stock, including sales by future investors in future offerings we expect to make to raise additional capital.

These and other factors are largely beyond our control, and the impact of these risks, singly or in the aggregate, may result in material adverse changes to the market price of our common stock and/or our consolidated results of operations and financial condition.

We do not expect to pay dividends in the foreseeable future.

We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. Therefore, investors will not receive any funds unless they sell their common stock, and stockholders may be unable to sell their shares on favorable terms or at all. Investors cannot be assured of a positive return on investment or that they will not lose the entire amount of their investment in the common stock.

Our officers, directors and principal shareholders own a controlling interest in our voting stock and investors will not have any voice in our management.

Our officers, directors and principal shareholders in the aggregate, beneficially own or control the votes of approximately 70.48% of our outstanding common stock. As a result, these stockholders, acting together, will have the ability to control substantially all matters submitted to our stockholders for approval, including:

	●	election of our board of directors;
	●	removal of any of our directors;
	●	amendment of our certificate of incorporation or bylaws; and
	●	adoption of measures that could delay or prevent a change in control or impede a merger, takeover or other business combination involving us.

As a result of their ownership and positions, our directors, executive officers and principal shareholders collectively are able to influence all matters requiring stockholder approval, including the election of directors and approval of significant corporate transactions. In addition, sales of significant amounts of shares held by our directors, executive officers or principal shareholders, or the prospect of these sales, could adversely affect the market price of our common stock. Management's stock ownership may discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of us, which in turn could reduce our stock price or prevent our stockholders from realizing a premium over our stock price.

Efforts to comply with recently enacted changes in securities laws and regulations will increase our costs and require additional management resources.

As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the SEC adopted rules requiring public companies to include a report of management on their internal controls over financial reporting in their annual reports on Form 10-K. In addition, in the event we are no longer a smaller reporting company, the independent registered public accounting firm auditing our consolidated financial statements would be required to attest to the effectiveness of our internal controls over financial reporting. Such attestation requirement by our independent registered public accounting firm would not be applicable to us until the report for the year ended December 31, 2011 at the earliest, if at all. If we are unable to conclude that we have effective internal controls over financial reporting or if our independent registered public accounting firm is required to, but is unable to provide us with a report as to the effectiveness of our internal controls over financial reporting, investors could lose confidence in the reliability of our financial statements, which could result in a decrease in the value of our securities.

Our common stock is subject to the "penny stock" rules of the SEC and the trading market in our securities is limited, which makes transactions in our stock cumbersome and may reduce the value of an investment in our stock.

The SEC has adopted Rule 15g-9 which establishes the definition of a "penny stock," for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require:

	●	that a broker or dealer approve a person's account for transactions in penny stocks; and
	●	the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.

In order to approve a person's account for transactions in penny stocks, the broker or dealer must:

●	obtain financial information and investment experience objectives of the person; and

●	make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form:

●	sets forth the basis on which the broker or dealer made the suitability determination; and

●	that the broker or dealer received a signed, written agreement from the investor prior to the transaction.

Generally, brokers may be less willing to execute transactions in securities subject to the "penny stock" rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

FINRA sales practice requirements may also limit a shareholder’s ability to buy and sell our stock.

In addition to the “penny stock” rules described above, FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2. PROPERTIES.

Our principal executive offices are located at 218 N. Broadway, Suite 204 Tyler, Texas 75702. Our telephone number is (903) 595-4139.

The principal executive office occupies 2,200 square feet with a monthly rate of $2,200. The term of the original lease was for a five-year period which expired August 31, 2010 and had an option to renew for two one-year periods on the same terms with inflation adjustments. If the renewal option was not exercised the lease automatically renews for additional periods of one month with the same terms. On the expiration date of August 31, 2010, the lease was not renewed and the principal executive office began to be leased monthly.

Our field operations are conducted out of our Jefferson, Texas office at 3546 N. US Hwy. 59, Jefferson, Texas 75657, and the phone number is (903) 665-8225. The lease was amended on July 1, 2008 to add an additional 3,600 square feet for a total of 5,300 square feet. The monthly rent was also amended as of that date from $750 to $4,500 per month until the lease expires on January 1, 2012 with an option to extend on a month-to-month basis. The monthly cost includes surface-use rights for the storing of equipment.

Our oil and gas assets are located in Cass and Marion counties in northeast Texas. As of December 31, 2010, we operated 10 wells.

As of March 1, 2011, our leasehold position is approximately 25,310 gross acres and 16,668 net acres with net working acres of 9,280, which represents 25% to 80% working interest in the acreage. We have an ongoing leasing program whereby expiring leases are being renewed and previously unleased acreage is being leased. Most of our proved undeveloped acreage is subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three years. Our intention is to renew all leases that expire in the next three years.

In addition to the operating of the wells, we own an 80% undivided interest in approximately 40 miles of a natural gas pipeline, as well as an 80% undivided interest in a saltwater and drilling fluid disposal system.

ITEM 3. LEGAL PROCEEDINGS.

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. We are currently not aware of any such legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse affect on our business, consolidated financial condition, or operating results.

ITEM 4. REMOVED AND RESERVED.

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 quoted on the OTCBB under the symbol “PGSI”. For the periods indicated, the following table sets forth the high and low bid prices per share of common stock. These prices represent inter-dealer quotations without retail markup, markdown, or commission and may not necessarily represent actual transactions.

Year Ended December 31, 2009
	High		Low
First Quarter	$	1.01	$	0.50
Second Quarter	$	0.65	$	0.35
Third Quarter	$	0.65	$	0.25
Fourth Quarter	$	0.40	$	0.10

Year Ended December 31, 2010
	High		Low
First Quarter	$	0.40	$	0.23
Second Quarter	$	0.40	$	0.15
Third Quarter	$	0.30	$	0.12
Fourth Quarter	$	0.40	$	0.15

HOLDERS

As of March 25, 2011, we had approximately 36 holders of our common stock. The number of record holders was determined from the records of our transfer agent and does not include beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, and registered clearing agencies. The transfer agent of our common stock is Holladay Stock Transfer, 2939 North 67th Place, Suite C, Scottsdale, Arizona 85251.

DIVIDENDS

We have never paid any cash dividends on our capital stock and do not anticipate paying any cash dividends on our common stock in the foreseeable future. We intend to retain future earnings to fund ongoing operations and future capital requirements of our business. Any future determination to pay cash dividends will be at the discretion of the Board and will be dependent upon our consolidated financial condition, results of operations, capital requirements, and such other factors as the Board deems relevant.

RECENT SALES OF UNREGISTERED SECURITIES AND EQUITY PURCHASES BY THE COMPANY

None.

EQUITY COMPENSATION PLAN INFORMATION

The following table sets forth certain information about the common stock that may be issued upon the exercise of options under the equity compensation plans as of March 25, 2011.

Plan Category	Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Shares Reflected in the First Column)

Equity compensation plans approved by shareholders	1,969,285	$	0.78	4,780,715
Equity compensation plans not approved by shareholders	-	$	-	-

Total	1,969,285	$	0.78	4,780,715

ITEM 6. SELECTED FINANCIAL DATA.

Not required under Regulation S-K for “smaller reporting companies.”

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Forward Looking Statements

This Management's Discussion and Analysis of Financial Condition and Results of Operations includes a number of forward-looking statements that reflect Management's current views with respect to future events and financial performance. You can identify these statements by forward-looking words such as “may” “will,” “expect,” “anticipate,” “believe,” “estimate” and “continue,” or similar words. Those statements include statements regarding the intent, belief or current expectations of us and members of its management team as well as the assumptions on which such statements are based. Prospective investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve risk and uncertainties, and that actual results may differ materially from those contemplated by such forward-looking statements.

Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the Securities and Exchange Commission. Important factors currently known to us could cause actual results to differ materially from those in forward-looking statements. We undertake no obligation to update or revise forward-looking statements to reflect changed assumptions, the occurrence of unanticipated events or changes in the future operating results over time. We believe that its assumptions are based upon reasonable data derived from and known about our business and operations and the business and operations of the Company. No assurances are made that actual results of operations or the results of our future activities will not differ materially from its assumptions. Factors that could cause differences include, but are not limited to, expected market demand for the Company’s services, fluctuations in pricing for materials, and competition.

Company Overview

We conduct our main exploration and production operations through our wholly-owned subsidiary, POI. We conduct additional operations through two other wholly-owned subsidiaries: (i) TR Rodessa and (ii) 59 Disposal.

59 Disposal owns an 80% undivided interest in and operates a saltwater disposal facility which disposes saltwater and flow-back waste into subsurface storage.

Plan of Operations

We intend to continue to use our competitive strengths to advance our corporate strategy. The following are key elements of that strategy:

●	Develop the Cornerstone Project in East Texas through a lease renewal and lease acquisition program along with a drilling program. We will focus our near-term efforts on our leasing program and development drilling on existing acreage. We expect this drilling program to increase our proved reserve and cash flow profile. In late 2010, we completed drilling the Norbord #1 well to 7,005 feet in the Travis Peak formation. The deliverability rate is estimated at 3,381 MCF (a thousand cubic feet) per day and 55.2 BBLSPD (barrels per day). Based on the success of this well, we will begin a developmental drilling program in midyear 2011. We have a gross working interest of 25% in the well as we have been carried for the cost of the well. The Swamp Fox #1 test well was drilled to a total depth of 7,000 foot in December 2010. The well is presently waiting on fracture stimulation after testing oil in the Pettit formation.
●	Apply management expertise in the Cornerstone Project area and recent developments in drilling and completion technology to identify new drilling opportunities and enhance production. We plan to maximize the present value of our vertical wells by utilizing a shotgun-dual or sawtooth production technique. We will also implement the latest drilling, fracturing and completion techniques including shotgun duals to develop our properties as well as horizontal drilling. These horizontal wells will primarily target the Bossier formation and we anticipate these wells will yield significantly higher hydrocarbon flow rates than our vertical wells. We plan to begin our horizontal drilling programs in the second half of 2011.
●	Continue to lease underdeveloped acreage in the Cornerstone Project area. We are continuing our leasing program to support our present and future drilling plans with existing funding. The program includes renewing existing leasehold and acquiring new leaseholds. We are using our extensive proprietary database to help optimize additional drilling locations and to acquire additional acreage. We intend to target acreage with exploitation and technology upside within the Cornerstone Project area. Most properties in the Cornerstone Project area are held by smaller independent companies that lack the resources to exploit them to the fullest extent. We intend to pursue these opportunities to selectively expand our portfolio of properties. These acreage additions will complement our existing substantial acreage position in the area and provide us with significant additional drilling inventory.
●	Maintain a conservative and flexible financial strategy. We intend to continue focusing on maintaining a low level of corporate overhead expense in addition to continued utilization of outsourcing, when appropriate, to maximize cash flow. We believe this internally-generated cash flow, coupled with reserve-based debt financing when appropriate, will provide the optimal capital structure to fund our future drilling activity.

In order to implement our strategy, we will first need to raise additional capital to develop our properties. We are seeking to raise additional capital within the industry and financial institutions. We currently do not have any contracts or commitments for funding and there are no guarantees that we will be able to raise funds on terms acceptable to us, if at all. We may also consider farm-out agreements, whereby we would lease parts of our properties to other operators for drilling purposes and we would receive payment based on the production. We anticipate the cost of a horizontal oil well will be approximately $5 million and a vertical shallow gas well to be approximately $1 million.

Our oil and gas assets are located in Cass and Marion counties in northeast Texas. As of December 31, 2010, we operated 10 wells.

As of March 1, 2011, our leasehold position is 25,310 gross acres and 16,668 net acres with net working acres of 9,280, which represents 25% to 80% working interest in the acreage. Our leasing program consisted of renewing expiring leases and previously unleased acreages being leased. We began discussions with two independent oil and gas companies during the first quarter of 2010 regarding leasing specific areas on the Cornerstone project. Agreements were finalized in the middle of February and late March 2010 and could result in up to $4,000,000 and $4,700,000, respectively, in lease acquisitions. We have presently spent approximately $3.8 million of the funds. This includes both extensions and renewals of existing leasehold that we currently hold and acquisitions of new leaseholds in order to expand our acreage position. The participating companies are paying 100% of the cost for a 50% interest in the acreage, resulting in no cost to us. We believe that this will result in follow-up drilling opportunities. We also finalized drilling agreements with various independent oil and gas companies in 2010 that have provided approximately $1.3 million in funds towards the drilling of the Norbord and Swamp Fox wells. In addition to the operating wells, we own an 80% undivided interest in approximately 40 miles of natural gas pipeline as well as an 80% undivided interest in a saltwater and drilling fluid disposal system.

If we are able to obtain funding, our main emphasis will be to explore for oil with horizontal drilling. The present discussions are based on pursuing an aggressive drilling program where we would be carried for an interest in any wells at no cost to us. In addition, any funds could be used to apply fracture treatment to the Harris #2 and Childers #2 as well as deepening the Childers #1 and Harris #1. The deepening will be to a minimum depth to complete the wells in the Cotton Valley formation and possibly deeper in order to evaluate the Cotton Valley Lime formation.

Consolidated Results of Operations

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Summarized Consolidated Results of Operations

	2010 (As restated)			2009			Increase (Decrease)
Total revenues	$	996,943		$	1,006,118		$	(9,175	)
Total other operating expenses		1,109,185			1,148,693			(39,508	)
Total general and administrative expense		2,109,130			2,201,044			(91,914	)
Loss from operations		(2,221,372	)		(2,343,619	)		(122,247	)
Total other expenses		(4,269,801	)		(474,033	)		3,795,768
Loss before income tax benefit		(6,491,173	)		(2,817,652	)		3,673,521
Income tax benefit		-			5,702			(5,702	)
Net loss	$	(6,491,173	)	$	(2,811,950	)	$	3,679,223

Revenues: Total revenues for the year ended December 31, 2010 totaled $996,943 compared to $1,006,118, for the year ended December 31, 2009. Production revenues of oil and gas increased $40,797 to $578,207 for the year ended December 31, 2010 compared to $537,410 for the year ended December 31, 2009. Approximately $11,500 of this increase in revenues was from the Norbord well which began production in December 2010. The remaining increase reflects the impact of a rise in sales prices from production on our operated wells, for natural gas of about 20% and oil of about 34%. Transportation and gathering revenue increased $22,719 to $268,983 for the year ended December 31, 2010, compared to $246,264 for the year ended December 31, 2009. The increase was mainly due to the Norbord gas being carried on the pipeline beginning in December 2010. Saltwater disposal income for the year ended December 31, 2010 was $67,636 compared to $133,028 for the year ended December 31, 2009. The decrease of $65,392 was due to a decrease in drilling activity in the area requiring water disposal.

Expenses: Total operating expenses for the year ended December 31, 2010 were $3,218,315, compared to $3,349,737 for the year ended December 31, 2009 resulting in a total decrease of $131,422. This change is comprised primarily of decreases in general and administrative expenses, disposal expenses and lease operating expenses offset by increases in the cost of gas purchased for resale and pipeline operating expenses.

●

General and Administrative Expense: The $91,914 decrease in general and administrative expense to $2,109,130 for the year ended December 31, 2010 from $2,201,044 for the year ended December 31, 2009 is due to decreases in audit and accounting fees of $132,398, a decrease in regulatory filing expense of $39,567, and a decrease in loan fees of $150,000 offset by an increase in stock-based compensation of $230,302. The decrease in audit and accounting fees as well as regulatory filing expenses were due to continued efficiencies in the accounting work performed during the first quarter of 2010 related to the preparation of the 2009 10-K as compared to fees for accounting work in the first quarter of 2009 related to the preparation of the 2008 10-K. The decrease in loan fees was due to the termination in 2009 of an agreement with a financial advisor for assistance in finding financing.

●

Disposal Expense: The $94,578 decrease in saltwater disposal expenses to $198,572 for the year ended December 31, 2010 from $293,150 for the year ended December 31, 2009 is due to a decrease in the operating expenses as a result of the decrease in disposal activity as noted in the lower revenue in 2010. In addition, there were decreases in repairs and maintenance of $14,244 and contract labor of $37,023 during 2010.

●	· Lease Operating Expenses: The $76,043 decrease in lease operating expenses to $312,505 for the year ended December 31, 2010 from $388,548 for the year ended December 31, 2009 is primarily due to workover costs on the Bramlett and Ralph #1 wells incurred in the first half of 2009.

●

Cost of Gas Purchased for Resale: The $32,560 increase in cost of gas purchased for resale to $180,614 for the year ended December 31, 2010 from $148,054 for the year ended December 31, 2009 is due to an increase in the purchase price for natural gas and volumes purchased from operators in addition to a by higher volume produced in December 2010 due to the Norbord well starting production.

●

Pipeline Operating Expense: Pipeline operating expenses of $151,600 for the year ended December 31, 2010 increased $72,854 from $78,746 for the year ended December 31, 2009. The majority of the increase was due to $46,794 of contract labor on the Norbord well which was incurred in the last quarter of 2010. Other expenses related to the Norbord well such as engineering fees, chart integration, trucking, etc. were also incurred during the last quarter of 2010.

Other Income (Expenses): Total other expenses for the year ended December 31, 2010 was $4,269,801, compared to $474,033 for the year ended December 31, 2009. The primary reason for this $3,795,768 increase was a result of change in fair value of the derivative warrant liability pursuant to the reset provision in the warrant agreement which was triggered in December 2010. This provision generated a change of $3,638,311. The remaining change was due to a $138,405 increase in interest expense from $456,719 for the year ended December 31, 2009 to $595,124 for the year ended December 31, 2010 due to an increase in the balance of the line of credit as well as the addition of the accrued and unpaid interest on the Teton Note being added to the principal balance of the Teton Renewal Note on June 1, 2010 both of which resulted in higher interest expense.

Income Tax Expense: During the year ended December 31, 2010, we recognized an income tax benefit of $0 as compared to an income tax benefit of $5,702 for the year ended December 31, 2009 which was due to an over-accrual of the Texas Franchise tax liability in a prior year.

Net Loss: As a result of the above described revenues and expenses, we incurred a net loss of $6,491,173 in the year ended December 31, 2010 as compared to a net loss of $2,811,950 in the year ended December 31, 2009.

Liquidity and Capital Resources

We held approximately $250,000 in cash at December 31, 2010, made up of a majority of our cash accounts. However, at December 31, 2010, several cash accounts had an overdraft which totaled $340,118, resulting in an amount of cash owed of $90,118. The cash balance at December 31, 2009 was approximately $127,000. The decrease in cash is related to purchases of leases and well equipment and oil and gas properties and using cash to cover operating expenses. The decrease is partially offset by additional proceeds received from Teton, a related party, on our notes payable. In addition, our trade accounts payable have increased by $406,980 due to the drilling activity on the Norbord #1 and Swamp Fox #1 wells during the last quarter of 2010.

Cash Flows

The following table summarizes our cash flows for the years ended December 31:

	2010		2009
Total cash provided by (used in):
Operating activities	$	(1,137,309)	$	(1,643,875)
Investing activities		153,388		(489,615)
Financing activities		1,106,547		1,468,411
Increase (decrease) in cash and cash equivalents	$	122,626	$	(665,079)

Cash used in operating activities for the year ended December 31, 2010 totaled $1,137,309, compared to $1,643,875 used in operating activities for the year ended December 31, 2009. The decrease in cash used of $506,566 is primarily due to additional cash provided by changes in connection with operating assets and liabilities. The changes in operating assets and liabilities are primarily due to changes in accounts payable, accounts payable, related parties, and interest payable, related party. In addition, the operations during 2010 included a non-cash charge of $230,302 for stock-based compensation expense and a non-cash charge for the change in fair value of the derivative warrant liability of $3,638,311.

Cash provided by investing activities for the year ended December 31, 2010 was $153,388, compared to cash used of $489,615 for the year ended December 31, 2009. The change of $643,003 is due primarily to decreased drilling activities for the year ended December 31, 2010. We spent $459,421 on leasehold costs, lease and well equipment, and intangible drilling and completion costs during 2009 compared to $187,158 during 2010. During 2010, the participants in our drilling program paid for the intangible drilling and completion costs on the Norbord #1 well. This was offset by the additional purchases for the disposal system and pipeline of $117,402 during 2010 compared to $30,194 during 2009. In addition, we received $458,700 of proceeds on the sale of working interests in our new wells during 2010.

Cash provided by financing activities for the year ended December 31, 2010 totaled $1,106,547, compared to $1,468,411 of cash provided by financing activities for the year ended December 31, 2009. In 2010, we received cash proceeds of $773,000 on a related party note payable compared to proceeds of $1,475,000 for the year ended December 31, 2009.

Sources of Liquidity

Our two main sources of liquidity continue to be from funds generated by production promotion fees and financing from a related party in the form of notes payable. During 2010, we received promotion fees which pay for a portion or all of our cost in a proposed drilling well as well as prospect fees associated with the transactions. Any shortfall in revenue to cover costs has been covered by utilizing financing from a related party in the form of notes payable. We believe that the proceeds from production and continued promotion of prospects, joint ventures with industry partners, and our anticipated selling of our disposal plant will be sufficient to finance our operations for 2011. In addition, future acquisitions and future exploration, development, production and marketing activities, as well as administrative requirements (such as salaries, insurance expenses, general overhead expenses, legal compliance costs and accounting expenses) will require a substantial amount of additional capital and cash flow.

We are pursuing sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We have aggressively contacted many potential investors both within the industry as well as institutional investors to secure additional financing. Additional financing would be used for drilling opportunities and additional lease funding in the near future, along with working capital purposes. We do not have any commitments or agreements for financing, and we cannot assure you that additional funding will be available on terms acceptable to us, if at all.

We previously entered into a credit agreement with lenders led by Amegy Bank, N.A. Pursuant to the terms of the credit agreement, the aggregate commitment was $50 million, with no initial borrowing base or borrowing base reduction under the agreement. Upon satisfaction of various conditions precedent to the initial credit extension, the borrowing base was to be $5 million and the initial monthly borrowing base reduction was to be determined on the initial funding date. We did not meet the conditions prior to the maturity date of the agreement and we elected not to renew the agreement.

Off Balance Sheet Arrangements

We do not have any off balance sheet arrangements that are reasonably likely to have a current or future effect on our consolidated financial condition, revenues, results of operations, liquidity or capital expenditures.

Critical Accounting Policies

Our critical accounting policies, including the assumptions and judgments underlying them, are disclosed in the notes to consolidated financial statements which accompany the consolidated financial statements. These policies have been consistently applied in all material respects and address such matters as revenue recognition and depreciation methods. The preparation of consolidated 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 and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the recorded amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

Accounts Receivable

We perform ongoing credit evaluations of our customers’ financial condition and extend credit to virtually all of our customers. Collateral is generally not required, nor is interest charged on past due balances. Credit losses to date have not been significant and have been within management’s expectations. In the event of complete non-performance by our customers, our maximum exposure is the outstanding accounts receivable balance at the date of non-performance.

Property and Equipment

Property and equipment are stated at cost and depreciated using the straight-line method over the estimated useful lives of the assets, which range from five to thirty-nine years. Expenditures for major renewals and betterments that extend the useful lives are capitalized. Expenditures for normal maintenance and repairs are expensed as incurred. Upon the sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts and any gains or losses thereon are recognized in the operating results of the respective period.

Oil and Gas Properties

We use the full-cost method of accounting for our oil and gas producing activities, which are all located in Texas. Accordingly, all costs associated with the acquisition, exploration, and development of oil and gas reserves, including directly-related overhead costs, are capitalized.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the units-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment will be added to the capitalized costs to be amortized.

In addition, the capitalized costs are subject to a “ceiling test,” which limits such costs to the aggregate of the “estimated present value,” discounted at a ten percent interest rate, of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties and less the income tax effects related to the properties.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the operating results of the respective period.

Derivative Instruments

For derivative instruments that are accounted for as liabilities, the derivative instrument is initially recorded at its fair value and is then re-valued at each reporting date, with changes in fair value recognized in earnings each reporting period. For warrant derivative instruments, the Company uses the Black-Scholes model to value the derivative instruments at inception and subsequent valuation dates. The classification of derivative instruments, including whether such instruments should be recorded as a liability or as equity, is re-assessed at the end of each reporting period, in accordance with FASB ASC Topic 815, Derivatives and Hedging. Derivative instrument liabilities are classified in the balance sheet as current or non-current based on whether or not the net-cash settlement of the derivative instrument could be required within 12 months of the balance sheet date.

Revenue Recognition

We utilize the accrual method of accounting for natural gas and crude oil revenues, whereby revenues are recognized based on our net revenue interest in the wells. Crude oil inventories are immaterial and are not recorded.

Gas imbalances are accounted for using the entitlement method. Under this method, revenues are recognized only to the extent of our proportionate share of the gas sold. However, we have no history of significant gas imbalances.

Income Taxes

Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which such temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the operating results of the period that includes the enactment date. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.

Recently Issued Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. This standard requires reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy established by Statement of Financial Accounting Standards (“SFAS”) No. 157 (FASB ASC 820). The guidance is effective for any interim and annual reporting periods that begin after December 15, 2009. The Company adopted ASU No. 2010-06 in the first quarter of 2010 and the adoption did not have a material impact on the Company’s disclosures. The standard also requires entities to provide a reconciliation of purchases, sales, issuance, and settlements of anything valued with a Level 3 method. This guidance is effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The Company is currently assessing the impact that the adoption will have on its disclosures.

In April 2010, the FASB issued ASU 2010-13, “Compensation-Stock Compensation (Topic 718)-Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades.” ASU 2010-13 provides amendments to Topic 718 to clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. The amendments in ASU 2010-13 are effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010. The adoption of this standard will not have an effect on the Company’s results of operations or financial position.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Not required under Regulation S-K for “smaller reporting companies.”

ITEM 8. FINANCIAL STATEMENTS.

PEGASI ENERGY RESOURCES CORPORATION

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

		Page
Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets as of December 31, 2010 and 2009		F-3

Consolidated Statements of Operations for the years ended December 31, 2010 and 2009		F-5

Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2010 and 2009		F-6

Consolidated Statements of Cash Flows for the years ended December 31, 2010 and 2009		F-7

Notes to Consolidated Financial Statements		F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Pegasi Energy Resources Corporation and subsidiaries

We have audited the accompanying consolidated balance sheets of Pegasi Energy Resources Corporation and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. An audit includes 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 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 consolidated financial statements, assessing the accounting principles used and significant estimates made by management, and 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 referred to above present fairly, in all material respects, the financial position of Pegasi Energy Resources Corporation and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3, the Company restated its consolidated financial statements as of and for the year ended December 31, 2010.

/s/ Whitley Penn LLP

Dallas, Texas

March 31, 2011, except for Notes 2, 3, 10, 11 and 12 to which the date is August 22, 2011.

F-2

PEGASI ENERGY RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS


	December 31,
	2010			2009
Assets
Current assets:
Cash and cash equivalents	$	249,802		$	127,176
Accounts receivable, trade		186,669			98,578
Accounts receivable, related parties		13,002			13,002
Joint interest billing receivable, related parties, net		192,700			17,983
Joint interest billing receivable, net		29,627			-
Other current assets		52,440			51,288
Total current assets		724,240			308,027

Property and equipment:
Equipment		688,002			601,759
Pipelines		722,937			700,765
Buildings		19,916			19,916
Leasehold improvements		7,022			7,022
Vehicles		50,663			50,663
Office furniture		135,689			137,071
Website		15,000			15,000
Total property and equipment		1,639,229			1,532,196
Less accumulated depreciation		(658,528	)		(515,101	)
Property and equipment, net		980,701			1,017,095

Oil and gas properties:
Oil and gas properties, proved		11,762,909			11,928,985
Oil and gas properties, unproved		9,044,960			9,150,426
Capitalized asset retirement obligations		219,040			220,237
Total oil and gas properties		21,026,909			21,299,648
Less accumulated depletion and depreciation		(1,018,100	)		(900,275	)
Oil and gas properties, net		20,008,809			20,399,373

Other assets:
Restricted cash – leasing program		394,693			-
Restricted cash – drilling program		793,611			-
Certificates of deposit		77,947			77,195
Total other assets		1,266,251			77,195

Total assets	$	22,980,001		$	21,801,690

The accompanying notes are an integral part of these consolidated financial statements.

F-3

PEGASI ENERGY RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS (continued)

	December 31,
	2010			2009
	(As Restated)
Liabilities and Stockholders' Equity
Current liabilities:
Cash overdraft	$	340,118		$	-
Accounts payable		658,316			251,336
Accounts payable, related parties		1,321,979			874,076
Revenue payable		124,723			104,366
Interest payable, related parties		394,704			840,052
Liquidated damages payable		173,802			142,083
Other payables		27,893			35,795
Current portion of notes payable		1,976			6,570
Current portion of notes payable, related parties		8,160,646			6,352,303
Total current liabilities		11,204,157			8,606,581

Lease program deposits		394,693			-
Drilling prepayments		793,611			-
Notes payable		2,826			4,803
Asset retirement obligations		317,279			300,311
Derivative warrant liability		3,638,311			-
Total liabilities		16,350,877			8,911,695

Commitments and contingencies (Note 18)

Stockholders' equity:
Preferred stock: $0.001 par value; 5,000,000 shares authorized; none issued and outstanding		-			-
Common stock: $0.001 par value; 125,000,000 shares authorized; 33,610,801 shares issued and outstanding		33,611			33,611
Additional paid-in capital		19,903,404			19,673,102
Accumulated deficit		(13,307,891	)		(6,816,718	)
Total stockholders' equity		6,629,124			12,889,995

Total liabilities and stockholders' equity	$	22,980,001		$	21,801,690

The accompanying notes are an integral part of these consolidated financial statements

F-4

PEGASI ENERGY RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

		Year Ended December 31,
		2010		2009
		(As Restated)
Revenues:
Oil and gas	$	578,207	$	537,410
Condensate and skim oil		82,117		89,416
Transportation and gathering		268,983		246,264
Saltwater disposal income		67,636		133,028
Total revenues		996,943		1,006,118
Operating expenses:
Lease operating expenses		312,505		388,548
Saltwater disposal expenses		198,572		293,150
Pipeline operating expenses		151,600		78,746
Cost of gas purchased for resale		180,614		148,054
Depletion and depreciation		265,894		240,195
General and administrative		2,109,130		2,201,044
Total operating expenses		3,218,315		3,349,737
Loss from operations		(2,221,372)		(2,343,619)

Other income (expenses):
Interest income		752		2,431
Interest expense		(595,124)		(456,719)
Other expense, net		(37,118)		(19,745)
Changes in fair value of warrant derivative liability		(3,638,311)		-
Total other expenses, net		(4,269,801)		(474,033)

Loss before income tax benefit		(6,491,173)		(2,817,652)

Income tax benefit		-		5,702
Net loss	$	(6,491,173)	$	(2,811,950)

Basic and diluted loss per share	$	(0.19)	$	(0.08)

Weighted average shares outstanding – basic and diluted		33,610,801		33,610,801

The accompanying notes are an integral part of these consolidated financial statements

F-5

PEGASI ENERGY RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Years Ended December 31, 2010 and 2009

					Additional
	Common Stock				Paid-in		Accumulated
	Shares		Amount		Capital		Deficit			Total

Balance at December 31, 2008		33,610,801	$	33,611	$	19,673,102	$	(4,004,768	)	$	15,701,945
Net loss		-		-		-		(2,811,950	)		(2,811,950	)
Balance at December 31, 2009		33,610,801		33,611		19,673,102		(6,816,718	)		12,889,995
Stock-based compensation		-		-		230,302		-			230,302
Net loss (As Restated)		-		-		-		(6,491,173	)		(6,491,173	)
Balance at December 31, 2010 (As Restated)		33,610,801	$	33,611	$	19,903,404	$	(13,307,891	)	$	6,629,124

The accompanying notes are an integral part of these consolidated financial statements

F-6

PEGASI ENERGY RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2010		2009
	(As Restated)
Operating Activities
Net loss	$	(6,491,173)	$	(2,811,950)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion and depreciation		265,894		240,195
Accretion of discount on asset retirement obligations		18,165		17,004
Stock based compensation		230,302		-
Loss on abandonment of equipment		5,727		-
Change in fair value of warrant derivative liability		3,638,311		-
Changes in operating assets and liabilities:
Accounts receivable, trade		(88,091)		151,073
Accounts receivable, related parties		-		56,406
Joint interest billing receivable, related parties, net		(174,717)		40,266
Joint interest billing receivable, net		(29,627)		-
Other current assets		(1,152)		38,489
Accounts payable		406,980		48,626
Accounts payable, related parties		447,903		209,080
Revenue payable		20,357		(90,194)
Interest payable, related parties		589,995		454,892
Liquidated damages payable		31,719		20,504
Other payables		(7,902)		(18,266)
Net cash used in operating activities		(1,137,309)		(1,643,875)

Investing Activities
Additions to certificates of deposit		(752)		-
Purchases of property and equipment		(117,402)		(30,194)
Purchases of oil and gas properties		(187,158)		(459,421)
Proceeds from sale of working interest		458,700		-
Net cash (used in) provided by investing activities		153,388		(489,615)

Financing Activities
Payments on notes payable		(6,571)		(6,589)
Cash overdraft		340,118		-
Borrowings on notes payable, related party		773,000		1,475,000
Net cash provided by financing activities		1,106,547		1,468,411

Net increase (decrease) in cash and cash equivalents		122,626		(665,079)
Cash and cash equivalents at beginning of year		127,176		792,255
Cash and cash equivalents at end of year	$	249,802	$	127,176

See Note 4 for supplemental cash flow and non-cash information.

The accompanying notes are an integral part of these consolidated financial statements

F-7

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

1. NATURE OF OPERATIONS

Pegasi Energy Resources Corporation (“PERC,” or the “Company”) is engaged in the exploration and production of natural gas and oil through the development of a repeatable, low geological risk, high potential project in the active East Texas oil and gas region. The Company's business strategy, which it designated as the “Cornerstone Project,” is to identify and exploit resources in and adjacent to existing or indicated producing areas within the Rodessa field area. PERC’s principals spent over three years and invested over $3.5 million in equity for data harvesting, prospect evaluation and acreage acquisitions for the Cornerstone Project.

PERC is the successor entity to First Southern Crown Ltd. ("FSC"), a Texas limited partnership formed in December 2002. In December 2004, FSC sold a thirty percent (30%) interest in all of its production, acreage position, pipeline and a thirty percent (30%) partnership interest in 59 Disposal, Inc. ("59 Disposal") (PERC’s disposal plant) to Marion Energy Limited ("Marion"), an entity publicly traded on the Australian stock exchange ("ASE.ax"). In February 2007, Marion traded its 30% partnership interest in 59 Disposal for a 30% undivided ownership in 59 Disposal’s assets. Marion later sold its 30% undivided interest in 59 Disposal’s assets, its production interest, acreage position, and its pipeline interest to TR Energy, Inc. (“TR Energy”), a related party. In 2008, the Company acquired an additional 10% interest in these assets in exchange for 4.2 million shares of the Company’s stock.

PERC conducts its main exploration and production operations through its wholly-owned subsidiary, Pegasi Operating, Inc. ("POI"). It conducts additional operations through two other wholly-owned subsidiaries: (i) TR Rodessa, Inc. ("TR Rodessa") and (ii) 59 Disposal.

TR Rodessa owns an 80% undivided interest in and operates a 40-mile natural gas pipeline and gathering system which is currently being used by PERC to transport its hydrocarbons to market. Excess capacity on this system is used to transport third-party hydrocarbons. 59 Disposal owns an 80% undivided interest in and operates a saltwater disposal facility which disposes saltwater and flow back waste into subsurface storage.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

a) Consolidation and Use of Estimates

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted (“GAAP”) in the United States of America and include the accounts of PERC and its wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures. Actual results may differ from these estimates.

Estimates made in preparing these consolidated financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating depletion expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; operating costs accrued; volumes and prices for revenues accrued; estimates of the fair value of stock-based compensation awards; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods.

b) Cash and Cash Equivalents

We consider all highly-liquid investments with an original maturity of three months or less, when purchased, to be cash equivalents. At December 31, 2010 and 2009, the Company had no cash equivalents.

F-8

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

c) Accounts Receivable

The Company’s accounts receivable consists primarily of oil and natural gas sales and joint interest billings, which are recorded at the invoiced amount. Collateral is not required for such receivables, nor is interest charged on past due balances. The Company extends credit based on management’s assessment of the customers’ financial condition and evaluates the allowance for doubtful accounts based on receivable aging, customer disputes and general business and economic conditions. No allowance was indicated at December 31, 2010 or 2009. Accounts receivables from three customers approximated 38%, 36%, and 19% of the Company’s total trade receivables at December 31, 2010. As of December 31, 2009, three customers, two of which are the same customers, totaled approximately 44%, 37%, and 15% of total accounts receivable.

d) Property and Equipment

Property and equipment are recorded at cost and depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from five to thirty-nine years. Expenditures for major renewals and betterments that extend the useful lives are capitalized. Expenditures for normal maintenance and repairs are expensed as incurred. Upon sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts and any gains or losses thereon are recognized in the operating results of the respective period. Depreciation expense was $148,069 and $146,223 for the years ended December 31, 2010 and 2009, respectively.

e) Oil and Gas Properties

The Company uses the full-cost method of accounting for its oil and gas producing activities, which are all located in Texas. Accordingly, all costs associated with the acquisition, exploration, and development of oil and gas reserves, including directly related overhead costs, are capitalized.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the units-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment shall be added to the capitalized costs to be amortized.

In addition, the capitalized costs are subject to a “ceiling test,” which limits such costs to the aggregate of the “estimated present value,” discounted at a 10 percent interest rate of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties and less the income tax effects related to the properties. As capitalized costs do not exceed the “ceiling,” the accompanying consolidated financial statements do not include a provision for such impairment of oil and gas property costs for the years ended December 31, 2010 and 2009.

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2010, by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The 2010 amount is net of reimbursements received in the current year for costs incurred in prior years under our leasing program. The majority of the evaluation activities are expected to be completed within five to ten years.

													2007
	Total			2010			2009			2008			and Prior
	(In thousands)
Property acquisition costs		$	9,045		$	(105)		$	435		$	4,679		$	4,036

F-9

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

f) Impairment of Long-Lived Assets

The carrying value of property and equipment is periodically evaluated under the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic No. 360, Property, Plant, and Equipment. FASB ASC Topic No. 360 requires long-lived assets and certain identifiable intangibles to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. The Company had no impairment in 2010 and 2009.

g) Asset Retirement Obligations

FASB ASC Topic No. 410, Asset Retirement and Environmental Obligations, requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of the Company’s oil and natural gas properties at its discounted fair value. The liability is then accreted up by recording expense each period until it is settled or the well is sold, at which time the liability is reversed. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. See Note 8 – Asset Retirement Obligations for additional information.

h) Revenue Recognition

The Company utilizes the accrual method of accounting for natural gas and crude oil revenues, whereby revenues are recognized based on the Company’s net revenue interest in the wells. Crude oil inventories are immaterial and are not recorded. Gas imbalances are accounted for using the entitlement method. Under this method revenues are recognized only to the extent of the Company’s proportionate share of the gas sold. However, the Company has no history of significant gas imbalances.

i) Stock-based Compensation

The Company has accounted for stock-based compensation under the provisions of FASB ASC 718-10-55. The Company recognizes stock-based compensation expense in the consolidated financial statements for equity-classified employee stock-based compensation awards based on the grant date fair value of the awards. Equity instruments issued to non-employees are accounted for under the same provisions. During the years ended December 31, 2010 and 2009, the Company recognized $230,302 and $0, respectively, of stock-based compensation expense which has been recorded as a general and administrative expense in the consolidated statements of operations.

j) Derivative Instruments

F-10

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

k) Income Taxes

Deferred income taxes are determined using the “liability method” in accordance with FASB ASC Topic No. 740, Income Taxes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the operating results of the period that includes the enactment date. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.

l) Net Loss per Common Share

Basic net loss per common share is calculated using the weighted average number of common shares outstanding during the period. The Company uses the treasury stock method of calculating fully diluted per share amounts whereby any proceeds from the exercise of stock options or other dilutive instruments are assumed to be used to purchase common shares at the average market price during the period. The dilutive effect of convertible securities is reflected in diluted loss per share by application of the if-converted method. Under this method, conversion shall not be assumed for the purposes of computing diluted loss per share if the effect would be anti-dilutive. For the years ended December 31, 2010 and 2009 the Company had potentially dilutive shares of 26,985,880 and 10,666,834, respectively. For the years ended December 31, 2010 and 2009, the diluted loss per share is the same as basic loss per share, as the effect of common stock equivalents are anti-dilutive.

m) Fair Value of Financial Instruments

ASC Topic 825 requires certain disclosures regarding the fair value of financial instruments. Fair value of financial instruments is made at a specific point in time, based on relevant information about financial markets and specific financial instruments. As these estimates are subjective in nature, involving uncertainties and matters of significant judgment, they cannot be determined with precision. Changes in assumptions can significantly affect estimated fair values.

ASC Topic 820 defines fair value as the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. When determining the fair value measurements for assets and liabilities required or permitted to be recorded at fair value, the Company considers the principal or most advantageous market in which it would transact and it considers assumptions that market participants would use when pricing the asset or liability.

ASC Topic 820 establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. A financial instrument’s categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. ASC Topic 820 establishes three levels of inputs that may be used to measure fair value:

Level 1 - Level 1 applies to assets or liabilities for which there are quoted prices in active markets for identical assets or liabilities.

Level 2 - Level 2 applies to assets or liabilities for which there are inputs other than quoted prices included within Level 1 that are observable for the asset or liability such as quoted prices for similar assets or liabilities in active markets; quoted prices for identical

assets or liabilities in markets with insufficient volume or infrequent transactions (less active markets); or model-derived valuations in which significant inputs are observable or can be derived principally from, or corroborated by, observable market data.

Level 3 - Level 3 applies to assets or liabilities for which there are unobservable inputs to the valuation methodology that are significant to the measurement of the fair value of the assets or liabilities.

The following table sets forth our estimate of fair value of our financial instruments that are liabilities as of December 31, 2010:

	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Total
2007 Warrants	$	-	$	3,638,311	$	-	$	3,638,311

The following table sets forth a summary of changes in fair value of our derivative liability for the years ended December 31, 2010 and 2009:

	2010		2009
Beginning Balance	$	-	$	-
Expense included in net loss		3,638,311		-
Balance at December 31	$	3,638,311	$	-

In accordance with the reporting requirements of FASB ASC Topic No. 825, Financial Instruments, the Company calculates the fair value of its assets and liabilities which qualify as financial instruments under this statement and includes this additional information in the notes to consolidated financial statements when the fair value is different than the carrying value of these financial instruments. The estimated fair values of accounts receivable, accounts payable and other current assets and accrued liabilities approximate their carrying amounts due to the relatively short maturity of these instruments. The carrying value of long-term debt approximates market value due to the use of market interest rates.

n) New Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. This standard requires reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy established by Statement of Financial Accounting Standards (“SFAS”) No. 157 (FASB ASC 820). The guidance is effective for any interim and annual reporting periods that begin after December 15, 2009. The Company adopted ASU No. 2010-06 in the first quarter of 2010 and the adoption did not have a material impact on the Company’s disclosures. The standard also requires entities to provide a reconciliation of purchases, sales, issuance, and settlements of anything valued with a Level 3 method. This guidance is effective for fiscal years beginning after December 15, 2010, and for interim and periods within those fiscal years. The Company is currently assessing the impact that the adoption will have on its disclosures.

F-11

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

3. RESTATEMENT

On August 10, 2011, the Company filed with the Securities and Exchange Commission (“SEC”) a Current Report on Form 8-K, to report management’s determination that the Company’s consolidated financial statements for the year ended December 31, 2010, included in its Annual Report on Form 10-K filed with the SEC on March 31, 2011 (the “2010 Form 10-K”), should not be relied upon due to an error in such consolidated financial statements with respect to the accounting for common stock purchase warrants in connection with its December 2007 private placement (the “2007 Warrants”). The Company determined that the historical consolidated financial statements for the year ended December 31, 2010 included in the Company’s 2010 Form 10-K require restatement to record the 2007 Warrants as a derivative liability and to properly reflect the liability through adjustment to Other Income/Expense in the Consolidated Statement Operations.

The Company has performed a complete assessment of its outstanding 2007 Warrants and has concluded that its outstanding 2007 Warrants are within the scope of Accounting Standards Codification 815-40, “Derivatives and Hedging – Contracts in Entity’s Own Equity” (“ASC 815-40”), formerly Emerging Issues Task Force Issue No. 07-05, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock” (“EITF 07-05”), due to the inclusion in the Warrants of a provision requiring an adjustment to the number of shares and the exercise price of the 2007 Warrants in the event the Company issues common stock, or securities convertible into or exercisable for common stock, at a price per share lower than such exercise price. Accordingly, ASC 815-40, formerly EITF 07-05, which was effective as of January 1, 2009, should have been applied resulting in a reclassification of the warrants as a liability, measured at fair value, with changes in fair value recognized as part of other income or expense for each reporting period thereafter. The issuance of non-excluded stock options to a third party in December 2010 triggered the anti-dilution protection rights which reduced the exercise price of the Warrants and increased the number of shares of common stock issuable upon exercise of the Warrants. As a result of the adjustment the exercise price was adjusted from $1.60 to $0.42 and the number of shares issuable upon exercise of the Warrants increased from 5,035,367 to 19,182,350.

This amended Annual Report on Form 10-K/A for the fiscal year ended December 31, 2010 incorporates corrections made in response to the accounting errors described above by restating the Company’s consolidated financial statements presented herein for the year ended December 31, 2010. The corrections to the annual information in this amended Form 10-K/A had no impact on the Company’s previously reported operations from oil and gas activities or cash flows for the periods being restated. However, a derivative liability has been recorded on the Consolidated Balance Sheet and a corresponding non-cash charge to Other Income/Expense has been reported on the Consolidated Statement of Operations.

The Company determined that it did not properly record its derivative liability related to the 2007 Warrants pursuant to ASC 815-40 upon its effective date of January 1, 2009 which required these Warrants to be recorded on the balance sheet at fair value. This misstatement was determined by the Company to be immaterial to the previously issued consolidated financial statements for the year ended December 31, 2009, included in the Company’s Form 10-K filed March 29, 2010, and each of the quarterly periods from March 31, 2009 through September 30, 2010 included in the Company’s quarterly reports on Form 10-Q (collectively, the “Affected Periods”). Accordingly, the consolidated financial statements for the Affected Periods are not being restated.

The following tables show the effects of the restatement on the Company's consolidated balance sheet as of December 31, 2010 and consolidated statements of operations and cash flows for the year ended December 31, 2010:

Pegasi Energy Resources Corporation

Consolidated Balance Sheets

	As of December 31, 2010
	As Previously Reported			As Restated

Derivative warrant liability	$	-		$	3,638,311

Total liabilities	$	12,712,566		$	16,350,877

Accumulated deficit	$	(9,669,580	)	$	(13,307,891	)

Total stockholders’ equity	$	10,267,435		$	6,629,124

Pegasi Energy Resources Corporation

Consolidated Statement of Operations

	Year ended December 31, 2010
	As Previously Reported			As Restated

Changes in fair value of warrant derivative liability	$	-		$	(3,638,311	)

Total other income (expense)	$	(631,490	)	$	(4,269,801	)

Net loss	$	(2,852,862	)	$	(6,491,173	)

Basic and diluted loss per share	$	(0.08	)	$	(0.19	)

The loss resulting from the change in fair value of the warrant derivative liability for the year ended December 31, 2010, was incurred at the corporate level. The Company did not recognize any income tax benefits (expense) associated with the change in fair value for the year ended December 31, 2010. Therefore, the restatement did not have an effect on the Company’s taxable income for the year ended December 31, 2010.

Pegasi Energy Resources Corporation

Consolidated Statement of Cash Flows

	Year ended December 31, 2010
	As Previously Reported			As Restated

Net loss	$	(2,852,862	)	$	(6,491,173	)

Changes in fair value of warrant derivative liability		-			3,638,311

Net cash used in operating activities	$	(1,137,309	)	$	(1,137,309	)

F-12

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

4. SUPPLEMENTAL CASH FLOW AND NON-CASH INFORMATION

The following non-cash transactions were recorded during the years ended December 31:

	2010		2009
Accounts payable, related parties converted into notes payable, related parties	$	-	$	20,000
Interest payable, related parties converted into notes payable, related parties	$	1,035,343	$	-

The following is supplemental cash flow information for the years ended December 31:

		2010		2009
Cash paid during the year for interest	$	5,129	$	1,827
Cash paid during the year for taxes	$	-	$	-

F-13

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

5. PROPERTY AND EQUIPMENT

Property and equipment consists of the following:

	Depreciation Methods	Depreciation Period
Equipment	Straight-line	7 Years
Pipelines	Straight-line	15 Years
Buildings	Straight-line	39 Years
Leasehold improvements	Straight-line	Lesser of the Estimated Useful Life or the Lease Term
Vehicles	Straight-line	5 Years
Office furniture	Straight-line	5 Years
Website	Straight-line	5 Years

6. NOTES PAYABLE AND CAPITAL LEASES

Notes payable and capital leases consisted of the following at December 31:

	2010		2009
Capital lease in the original amount of $9,521 to Xerox Corporation, with monthly
installments of $184, including interest at 6.00%, maturing April 1, 2013	$	4,802	$	6,664

Note payable in the original amount of $22,548 to Capital One (formerly Hibernia Bank),
with monthly installments of $442, including interest at 6.59%, collateralized by a truck,
matured November 7, 2010.		-		4,709

Total notes payable and capital leases		4,802		11,373
Less current portion		1,976		6,570

Total long term (notes payable and capital leases)	$	2,826	$	4,803

Future annual maturities of notes payable and capital leases at December 31, 2010 are as follows:

Year Ended
2011	$	1,976
2012		2,098
2013		728

Total	$	4,802

F-14

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

7. NOTES PAYABLE, RELATED PARTIES

Notes payable, related parties consisted of the following at December 31:

	2010		2009
Original note payable dated May 21, 2007 to Teton (the “Teton Note”). Additional funds
added by amendments two, four and five to the note result in an outstanding balance of
$5,952,303, including interest at 8%, with all interest and principal due on the maturity date
of May 21, 2010. Substantially all of the Company’s assets are pledged as collateral on the note. Upon maturity this note was replaced with the “Teton Renewal Note” below.	$	-	$	5,952,303

Note payable to Teton (the “Teton Renewal Note”) in the amount of $6,987,646 dated June 1, 2010, including interest at 8%, with all principal due on the maturity date of June 1, 2011. Interest payments are due April 1, 2011; and at maturity. Renewed original note above which matured May 21, 2010. Secured by a stock pledge and security agreement.		6,987,646		-

Original unsecured promissory note payable in the amount of $1 million dated October 14, 2009 to Teton (the “Teton Promissory”). Additional funds added by amendment two to the note results in funds available of $1.5 million, including interest of 6.25%, with all interest and principal due on the maturity date of April 2, 2011.		1,173,000		400,000

Total notes payable, related parties		8,160,646		6,352,303
Less current portion		(8,160,646)		(6,352,303)
Total long-term notes payable, related parties	$	-	$	-

On June 1, 2010, a Promissory (Teton Renewal Note) note was executed to renew and extend the original note payable (Teton Note) which matured May 21, 2010. The renewal note’s principal balance of $6,987,646 is the total of the outstanding principal of $5,952,303 and accrued and unpaid interest of $1,035,343 on the original note. Effective October 1, 2010 an amendment to the Teton Renewal Note was executed to eliminate the October 1, 2010 interest payment. Effective January 2, 2011, a second amendment was executed which eliminated the January 1, 2011 interest payment. The final maturity date of the Teton Renewal Note was unchanged and remains June 1, 2011. Teton has the right, but not the obligation to convert all or a portion of the indebtedness at any time after May 1, 2008, unless the debt is repaid before such date. This option will continue in existence as long as any balance remains outstanding on the note.

The Teton Promissory was amended effective January 1, 2010 to eliminate the requirement of interest payments to be made on January 1, 2010; April 1, 2010; and October 1, 2010. A second amendment was executed which increased the available balance to $1,500,000 effective March 2, 2010. Effective July 1, 2010, a third amendment to the Teton Promissory was executed to eliminate the interest payment required on July 1, 2010 and to extend the maturity date of the note to January 2, 2011. Effective January 2, 2011, a fourth amendment was executed to extend the maturity date of the note from January 2, 2011, to April 2, 2011 at which time all outstanding principal and accrued and unpaid interest will be due.

On May 1, 2007, a “Memorandum of Understanding” was executed to grant Teton the right to convert the outstanding balance on the Teton Note into shares of PERC’s common stock at a fixed conversion price of $1.20 per share. Teton has the right, but not the obligation to convert all or a portion of the indebtedness at any time after May 1, 2008, unless the debt is repaid before such date. This option will continue in existence as long as any balance remains outstanding on the note.

F-15

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

On March 3, 2009, a “Second Amendment to Renewal Promissory Note and Loan Modification Agreement” (the “Second Amendment”) was executed, which amended the Teton Note. This agreement added $550,000 of additional cash proceeds and $20,000 of advances payable to the outstanding balance of the Teton Note and pledged substantially all of the Company’s assets to secure repayment of the note. The Second Amendment confirmed that the fixed conversion price of $1.20 per share would remain for the portion of the note payable balance that existed prior to its execution, and a fixed conversion price of $1.60 was agreed upon for conversion of the additional funds.

In May 2009, the third and fourth amendments to the Teton Note were executed. The third amendment deferred the May 21, 2009 interest payment to September 21, 2009 and the fourth amendment added $350,000 of additional funds to the outstanding balance of the Teton Note. In September 2009, the fifth amendment was executed, which added $175,000 of additional funds to the outstanding balance of the Teton Note and deferred the interest payment due date from September 21, 2009 to October 21, 2009. In February 2010, the seventh amendment to the Teton Note, dated May 21, 2007, was executed. This amendment amended the sixth amendment, executed in October 2009, to defer the October 21, 2009 interest payment to February 21, 2010. The seventh amendment eliminated the February 21, 2010 interest payment. The final maturity date of the Teton Note was unchanged and remained May 21, 2010. Upon maturity, the outstanding principal and accrued and unpaid interest on this note was renewed and extended to a maturity date of June 1, 2011. See the Teton Renewal Note above.

8. ASSET RETIREMENT OBLIGATIONS

Pursuant to FASB ASC Topic No. 410, Asset Retirement and Environmental Obligations, the Company has recognized the fair value of its asset retirement obligations related to the plugging, abandonment, and remediation of oil and gas producing properties. The present value of the estimated asset retirement costs has been capitalized as part of the carrying amount of the related long-lived assets, which approximated $219,040 and $220,237 at December 31, 2010 and 2009, respectively.

The liability has been accreted to its present value as of the end of each year. The Company evaluated 15 wells, and has determined a range of abandonment dates through June 2025.

The following represents a reconciliation of the asset retirement obligations for the years ended December 31:

	2010		2009

Asset retirement obligations at beginning of year	$	300,311	$	283,307
Asset retirement obligations incurred in the current year				-
Revisions to estimates		(1,197)		-
Accretion of discount		18,165		17,004
Asset retirement obligations at end of year	$	317,279	$	300,311

In order to ensure current costs are reflected in the estimation of retirement costs, the Company obtained assurance from its independent petroleum engineer in 2010 that the plugging costs used in the estimation are appropriate. The Company uses the expected present value technique to measure the fair value of the asset retirement obligations which is classified as a Level 3 measurement under FASB ASC Topic No. 820, Fair Value Measurements and Disclosures.

9. STOCK-BASED COMPENSATION

The Company has granted stock options to key employees, directors, and consultants as discussed below:

On May 29, 2007, the Company adopted the 2007 Stock Option Plan (the “2007 Plan”) for employees, consultants and such other persons selected by the plan administrator to provide a means to retain the services of such employees and strengthen their incentive to achieve the objectives of the Company and to provide an equity incentive to consultants and other persons to promote the success of the Company. The 2007 Plan reserves 1,750,000 shares of common stock for issuance by the Company as stock options.

F-16

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

On October 19, 2010, the Company adopted the 2010 Incentive Stock Option Plan (the “2010 Plan”) for directors, executives, and selected employees and consultants to reward them for making major contributions to the success of the Company by issuing long-term incentive awards under the 2010 Plan thereby providing them with an interest in the growth and performance of the Company. The 2010 Plan reserves 5,000,000 shares of common stock for issuance by the Company as stock options, stock awards or restricted stock purchase offers.

On December 24, 2010, pursuant to the 2010 Plan, the Company issued stock options for 1,059,285 shares of common stock at an exercise price of $0.42 per share and 10,000 shares of common stock at an exercise price of $0.50 per share to various executives, and selected employees and consultants for their contributions to the success of the Company. All of the options vested immediately upon issuance at December 24, 2010, and are exercisable at any time, in whole or part, until December 24, 2015. There were no stock options granted during the year ended December 31, 2009.

A summary of option activity during the years ended December 31, 2010 and 2009 is as follows:

	Options		Weighted Average Exercise Price		Weighted Average Grant Date Fair Value

Outstanding at January 1, 2009		900,000	$	1.20	$	-
Options granted		-		-		-
Options exercised		-		-		-
Outstanding at December 31, 2009		900,000		1.20		-
Options granted		1,069,285		0.42		0.22
Options exercised		-		-		-
Outstanding at December 31, 2010		1,969,285	$	0.78	$	-

The following is a summary of stock options outstanding at December 31, 2010:


Exercise		Options		Remaining Contractual		Options
Price		Outstanding		Lives (Years)		Exercisable
$	1.20		900,000		2		900,000
$	0.42		1,059,285		5		1,059,285
$	0.50		10,000		5		10,000

Based on the Company's stock price of $0.30 at December 31, 2010, the options outstanding had no intrinsic value.

Total options exercisable at December 31, 2010 amounted to 1,969,285 shares and had a weighted average exercise price of $0.78. Upon exercise, the Company issues the full amount of shares exercisable per the term of the options from new shares. The Company has no plans to repurchase those shares in the future. The following is a summary of options exercisable at December 31, 2010 and 2009:

			Weighted Average
	Shares		Exercise Price
December 31, 2010		1,969,285	$	0.78
December 31, 2009		900,000	$	1.20

F-17

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

The Company estimates the fair value of stock options using the Black-Scholes option pricing valuation model, consistent with the provisions of FASB ASC Topic No. 505, Equity and FASB ASC Topic No. 718, Compensation—Stock Compensation. Key inputs and assumptions used to estimate the fair value of stock options include the grant price of the award, the expected option term, volatility of the Company’s stock, the risk-free rate and the Company’s dividend yield. Estimates of fair value are not intended to predict actual future events or the value ultimately realized by grantees, and subsequent events are not indicative of the reasonableness of the original estimates of fair value made by the Company. The Company used the simplified method to determine the expected term on the options issued in the year ended December 31, 2010, due to the lack of historical exercise data.

The following assumptions were used for the Black-Scholes model:

	Years Ended December 31,
	2010	2009
Risk free rates	0.85%	None granted
Dividend yield	0%	-
Expected volatility	134.04%	-
Weighted average expected stock options life	2.5 years	-

The fair value of each stock option is estimated on the date of the grant using the Black-Scholes option pricing model. No dividends were assumed due to the nature of the Company’s current business strategy.

As of December 31, 2010 and 2009, the Company had no unrecognized compensation expense related to non-vested stock-based compensation arrangements. There were 1,069,285 options granted and vested during the year ended December 31, 2010. There were no options granted or vested during the year ended December 31, 2009.

10. WARRANTS OUTSTANDING

In December 2007, the Company issued warrants to placement agents to purchase 837,850 shares of common stock, of which 346,850 could be exercised cashless and 491,000 exercised at a price of $1.60 per share until December 31, 2012, as part of a securities purchase offering. On January 24, 2008, the Company issued an additional 9,615 warrants to a placement agent under the same terms as the original warrants. Also in December 2007, the Company issued 8,375,784 warrants to purchase 4,187,901 shares of common stock exercisable until December 31, 2012 in connection with a securities purchase agreement. The warrants had an exercise price of $1.60 per share.

The 2007 Warrant Agreement contains anti-dilution protection rights (“ratchet provision”) which require an adjustment to the exercise price of the warrants and a proportional adjustment to the number of shares of common stock issuable upon exercise of the warrants in the event the Company issues common stock, stock options, or securities convertible into or exercisable for common stock, at a price per share lower than such exercise price. On December 24, 2010, the Company issued non-excluded stock options to a third party with an exercise price of $0.42 which was below the original exercise of $1.60 contained in the agreement which triggered the ratchet provision. The effect of the anti-dilution provision resulted in an adjustment to the number of shares of common stock issuable upon exercise of the warrants from 5,035,367 shares with an exercise price of $1.60 per share to 19,182,350 shares with an exercise price of $0.42 per share.

A summary of warrant activity and shares issuable upon exercise of the warrants during the years ended December 31, 2010 and 2009 is as follows:

	Warrants		Shares Issuable Under Warrants		Weighted Average Exercise Price
Outstanding at December 31, 2008		9,223,249		5,035,367	$	1.60
Warrants issued		-		-		-
Warrants exercised		-		-		-
Outstanding at December 31, 2009		9,223,249		5,035,367		1.60
Warrants issued		-		-		-
Warrants exercised		-		-		-
Shares issuable under anti-dilution adjustment on 12/24/10		-		14,146,983		0.42
Outstanding at December 31, 2010		9,223,249		19,182,350		0.42

F-18

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

11. DERIVATIVE WARRANT LIABILITIY

As of December 31, 2010 and 2009, the Company had derivative warrant liabilities of $3,638,311 and -0-, respectively.

The Company used the Black-Scholes valuation model to estimate the fair value of the warrant derivative liability. Significant assumptions used at December 31, 2010 were as follows:

	2010

Market value of stock on reporting date (1)	$	0.30
Risk-free interest rate (2)		0.65	%
Dividend yield (3)		0.00	%
Volatility factor		143.62	%
Expected life (4)	1.96 years

(1) The market value of the stock on the data of reporting was based on reported public market prices.

(2) The risk-free interest rate was determined by management using the U.S. Treasury zero-coupon yield over the contractual term of the warrant on date of reporting.

(3) Management determined the dividend yield to be 0% based upon its expectation that there will not be earnings available to pay dividends in the near term.

(4) Expected life is remaining contractual life of the warrants.

Upon issuance of non-excluded options on December 24, 2010, with an exercise price below the exercise price defined in the Warrant agreement, the anti-dilution provision was triggered. Upon triggering the anti-dilution provision, the Company assessed its Warrants under ASC 815-40, which provides guidance as to assessing equity versus liability treatment, and it was determined that the Warrants should be classified as a derivative liability under ASC 815-40. As a result, the fair value of the warrants is recorded as a derivative liability. Each reporting period, the derivative liability is fair valued with the non-cash gain or loss recorded in the period as Other Income/Expense. Since the exercise price of the Warrants can be potentially decreased and the number of shares to settle the Warrants increased each time a trigger event occurs that results in a new adjusted exercise price below the adjusted exercise price then in effect, there could be a potentially infinite number of shares required to settle the Warrant agreement. However, the Company has the capability of limiting the occurrence of such events.

12. INCOME TAXES

The Company is a taxable corporation and the provision (benefit) for federal income taxes related to the Company’s operating results has been included in the accompanying consolidated statements of operations.

The income tax benefit (expense) consists of the following:

	2010		2009
Deferred income tax benefit:
U.S. Federal	$	-	$	-
Current income tax benefit (expense):
State and local		-		5,702
Income tax benefit	$	-	$	5,702

Income tax benefit for the years presented differs from the “expected” federal income tax benefit for those years, computed by applying the statutory U.S. Federal corporate tax rate of 34% to pre-tax loss, as a result of the following:

	2010		2009

Computed “expected” tax benefit	$	2,206,999	$	958,002
State and local income taxes, net of federal income tax benefit		-		3,763
Change in valuation allowances		(393,458)		(1,054,242)
Non-deductible expenses		(4,294)		(4,551)
Prior year adjustment		(1,774,269) 1		-
Other		(34,978)		102,730
Income tax benefit	$	-	$	5,702

The Company has adjusted its tax basis of leasehold costs related to the 2008 acquisition from TR Energy resulting from a recent IRS audit of TR Energy’s value of the consideration received. The Company has adjusted its tax basis in the assets acquired to equal the tax value of the consideration determined to have been received by TR Energy.

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities, at December 31, are presented below:

	2010		2009
Deferred tax assets:
Net operating loss carry forwards	$	3,300,174	$	2,524,420
Deferred interest expense		486,482		285,618
Liquidated damages payable		59,093		48,308
Accretion expense		33,401		27,225
Contributions carry forward		612		605
Accrued salaries		306,177		161,500
Derivative warrant liability		1,237,026		-
Valuation allowance		(1,685,823)		(1,292,363)
Total deferred tax assets		3,737,142		1,755,313

Deferred tax liabilities:
Oil and gas properties		(3,489,326)		(1,514,020)
Fixed assets and organization costs		(247,816)		(241,293)
Total deferred tax liabilities		(3,737,142)		(1,755,313)

Net deferred tax liability	$	-	$	-

F-19

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

Based on the future reversal of existing taxable temporary differences and future earnings expectations, management believes it is more likely than not that the full amount of the net operating loss carry forwards will not be realized or settled, and accordingly, a valuation allowance has been recorded. The Company’s net operating loss carry forwards approximate $9,700,000 and will expire in various years commencing in 2023.

In May 2006, the State of Texas enacted legislation for a Texas margin tax which restructured the state business tax by replacing the taxable capital and earned surplus components of the franchise tax with a new “taxable margin” component. The Company’s margin tax expense is derived by multiplying its taxable margin by 1%. The taxable margin can be derived, at the Company’s discretion, in any one of three ways. The Company can choose gross receipts less its cost of goods sold, gross receipts less its salary and wages, or 70% of its gross receipts. The Company has determined the margin tax is an income tax and the effect on deferred tax assets and liabilities should be included in the deferred tax calculation. No margin tax accrual was necessary at December 31, 2010 or 2009.

The Company files tax returns in the U.S. federal jurisdiction, and the state of Texas jurisdiction. The Company is currently subject to a three year statute of limitations by major tax jurisdictions. The Company follows the provisions of uncertain tax provisions as addressed in FASB ASC 740-10. The Company recognized no increase in the liability for unrecognized tax benefits. The Company had no tax positions at December 31, 2010 or December 31, 2009 for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. The Company recognizes interest accrued related to unrecognized tax benefits in interest expense and penalties in operating expenses. No such interest or penalties were recognized during the periods presented. The Company had no accruals for interest and penalties at December 31, 2010 and 2009.

13. SEGMENT INFORMATION

The following information is presented in accordance with FASB ASC Topic 280, Segment Reporting. The Company is engaged in oil and gas exploration and production, saltwater disposal and pipeline transportation. PERC is engaged in the exploration and production of natural gas and oil. POI, a wholly-owned subsidiary of PERC, conducts the exploration and production operations. TR Rodessa operates a 40-mile gas pipeline and gathering system which is used to transport hydrocarbons to market to be sold. 59 Disposal operates a saltwater disposal facility which disposes saltwater and flow-back waste into subsurface storage and also sells the skim oil it separates from the saltwater. The Company identified such segments based on management responsibility and the nature of their products, services, and costs. There are no major distinctions in geographical areas served as all operations are in the United States. The Company measures segment profit (loss) as income (loss) from operations. Business segment assets are those assets controlled by each reportable segment. The following table sets forth certain information about the financial information of each segment for the years ended December 31, 2010 and 2009:

	Year Ended December 31,
	2010		2009

Business segment revenue:
Oil and gas sales	$	578,207	$	537,410
Condensate and skim oil		82,117		89,416
Transportation and gathering		268,983		246,264
Saltwater disposal sales		67,636		133,028
Total revenues	$	996,943	$	1,006,118

Business segment profit (loss):
Oil and gas sales	$	(309,701)	$	(467,559)
Condensate and skim oil		82,117		89,416
Transportation and gathering		(130,689)		(36,907	)
Saltwater disposal sales		(235,887)		(258,099	)
General corporate		(1,627,212)		(1,670,470	)
Loss from operations	$	(2,221,372)	$	(2,343,619	)

	Year Ended December 31,
	2010		2009
Depletion and depreciation:
Oil and gas sales	$	125,588	$	105,601
Transportation and gathering		29,966		30,401
Saltwater disposal sales		79,285		67,522
General corporate		31,055		36,671
Total depletion and depreciation	$	265,894	$	240,195

Capital expenditures:
Oil and gas sales	$	187,158	$	458,380
Transportation and gathering		24,618		-
Saltwater disposal sales		87,003		27,811
General corporate		5,781		3,424
Total capital expenditures	$	304,560	$	489,615

	December 31,
	2010		2009
Business segment assets:
Oil and gas sales	$	20,538,826	$	20,508,595
Transportation and gathering		712,561		664,306
Saltwater disposal sales		310,934		294,086
General corporate		1,417,680		334,703
Total assets	$	22,980,001	$	21,801,690

F-20

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

14. RELATED PARTY TRANSACTIONS

The Company entered into various transactions with related parties as follows. These amounts have been recorded at the exchange amount, being the amount agreed to by the parties:

Years ended December 31	2010		2009
Lease bonus paid to an entity controlled by officers	$	1,227	$	-
Rent paid to an entity controlled by other entities which are owned by PERC officers (c)		72,189		75,553
Interest expense to an entity controlled by officers		589,995		454,892
Receivables due from entities that are owned by officers and/or other entities that are controlled by officers		13,002		13,002
JIB receivables due from an entity controlled by an officer or director		192,700		17,983
Payables due to officers or to entities controlled by officers (a) (b)		1,321,979		874,076
Interest payable on notes owed to an entity controlled by officers		394,704		840,052
Notes payable owed to an entity controlled by officers		8,160,646		6,352,303

(a)	Includes $900,521 and $475,000 of accrued salaries payable at December 31, 2010 and 2009, respectively. Also includes $240,000 of advances from officers at December 31, 2010 and 2009.

(b)	Includes $65,770 and $109,576 owed to an entity controlled by an officer for a 20% undivided interest in pipeline and disposal well operations as of December 31, 2010 and 2009, respectively.

(c)	The Company leases certain office and yard space under non-cancelable operating leases with related parties that expire in various years through 2011. These leases may be renewed for additional periods ranging from one to two years.

Future annual lease obligations for leases with related parties at December 31, 2010 are as follows:

2011	$	72,000

Total future related party lease obligations	$	72,000

15. RESTRICTED CASH

Leasing Program

During the first quarter of 2010, the Company executed agreements with two independent oil and gas companies regarding leasing specific areas on the Cornerstone Project. The agreements include both extensions and renewals of existing leaseholds that the Company currently holds and acquisitions of new leaseholds in order to expand the Company’s acreage position. Funds received from these companies are restricted to the leasing programs and are considered released when they are spent in accordance with the agreements. Total funds of $4,238,000 were received on these programs and $3,843,307 was spent on leasing activities leaving a balance of $394,693 in restricted cash and lease program deposits at December 31, 2010.

Drilling Program

During the last quarter of 2010, the Company executed participation and operating agreements with various independent oil and gas companies regarding the drilling of the Norbord and Swamp Fox wells. Funds received from these companies are restricted to the drilling programs and are considered released when they are spent in accordance with the agreements. Total funds of $2,143,551 were received on these programs and $1,349,940 was spent on drilling activities leaving a balance of $793,611 in restricted cash and drilling prepayments at December 31, 2010.

F-21

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

16. PREFERRED AND COMMON STOCK

On October 19, 2010, the Company’s Board of Directors and a majority of its shareholders approved an amendment to the Articles of Incorporation of the Company to increase the number of authorized shares of common stock, par value $.001 per share to 125,000,000 shares. The amendment also authorized 5,000,000 shares of blank-check preferred stock, par value $.001.

17. RISK CONCENTRATIONS

PERC maintains its deposits in one financial institution, which at times may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation. The Company has a sweep account which covers all of their bank accounts in order to reduce fees and earn maximum interest. The balance in the sweep account is invested daily in federal obligations. The balance available for the sweep account was approximately $1.5 million at December 31, 2010 and $208,000 at December 31, 2009. The Company has not experienced any losses with respect to uninsured balances.

Two customers accounted for approximately 42% and 37% of the Company’s total sales for the year ended December 31, 2010. Two customers, who are the same customers, accounted for approximately 39% and 37%, respectively, of the Company’s total sales for the year ended December 31, 2009. Revenues were reported from these customers in the oil and gas, condensate and skim oil, and transportation and gathering segments.

Lease operating payments primarily made to a principal operator on its oil and gas producing properties approximated $294,000 and $372,000 in 2010 and 2009, respectively.

18. COMMITMENTS AND CONTINGENCIES

Other

Occasionally, the Company is involved in various lawsuits and certain governmental proceedings arising in the normal course of business. In the opinion of management, the outcome of such matters will not have a materially adverse effect on the consolidated results of operations or financial position of the Company. None of the Company’s directors, officers, or affiliates, owners of record or beneficially of more than five percent of any class of the Company’s voting securities, or security holder is involved in a proceeding adverse to the Company’s business or has a material interest adverse to the business.

Environmental

To date, the Company’s expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. Management monitors these laws and regulations and periodically assesses the propriety of its operational and accounting policies related to environmental issues. The Company is unable to predict whether its future operations will be materially affected by these laws and regulations. It is believed that legislation and regulations relating to environmental protection will not materially affect the consolidated results of operations of the Company.

Employment Contracts

The Company has an employment contract with its President and Chief Executive Officer that requires minimum compensation totaling $250,000 annually through May 1, 2011. The Company’s Executive Vice President has an employment contract through May 1, 2011 that provides for minimum compensation of $225,000 annually. The Company’s Sr. Vice President and Chief Financial Officer, has an employment contract through May 1, 2011 that provides for minimum compensation of $210,000 annually.

Leases

The Company leases certain office space under a non-cancelable operating lease that expired August 31, 2010. This lease can be renewed for additional periods ranging from one to two years. On the expiration date of August 31, 2010 the lease was not renewed and the office space is now being leased monthly. Lease expense was approximately $26,000 and $24,000 for the years ended December 31, 2010 and 2009, respectively.

F-22

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

Contingent Liabilities

In preparing financial statements at any point in time, management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for prolonged periods of time. The Company is involved in actions from time to time, which if determined adversely, could have a material negative impact on the Company's consolidated financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of the Company’s probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed.

Along with the Company's counsel, management monitors developments related to legal matters and, when appropriate, makes adjustments to record liabilities to reflect current facts and circumstances. Management has recorded a liability related to its registration rights agreement with investors that provides for the filing of a registration statement for the registration of the shares issued in the offering in December 2007, as well as the shares issuable upon exercise of related warrants. The Company failed to meet the deadline for the effectiveness of the registration statement and therefore was required to pay liquidated damages of approximately $100,000 on the first day of effectiveness failure, or July 18, 2008. An additional $100,000 penalty was required to be paid by the Company every thirty days thereafter, prorated for periods totaling less than thirty days, until the effectiveness failure was cured, up to a maximum of 18% of the aggregate purchase price, or approximately $1,800,000. The Company’s registration became effective on August 21, 2008. At December 31, 2010, management reevaluated the status of the registration statement and determined an accrual of $173,802 was sufficient to cover any potential payments for liquidated damages. The damages are reflected as liquidated damages payable of $173,802 and $142,083 in the accompanying consolidated balance sheets as of December 31, 2010 and 2009, respectively.

19. SUBSEQUENT EVENTS

Effective February 1, 2011, the Company executed an agreement with an independent investor relations consultant. In return for the consultant’s services, he will receive 50,000 shares of the Company’s stock, and a monthly fee of $3,500 plus any reasonable expenses incurred related to work performed on behalf of the Company. The shares were issued on March 1, 2011.

In January 2011, the Company offered for sale the wholly-owned subsidiary, 59 Disposal. It currently holds a letter of intent from a potential buyer for the purchase of 59 Disposal for $1.3 million. The letter of intent is valid for thirty days after its signing on March 1, 2011. In connection with the sale transaction the buyer will agree to accept disposal water from the Company at the rate of $0.45 per barrel for a period of 12 months and in a volume of up to 6,000 barrels per month from its owned production fields subject to all other normal terms and conditions. Following the initial twelve month period, and as long as the buyer owns 59 Disposal, the buyer will agree to terms and conditions equal to the most favorable terms as it offers to any other third party on up to 6,000 barrels per month. The Company expects to complete this sale by the end of April 2011. At December 31, 2010, assets of 59 Disposal to be sold consisted of property, plant and equipment with a net book value of $300,347.

The Company is currently in negotiations to sell a 35% portion of a pipeline they own. They anticipate closing the negotiations in approximately thirty to forty-five days. Their current plan is to use the proceeds to refurbish a pipeline near the Norbord well which they expect to potentially double production from that well.

The Company is currently considering an amendment to the 2007 stock options issued to change the exercise price from its original price of $1.20 per share to an amended exercise price of $0.50 per share to bring them closer in line to the current market value. The stock options will expire in 2012 and there have been none exercised to date.

F-23

PEGASI ENERGY RESOURCES CORPORATION

SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

The following tables set forth supplementary disclosures for oil and gas producing activities in accordance with FASB ASC Topic No. 932, Extractive Activities—Oil and Gas.

Capitalized Costs Relating to Oil and Gas Producing Activities

	2010		2009
Unproved oil and gas properties	$	9,044,960	$	9,150,426
Proved oil and gas properties (including asset retirement costs)		11,981,949		12,149,222
Less accumulated depreciation, depletion, amortization, and valuation allowance		(1,018,100)		(900,275	)
Net capitalized costs	$	20,008,809	$	20,399,373

Capitalized costs include leasehold costs, lease and well equipment, capitalized intangible drilling costs, and capitalized intangible completion costs.

Costs Incurred

A summary of costs incurred in oil and gas property acquisition, development, and exploration activities (both capitalized and charged to expense) for the years ended December 31, 2010 and 2009, as follows:

	2010		2009
Acquisition of proved properties	$	5,220	$	1,962
Acquisition of unproved properties		59,088		434,996
Development costs		122,850		22,463

Results of Operations for Producing Activities

The following table presents the consolidated results of operations for the Company’s oil and gas producing activities for the years ended December 31, 2010 and 2009:

	2010		2009
Revenues	$	578,207	$	537,410
Production costs		(312,505)		(388,548)
Depletion, depreciation, and valuation provisions		(117,825)		(93,972)
Exploration costs		-		-
Income before income tax expense		147,877		54,890
Income tax expense		(51,757)		(19,212)
Results of operations for producing activities (excluding corporate overhead and interest costs)	$	96,120	$	35,678

Reserve Quantity Information

The following table presents the Company’s estimate of its proved oil and gas reserves all of which are located in the United States. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of reserves related to new discoveries are more imprecise than those for producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared with the assistance of an independent petroleum reservoir engineering firm. The petroleum engineer that determined our reserves also planned and supervised the drilling of wells that we drilled in the East Texas project. His 2010 and 2009 compensation, from the Company, for the planning and supervision of drilling wells was $184,023 and $66,789, respectively. The petroleum engineer’s compensation for reserve estimation for that same time period was $16,484 and $16,210, respectively. Oil reserves, which include condensate and natural gas liquids, are stated in barrels and gas reserves are stated in thousands of cubic feet.

F-24

PEGASI ENERGY RESOURCES CORPORATION

SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

	Oil			Gas
	(Bbls.)			(MCF)
Changes in proved developed and undeveloped reserves:
Balance at January 1, 2008		455,071			11,594,098
Extensions and discoveries		674,080			17,442,522
Production		(7,515)			(62,708)
Revisions of previous estimates		(73,336)			(1,599,807)
Balance at December 31, 2008		1,048,300			27,374,105
Extensions and discoveries		-			-
Production		(5,719	)		(64,003	)
Revisions of previous estimates		(33,682	)		(999,947	)
Balance at December 31, 2009		1,008,899			26,310,155
Extensions and discoveries		-			-
Production		(4,346)			(61,678)
Revisions of previous estimates		(546,267)			(12,434,037)
Balance at December 31, 2010		458,286			13,814,440

Proved developed reserves:
December 31, 2008
Beginning of year	32,690	706,759
End of year	58,340	945,223
December 31, 2009
Beginning of year	58,340	945,223
End of year	45,656	772,470
December 31, 2010
Beginning of year	45,656	772,470
End of year	52,866	799,696

Proved Undeveloped reserves:
December 31, 2008
Beginning of year	422,381	10,887,339
End of year	989,960	26,428,882
December 31, 2009
Beginning of year	989,960	26,428,882
End of year	963,243	25,537,685
December 31, 2010
Beginning of year	963,243	25,537,685
End of year	405,420	13,014,744

Revisions of previous estimates decreased significantly during 2010. This was primarily due to the re-classification of the Cotton Valley area from proved undeveloped reserves to the probable and possible categories on the reserve report. As a result of the success of the Norbord well, the Company has decided to focus its attention on the Travis Peak area, and not develop the Cotton Valley area within the next five years.

Standardized Measure of Discounted Future Net Cash Flow and Changes Therein Relating to Proved Oil and Gas Reserves

The following table, which presents a standardized measure of discounted future cash flows and changes therein relating to proved oil and gas reserves, is presented pursuant to FASB ASC Topic No. 932. In computing this data, assumptions other than those required by the FASB could produce different results. Accordingly, the data should not be construed as being representative of the fair market value of the Company’s proved oil and gas reserves.

Future cash inflows were computed by applying existing contract and 12-month average prices of oil and gas relating to the Company’s proved reserves to the estimated year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence at year end. Future development and production costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs. Future income tax expenses were computed by applying the year-end statutory tax rate, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. The standardized measure of discounted future cash flows at December 31, 2010 and 2009, which represents the present value of estimated future cash flows using a discount rate of 10% a year, follows:

	2010		2009
Future cash inflows	$	84,524,242	$	137,366,695
Future production costs		(23,275,640)		(47,616,690)
Future development costs		(10,380,000)		(19,440,000)
Future income tax expenses		(12,763,161)		(16,736,520)
Future net cash flows		38,105,441		53,573,485
10% annual discount for estimated timing of cash flows		(22,335,947)		(43,372,071)
Standardized measure of discounted future net cash flows	$	15,769,494	$	10,201,414

F-25

PEGASI ENERGY RESOURCES CORPORATION

SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

		2010		2009
Beginning of year	$	10,201,414	$	11,709,886
Sales of oil and gas, net of production costs		(265,702)		(148,862	)
Extensions, discoveries, and improved recoveries, less related costs		-		-
Accretion of discount		1,184,227		1,512,233
Net change in sales and transfer prices, net of production costs		7,230,503		(7,669,020)
Changes in estimated future development costs		6,451,644		3,161,374
Net change in income taxes		(3,158,548)		1,771,585
Changes in production rates (timing and other)		14,456,049		1,266,931
Purchases and sales of mineral interests		-		-
Revisions of previous quantities		(20,330,093)		(1,402,713	)
End of year	$	15,769,494	$	10,201,414

F-26

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A – CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures.

Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Based on management’s evaluation, our chief executive officer and chief financial officer concluded that, as a result of the material weaknesses described below, as of December 31, 2010, our disclosure controls and procedures are not designed at a reasonable assurance level and are ineffective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. The material weaknesses, which relate to internal control over financial reporting, that were identified are:

We did not maintain sufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of GAAP commensurate with our complexity and our financial accounting and reporting requirements. We have limited experience in the areas of financial reporting and disclosure controls and procedures. Also, we do not have an independent audit committee. As a result, there is a lack of monitoring of the financial reporting process and there is a reasonable possibility that material misstatements of the consolidated financial statements, including disclosures, will not be prevented or detected on a timely basis. For example, on August 4, 2011, we became aware that we had failed to recognize a warrant derivative liability with respect to the impact of an anti-dilution provision on our warrants and the subsequent measurement of fair value of the warrant derivative, as required by Accounting Standards Codification 815-40. As a result, we determined that our consolidated financial statements for the year ended December 31, 2010 filed in the annual report on Form 10-K and our consolidated financial statements as of and for the three month period ended March 31, 2011 filed in the quarterly report on Form 10-Q (collectively, the “Report”) should not be relied upon and needed to be restated.; and

Due to our small size, we do not have a proper segregation of duties in certain areas of our financial reporting process. The areas where we have a lack of segregation of duties include cash receipts and disbursements, approval of purchases and approval of accounts payable invoices for payment. This control deficiency, which is pervasive in nature, results in a reasonable possibility that material misstatements of the consolidated financial statements will not be prevented or detected on a timely basis.

We are committed to improving our financial organization. As part of this commitment, in August 2011, we adopted additional controls to strengthen our internal controls over financial reporting as a result of the failure in recognizing the warrant derivative liability issued that resulted in the amendment to our Reports. If the issuance of any securities is contemplated, we will consult with legal counsel and appropriate accounting resources to evaluate the financial statement impact that the issuance of such warrants or other derivative financial instruments may have prior to issuance. Additional measures may be implemented as we evaluate the effectiveness of these efforts. We cannot assure you that these remediation efforts will be successful or that our internal control over financial reporting will be effective in accomplishing the control objectives.

In addition, we will look to increase our personnel resources and technical accounting expertise within the accounting function to resolve non-routine or complex accounting matters. In addition, when funds are available, we will take the following action to enhance our internal controls: Hiring additional knowledgeable personnel with technical accounting expertise to further support our current accounting personnel, which management estimates will cost approximately $100,000 per annum. As our operations are relatively small and we continue to have net cash losses each quarter, we do not anticipate being able to hire additional internal personnel until such time as our operations are profitable on a cash basis or until our operations are large enough to justify the hiring of additional accounting personnel. We currently engage an outside accounting firm to assist us in the preparation of our consolidated financial statements and anticipate doing so until we have a sufficient number of internal accounting personnel to achieve compliance. As necessary, we will engage consultants in the future in order to ensure proper accounting for our consolidated financial statements.

Management believes that hiring additional knowledgeable personnel with technical accounting expertise will remedy the following material weakness: insufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of GAAP commensurate with our complexity and our financial accounting and reporting requirements.

Management believes that the hiring of additional personnel who have the technical expertise and knowledge with the non-routine or technical issues we have encountered in the past will result in both proper recording of these transactions and a much more knowledgeable finance department as a whole. Due to the fact that our internal accounting staff consists solely of a Chief Financial Officer, additional personnel will also ensure the proper segregation of duties and provide more checks and balances within the department. Additional personnel will also provide the cross training needed to support us if personnel turn over issues within the department occur. We believe this will greatly decrease any control and procedure issues we may encounter in the future.

(b) Changes in internal control over financial reporting.

We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes. There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was not effective as of December 31, 2010, because of a material weakness relating to the accounting for equity-linked financial instruments, specifically stock purchase warrants. This material weakness resulted in a material misstatement of our liabilities, non-cash expense relating to the change in fair value of warrant derivative liabilities and equity accounts and related financial disclosures that was not prevented or detected on a timely basis. The material weakness described above resulted in a restatement of the Company’s consolidated financial statements for the year ended December 31, 2010 on Form 10-K/A and for the interim period ended March 31, 2011 on Form 10-Q/A as discussed in Note 3 to the consolidated financial statements included in this Annual Report on Form 10-K/A.

ITEM 9B – OTHER INFORMATION

None.

PART III.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Names:	Ages	Titles:	Position Held Since	Director Since
Michael H. Neufeld	61	President, Chief Executive Officer, and Director	November 22, 2006	November 22, 2006
William L. Sudderth	69	Executive Vice President, Land	November 22, 2006	n/a
Richard A. Lindermanis	65	Sr. Vice President, Chief Financial Officer, and Director	November 22, 2006	November 22, 2006
Alan Gelfand	51	Director	November 22, 2006	November 22, 2006
David J. Moss	40	Director	November 22, 2006	November 22, 2006

Directors are elected to serve until the next annual meeting of stockholders and until their successors are elected and qualified. Currently there are five seats on our board of directors.

Officers are elected by the Board of Directors and serve until their successors are appointed by the Board of Directors. Biographical resumes of each officer and director are set forth below.

Michael H. Neufeld - President, Chief Executive Officer and Director

Mr. Neufeld has been President and Chief Executive Officer of PERC and its predecessors since 2000. He worked for Pennzoil Company from 1972 to 1976 as a Development Geologist, Exploration Geologist and Senior Geologist working in Pennzoil’s Gulf Coast Division. He then joined American Resources Company from 1976 to 1977 as Senior Geologist. In 1977 he joined Hunt Oil Company as Sr. Geologist working in the Texas and Gulf Coast regions. From 1978 to 1981, Mr. Neufeld worked for Croftwood Corporation as Senior Exploration Geologist and Vice-President of Exploration working in the Gulf Coast of Louisiana and Texas. In 1983 Mr. Neufeld co-founded SMK Energy Corporation ("SMK Energy"), where exploration efforts were concentrated in East Texas, Gulf Coast Louisiana and the Rocky Mountains. He graduated from Louisiana State University in 1971 with a B.S. Degree in Geology. Mr. Neufeld was selected to serve as a director due to his deep familiarity with our business and his extensive entrepreneurial background.

William L. Sudderth - Executive Vice President

Mr. Sudderth has been an Executive Vice President of PERC and its predecessors since 2000. He began his career at Lone Star Producing Company in 1970 where he worked through 1971. In late 1971 he joined Midwest Oil Corporation and worked there until 1974, at which point he became an independent landman working the entire continental United States. In 1981 Mr. Sudderth became a Certified Professional Landman. In 1983 Mr. Sudderth co-founded SMK Energy, along with Mr. Neufeld, which later merged with Windsor Energy in 1997. Mr. Sudderth received his B.B.A. Degree from Sam Houston State University in 1970.

Richard A. Lindermanis - Sr. Vice-President, CFO and Director

Mr. Lindermanis has been Senior Vice President of PERC and its predecessors since 2000. He was employed by Amerada Corp. from 1967 to 1971 in Williston, ND and Lafayette, LA as District Land Manager, Gulf Coast. He joined Louisiana Land & Exploration Co. in 1971 where he was Division Land Manager for the Rocky Mountain Division until 1975. He then joined Patrick Petroleum Corp. as Western Division Manager in Denver and later moved to Jackson, MS as Executive Vice President responsible for Corporate Development, Exploration and Investor Relations. In 1979 Mr. Lindermanis co-founded and became Executive Vice President, Director and a major stockholder of Sandefer Oil and Gas in Houston, Texas. The company grew to have a $100 million drilling and completion budget. Mr. Lindermanis left the Company in 1986 and since then he has founded several companies. Mr. Lindermanis graduated from Phillips University in 1967 with a B.A. in History and Political Science. Mr. Lindermanis was selected to serve as a director due to his deep familiarity with our business, his extensive entrepreneurial background and his substantial financial and accounting experience.

Alan Gelfand - Director

Alan Gelfand has been a director since May 2007. Mr. Gelfand served as a director of American Oil and Gas Inc. where he sat on the audit and compensation committee, since its inception in December 2002 until 2007. Prior to becoming a director of the Company, Mr. Gelfand was a stockbroker from 1987 until December 2002. He graduated from Simon Fraser University with a B.B.A in 1982. Mr. Gelfand was selected to serve as a director due to his experience serving as a director for an oil and gas company.

David J. Moss - Director

David Moss has been a director since May 2007. As of October 2008 he also serves as director for Sorteo Games, LLC. Since 2005, Mr. Moss has been a Managing Director and he is co-founder of Aegis Equity, LLC, a corporate finance and strategic advisory firm based in San Diego and Santa Monica, California. He has founded, funded and taken public various companies in a variety of industries since 1995. Prior to starting Aegis, Mr. Moss served as Managing Director, Corporate Finance, for Jesup & Lamont Securities, where he advised companies on corporate strategy, financings, and business development. Prior to Jesup & Lamont, Mr. Moss was Chief Business Officer and V.P. of Corporate Development for a privately-held biotechnology firm. Previously, Mr. Moss served as Managing Partner at a Seattle-based venture capital firm, The Phoenix Partners. Mr. Moss holds an M.B.A. from Rice University and a B.A. in Economics from the University of California, San Diego. Mr. Moss was selected to serve as a director due to his extensive entrepreneurial background and his substantial financial and accounting experience.

Family Relationships

None.

Board Committees and Independence

We are not required to have any independent members of the Board of Directors. The board of directors has determined that (i) Messrs. Neufeld and Lindermanis have relationships which, in the opinion of the board of directors, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director and each is not an “independent director” as defined in the Marketplace Rules of The NASDAQ Stock Market and (ii) Messrs. Gelfand and Moss are independent directors as defined in the Marketplace Rules of The NASDAQ Stock Market. As we do not have any board committees, the board as a whole carries out the functions of audit, nominating and compensation committees, and such “independent director” determination has been made pursuant to the committee independence standards.

Involvement in Certain Legal Proceedings

Our directors, executive officers and control persons if more than one person have not been involved in any of the following events during the past five years:

1.	any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;

2.	any conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);

3.	being subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or

4.	being found by a court of competent jurisdiction (in a civil action), the Commission or the Commodity Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended, or vacated.

Code of Ethics

The Board of Directors has adopted a Code of Ethics that applies to all directors, officers and employees. A copy of the Code is incorporated by reference as an exhibit.

Section 16(a) Compliance

Since we are governed under Section 15(d) of the Exchange Act, we are not required to file reports of executive officers and directors and persons who own more than 10% of a registered class of our equity securities pursuant to Section 16(a) of the Exchange Act.

ITEM 11. EXECUTIVE COMPENSATION.

Summary Compensation Table

The following table provides certain summary information concerning compensation awarded to, earned by or paid to our Chief Executive Officer, the two highest paid executive officers and one other highest paid individual whose total annual salary and bonus exceeded $100,000 for fiscal years 2010 and 2009.In accordance with the rules of the SEC, this table omits columns that are not relevant.

Name and Principal Position	Year	Salary ($)			Stock Awards($)3			Total ($)
Michael Neufeld	2010	$	250,000	1	$	51,300	3	$	301,300
Chief Executive Officer	2009	$	250,000	1		-		$	250,000

Bill L. Sudderth	2010	$	225,000	2	$	51,300	3	$	276,300
Executive Vice President	2009	$	225,000	2		-		$	225,000

Richard A. Lindermanis	2010	$	210,000		$	51,300	3	$	261,300
Senior Vice-President and Chief Financial Officer	2009	$	210,000			-		$	210,000

William Denman	2010	$	120,000		$	32,319	4	$	152,319
Land Manager	2009	$	120,000			-		$	120,000

1.	Mr. Neufeld’s salary consists of $26,041 paid and $223,959 accrued during 2010 and $125,000 paid and $125,000 accrued during 2009.

2.	Mr. Sudderth’s salary consists of $23,437 paid and $201,563 accrued during 2010 and $112,500 paid and $112,500 accrued during 2009.

3.	On December 24, 2010, we granted options to Michael Neufeld, Bill L. Sudderth, and Richard A. Lindermanis to purchase 238,095 shares of our common stock at a price of $0.42 per share until December 24, 2015. These options were fully vested on the exercise date.

4.	On December 24, 2010, we granted options to William Denman to purchase 150,000 shares of our common stock at a price of $0.42 per share until December 24, 2015. These options were fully vested on the exercise date.

The employment agreements with each of our executive officers were not tied to specific performance goals or company targets because we were a relatively new operating company at the time each executive officer’s agreement was negotiated. Our negotiation of the employment agreements was highly dependent on our cash flow projections and, in fact, both Michael Neufeld and Bill L. Sudderth are currently not receiving any of their agreed-upon salary. The full salary is being accrued and will be paid at a later date when our cash flow increases.

Employment Agreements with Executive Officers

The material terms of each Executive Officer’s services agreement or arrangement is as follows:

Each of Michael Neufeld, Bill Sudderth and Richard Lindermanis has entered into an employment agreement with us. Each of these agreements is substantially similar. They had an initial term of three years, commencing May 1, 2007. The contracts were automatically renewed for a one-year term and will continue to automatically renew for successive one year terms unless, at least 90 days before the last day of the employment period, a written notice is given stating that the employment period will not be extended. Mr. Neufeld will be paid an annual salary of $250,000, Mr. Sudderth $225,000 and Mr. Lindermanis will be paid $210,000. Each person may be entitled to a bonus at the discretion of the Board of Directors. Each person may be terminated for cause, which under the terms of the agreements is defined as:

●	The employee having, in the reasonable judgment of the Company, committed an act which if prosecuted and resulting in a conviction would constitute a fraud, embezzlement, or any felonious offense (specifically excepting simple misdemeanors not involving acts of dishonesty and all traffic violations);
●	The employee’s theft, embezzlement, misappropriation of or intentional and malicious infliction of damage to the Company’s property or business opportunity;
●	the employee’s repeated abuse of alcohol, drugs or other substances as determined by an independent medical physician; or
●	the employee’s engagement in gross dereliction of duties, refusal to perform assigned duties consistent with his position, his knowing and willful breach of any material provision of their agreements continuing after written notice from the Company or repeated violation of the Company’s written policies after written notice.

Each of the agreements contains standard non-disclosure and prohibits the employee from competing with the Company in its territory for a period of two years following the termination of employment for any reason. For purposes of the employment agreement, the territory consists of all land at any time held under lease by PERC (or its affiliates) for mineral exploration or development and all surrounding land within two miles from any leased land.

Outstanding Equity Awards at Fiscal Year-End Table.

The following table sets forth information concerning unexercised options, stock that has not vested, and equity incentive awards outstanding as of December 31, 2010 for each of our executive officers.

Outstanding Equity Awards at Fiscal Year End Option Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)		Original Option Exercise Price ($)		Option Expiration Date
Michael Neufeld, CEO		238,095		-		-	$	0.42	December 24, 2015
Bill L. Sudderth, Executive Vice President		238,095		-		-	$	0.42	December 24, 2015
Richard A. Lindermanis, Senior Vice-President and CFO		238,095		-		-	$	0.42	December 24, 2015

Director Compensation

Non-employee directors did not receive any compensation for services to our company for the fiscal year ended December 31, 2010.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The following table sets forth certain information regarding beneficial ownership of our common stock as of March 25, 2011.

●	by each person who is known by us to beneficially own more than 5% of our common stock;

●	by each of our officers and directors; and

●	by all of our officers and directors as a group.

NAME AND ADDRESS OF OWNER (1)	TITLE OF CLASS	NUMBER OF SHARES OWNED (2)	PERCENTAGE OF CLASS (3)

Michael H. Neufeld (4)	Common Stock	20,110,098 (5)	50.37%

William L. Sudderth (4)	Common Stock	20,035,098 (6)	50.22%

Richard A. Lindermanis	Common Stock	2,425,595 (7)	7.16%

Alan Gelfand	Common Stock	525,000 (8)	1.54%

David J. Moss	Common Stock	600,000 (9)	1.76%

All Officers and Directors	Common Stock	29,017,538 (10)	70.48%
As a Group (5 persons)

Teton Royalty Ltd. (4)	Common Stock	10,478,253 (11)	26.42%

TR Energy, Inc. (12)	Common Stock	4,200,000	12.48%

* Less than 1%.

(1) The address is c/o Pegasi Energy Resources Corporation, 218 N. Broadway, Suite 204, Tyler, Texas 75702.

(2) Beneficial Ownership is determined in accordance with the rules of the SEC and generally includes voting or investment power with respect to securities. Shares of common stock subject to options or warrants currently exercisable or convertible, or exercisable or convertible within 60 days of March 25, 2011 are deemed outstanding for computing the percentage of the person holding such option or warrant but are not deemed outstanding for computing the percentage of any other person.

(3) Based upon 33,660,801 shares issued and outstanding on March 25, 2011.

(4) Messrs. Neufeld and Sudderth are co-owners, executive officers and directors of Teton Royalty Ltd.

(5) Includes 25,000 shares of common stock underlying warrants and 238,095 shares of common stock underlying options that are currently exercisable or exercisable within 60 days. Also includes 4,200,000 shares of common stock held by TR Energy, Inc., 4,480,000 shares of common stock held by Teton Royalty Ltd., 52,500 shares of common stock underlying warrants held by Teton Royalty Ltd. and 5,945,753 shares of common stock issuable upon conversion of debt held by Teton Royalty Ltd. Mr. Neufeld disclaims 50% of the shares held by Teton Royalty Ltd., which corresponds to his 50% ownership interest in the entity.

(6) Includes 238,095 shares of common stock underlying options that are currently exercisable or exercisable within 60 days. Also includes 4,200,000 shares of common stock held by TR Energy, Inc., 4,480,000 shares of common stock held by Teton Royalty Ltd., 52,500 shares of common stock underlying warrants held by Teton Royalty Ltd. and 5,945,753 shares of common stock issuable upon conversion of debt held by Teton Royalty Ltd. Mr. Sudderth disclaims 50% of the shares held by Teton Royalty Ltd., which corresponds to his 50% ownership interest in the entity.

(7) Represents shares held by the Lindermanis Family Living Trust of which Mr. Lindermanis is a trustee. Includes 238,095 shares of common stock underlying options that are currently exercisable or exercisable within 60 days.

(8) Includes 375,000 shares of common stock underlying options that are currently exercisable or exercisable within 60 days.

(9) Includes 25,000 shares of common stock issuable upon conversion of warrants and 375,000 shares of common stock underlying options that are currently exercisable or exercisable within 60 days.

(10) Includes 50,000 shares of common stock issuable upon conversion of warrants and 1,464,285 shares of common stock underlying options that are currently exercisable or exercisable within 60 days. Also includes 4,200,000 shares of common stock held by TR Energy, Inc., 4,480,000 shares of common stock held by Teton Royalty Ltd., 52,500 shares of common stock underlying warrants held by Teton Royalty Ltd. and 5,945,753 shares of common stock issuable upon conversion of debt held by Teton Royalty Ltd.

(11) Includes 52,500 shares of common stock underlying warrants held by Teton Royalty Ltd. and 5,945,753 shares of common stock issuable upon conversion of debt held by Teton Royalty Ltd. As of March 25, 2011, Teton Royalty Ltd. had $5,792,957 of outstanding principal and $386,200 of accrued interest that the Company has agreed to allow Teton Royalty Ltd. to convert into shares of common stock at a conversion price of $1.20 per share and $1,194,689 of outstanding principal and $79,640 of accrued interest that the Company has agreed to allow Teton Royalty Ltd. to convert into shares of common stock at a conversion price of $1.60 per share.

(12) Mike Neufeld and William Sudderth have voting and investment control over shares owned by this entity. The address of this entity is PO Box 479, Tyler, Texas 75710.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

Except as disclosed below, there have been no transactions, or proposed transactions, which have materially affected or will materially affect us in which any director, executive officer or beneficial holder of more than 5% of the outstanding common stock, or any of their respective relatives, spouses, associates or affiliates, has had or will have any direct or material indirect interest. We have no policy regarding entering into transactions with affiliated parties.

Effective January 1, 2007, PERC, entered into a five-year lease agreement with Marion Swamp Fox L.P. providing for (i) the lease to PERC of 34 acres of storage facilities and (ii) use of office space. On July 1, 2008 the lease for office space was amended to include additional office space and the lease payments were increased from $750 per month to $4,500 per month for the remaining term. The 34 acre storage facility has lease payments of $1,500 per month plus $0.05 per barrel of water injected into the facility. The total lease payments over the entire term of the lease equal $202,500. Marion Swamp Fox LP is owned by Messrs. Neufeld, Sudderth and Lindermanis, each an executive officer of the Company.

POI, TR Rodessa, and 59 Disposal, had each executed a promissory note dated May 21, 2007, payable to Teton, an entity owned by Messrs. Neufeld and Sudderth, each an executive officer of the Company, in the original principal amount of $5,579,847. The note evidences the combined total of prior working capital loans Teton made to PERC and its subsidiaries over the previous two years. The note accrued interest at eight percent (8%) per annum. Additional funds totaling $1,095,000 were added to the note during 2009. On June 1, 2010 a Promissory (Teton Renewable Note) note was executed to renew and extend the original promissory note dated May 21, 2007. The renewal note’s principal balance of $6,987,646 is the total of the outstanding principal of $5,952,303 and accrued and unpaid interest of $1,035,343 on the original note. Accrued interest and principal is due on the notes maturity date of June 1, 2011. Under the terms of a memorandum of understanding dated May 21, 2007, between the Company and Teton, Teton has the right to convert that original amount into shares of common stock at any time after May 21, 2008 at $1.20 per share. An amendment to the promissory note was executed on March 3, 2009 that gave Teton the right to convert the additional funds into shares of common stock at $1.60 per share. The largest aggregate amount of principal outstanding during 2010 was $6,987,646 (See Note 7). Interest expense on the note during 2010 was $524,503.

On October 14, 2009, PERC executed a promissory note payable to Teton that would allow the Company to receive up to $1,000,000. On March 2, 2010 an amendment to the promissory note was executed that provided additional funds available of $1.5 million. As of December 31, 2010, PERC had received $1,173,000 related to this note. The accrued interest and outstanding principal are due on the maturity date of April 2, 2011. Interest expense on this note during 2010 was $65,492.

In addition, at December 31, 2010 and 2009, we owed TR Energy an amount of $65,770 and $109,576, respectively, in connection with our purchase of a 20% undivided interest in their pipelines and disposal well. TR Energy is owned by Messrs. Neufeld and Sudderth.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

Audit Fees

The aggregate fees billed by our auditors, for professional services rendered for the audit of our annual consolidated financial statements during the years ended December 31, 2010 and 2009, and for the reviews of the consolidated financial statements included in our Quarterly Reports on Form 10-Q during the fiscal years, were approximately $82,000 and $95,000, respectively.

Audit-Related Fees

Our independent registered public accounting firm did not bill us during the years ended December 31, 2010 and 2009 for audit related services.

Tax Fees

Our independent registered public accounting firm did not bill us during fiscal years ended December 31, 2010 and 2009 for tax related services.

All Other Fees

Our independent registered public accounting firm billed us during the year ended December 31, 2009 for other services of $28,000. During the year ended December 31, 2010, there were no amounts billed for other services.

The Board of Directors has considered whether the provision of non-audit services is compatible with maintaining the principal accountant's independence.

PART IV.

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

Exhibit No.

Description

2.01	Share Exchange Agreement, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on December 18, 2007 and incorporated herein by reference.

3.01	Articles of Incorporation, filed as an exhibit to the registration statement on Form SB-2 filed with the Securities and Exchange Commission on May 30, 2006 and incorporated herein by reference.

3.02	Amendment to Articles of Incorporation, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on January 29, 2008 and incorporated herein by reference.

3.03	By-Laws, filed as an exhibit to the registration statement on Form SB-2 filed with the Securities and Exchange Commission on May 30, 2006 and incorporated herein by reference.

3.04	Amendment to Articles of Incorporation, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2010 and incorporated herein by reference.

4.01	Form of Warrant, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on December 18, 2007 and incorporated herein by reference.

10.01

2007 Stock Option, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on June 4, 2007 and incorporated herein by reference.

10.02

Securities Purchase Agreement, filed as an exhibit to the amended current report on Form 8-K/A filed with the Securities and Exchange Commission on January 29, 2008 and incorporated herein by reference.

10.03

Registration Rights Agreement, filed as an exhibit to the amended current report on Form 8-K/A filed with the Securities and Exchange Commission on January 29, 2008 and incorporated herein by reference.

10.04

Employment Agreement dated May 1, 2007 between the Company and Michael Neufeld, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on December 18, 2007 and incorporated herein by reference.

10.05

Employment Agreement dated May 1, 2007 between the Company and William Sudderth, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on December 18, 2007 and incorporated herein by reference.

10.06

Employment Agreement dated May 1, 2007 between the Company and Richard Lindermanis, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on December 18, 2007 and incorporated herein by reference.

10.07

Form of Amendment No. 1 to Registration Rights Agreement, filed as an exhibit to the amended registration statement on Form S-1/A filed with the Securities and Exchange Commission on July 25, 2008 and incorporated herein by reference.

10.08

2010 Incentive Stock Option Plan, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2010 and incorporated herein by reference.

10.09

Form of Renewal Promissory Note, issued to Teton, Ltd. on May 21, 2007, filed as an exhibit to the quarterly report on Form 10-Q filed with the Securities and Exchange Commission on November 12, 2010 and incorporated herein by reference.

10.10

Form of Amendment to Renewal Promissory Note, effective as of May 21, 2008, by and among Pegasi Energy Resources Corporation, Pegasi Operating Inc., TR Rodessa, Inc., 59 Disposal, Inc. and Teton, Ltd., filed as an exhibit to the quarterly report on Form 10-Q filed with the Securities and Exchange Commission on November 12, 2010 and incorporated herein by reference.

10.11

Form of Second Amendment to Renewal Promissory Note and Loan Modification Agreement, effective as of March 3, 2009, by and among Pegasi Energy Resources Corporation, Pegasi Operating Inc., TR Rodessa, Inc., 59 Disposal, Inc. and Teton, Ltd., filed as an exhibit to the quarterly report on Form 10-Q filed with the Securities and Exchange Commission on November 12, 2010 and incorporated herein by reference.

10.12

Form of Third Amendment to Renewal Promissory Note, effective as of May 21, 2009, by and among Pegasi Energy Resources Corporation, Pegasi Operating Inc., TR Rodessa, Inc., 59 Disposal, Inc. and Teton, Ltd., filed as an exhibit to the quarterly report on Form 10-Q filed with the Securities and Exchange Commission on November 12, 2010 and incorporated herein by reference.

10.13

Form of Fourth Amendment to Renewal Promissory Note, effective as of May 20, 2009, by and among Pegasi Energy Resources Corporation, Pegasi Operating Inc., TR Rodessa, Inc., 59 Disposal, Inc. and Teton, Ltd., filed as an exhibit to the quarterly report on Form 10-Q filed with the Securities and Exchange Commission on November 12, 2010 and incorporated herein by reference.

10.14

Form of Fifth Amendment to Renewal Promissory Note, effective as of September 21, 2009, by and among Pegasi Energy Resources Corporation, Pegasi Operating Inc., TR Rodessa, Inc., 59 Disposal, Inc. and Teton, Ltd., filed as an exhibit to the quarterly report on Form 10-Q filed with the Securities and Exchange Commission on November 12, 2010 and incorporated herein by reference.

10.15

Form of Sixth Amendment to Renewal Promissory Note, effective as of October 21, 2009, by and among Pegasi Energy Resources Corporation, Pegasi Operating Inc., TR Rodessa, Inc., 59 Disposal, Inc. and Teton, Ltd., filed as an exhibit to the quarterly report on Form 10-Q filed with the Securities and Exchange Commission on November 12, 2010 and incorporated herein by reference.

10.16

Form of Seventh Amendment to Renewal Promissory Note, effective as of February 15, 2010, by and among Pegasi Energy Resources Corporation, Pegasi Operating Inc., TR Rodessa, Inc., 59 Disposal, Inc. and Teton, Ltd., filed as an exhibit to the quarterly report on Form 10-Q filed with the Securities and Exchange Commission on November 12, 2010 and incorporated herein by reference.

10.17

Form of Promissory Note, issued to Teton, Ltd. on June 1, 2010, filed as an exhibit to the quarterly report on Form 10-Q filed with the Securities and Exchange Commission on November 12, 2010 and incorporated herein by reference.

10.18

Form of Second Amendment to Promissory Note, effective as of January 1, 2011, by and among Pegasi Energy Resources Corporation, Pegasi Energy Resources Corporation, Pegasi Operating Inc., TR Rodessa, Inc., 59 Disposal, Inc. and Teton, Ltd. †

10.19

Form of Fourth Amendment to Promissory Note, effective as of January 2, 2011, by and among Pegasi Energy Resources Corporation, Pegasi Energy Resources Corporation, Pegasi Operating Inc., TR Rodessa, Inc., 59 Disposal, Inc. and Teton, Ltd. †

14.01

Code of Ethics, filed as an exhibit to the annual report on Form 10-K filed with the Securities and Exchange Commission on March 29, 2010 and incorporated herein by reference.

21.01

List of subsidiaries, filed as an exhibit to the annual report on Form 10-K filed with the Securities and Exchange Commission on March 29, 2010 and incorporated herein by reference.

23.01

Consent of James E. Smith & Associates, Independent Petroleum Engineers

23.02

Consent of Whitley Penn LLP

31.01

Certification of Chief Executive Officer pursuant to Rule 13a-14 and Rule 15d-14(a), promulgated under the Securities and Exchange Act of 1934, as amended.

31.02

Certification of Chief Financial Officer pursuant to Rule 13a-14 and Rule 15d 14(a), promulgated under the Securities and Exchange Act of 1934, as amended.

32.01

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer).

32.02

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer).

99.1	Reserve Report of James E. Smith & Associates, Independent Petroleum Engineers

† Previously filed

SIGNATURES

In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PEGASI ENERGY RESOURCES CORPORATION

Date: October 14 , 2011	By: /s/ MICHAEL NEUFELD
	Michael Neufeld
	Chief Executive Officer (Principal Executive Officer)

Date: October 14 , 2011	By: /s/ RICHARD LINDERMANIS
	Richard Lindermanis
	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

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

Name	Position	Date

/s/ MICHAEL NEUFELD	Chief Executive Officer (Principal Executive Officer) and Director	October 14, 2011
Michael Neufeld

/s/ RICHARD LINDERMANIS	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) and Director	October 14, 2011
Richard Lindermanis

/s/ ALAN GELFAND	Director	October 14, 2011
Alan Gelfand

/s/ DAVID J. MOSS	Director	October 14, 2011
David J. Moss

/s/ OLIVER WALDRON	Director	October 14, 2011
Oliver Waldron

Pegasi Energy Resources Corporation. - FORM 10-K/A - October 14, 2011

Attached files

Pegasi Energy Resources Corporation. Reports