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EX-32.2 - EXHIBIT 32.2 - Pegasi Energy Resources Corporation.ex322.htm
EX-23.1 - EXHIBIT 23.1 - Pegasi Energy Resources Corporation.ex231.htm
EX-31.2 - EXHIBIT 31.2 - Pegasi Energy Resources Corporation.ex312.htm
EX-31.1 - EXHIBIT 31.1 - Pegasi Energy Resources Corporation.ex311.htm
EX-21.1 - EXHIBIT 21.1 - Pegasi Energy Resources Corporation.ex211.htm
EX-23.2 - EXHIBIT 23.2 - Pegasi Energy Resources Corporation.ex232.htm
EX-32.1 - EXHIBIT 32.1 - Pegasi Energy Resources Corporation.ex321.htm
EX-14.1 - EXHIBIT 14.1 - Pegasi Energy Resources Corporation.ex141.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2009

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, 2009, based on the closing sales price of the Common Stock as quoted on the Over-the-Counter Bulletin Board was $10,598,770.65. 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 10, 2010, there were 33,610,801 shares of registrant’s common stock outstanding
 

 
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Table of Contents

 
  Part I   Page  
         
Item 1.
Business
    3  
           
Item 1A.
Risk Factors
    12  
           
Item 1B.
Unresolved Staff Comments
    20  
           
Item 2.
Properties
    20  
           
Item 3.
Legal Proceedings
    21  
           
Item 4.
Reserved.
    21  

   Part II   Page  
         
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters
     
 
and Issuer Purchases of Equity Securities
    22  
           
Item 6.
Selected Financial Data
    23  
           
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
    24  
           
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
    30  
           
Item 8.
Financial Statements and Supplementary Data
    F-1  
           
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
    31  
           
Item 9A.
Controls and Procedures
    31  
           
Item 9B.
Other Information
    32  
           
           
 
Part III
 
Page
 
           
Item 10.
Directors, Executive Officers and Corporate Governance
    33  
           
Item 11.
Executive Compensation
    35  
           
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
    37  
           
Item 13.
Certain Relationships and Related Transactions, and Director Independence
    38  
           
Item 14.
Principal Accounting Fees and Services
    39  
           
 
Part IV
 
Page
 
           
Item 15.
Exhibits, Financial Statement Schedules
    40  
           
Signatures.
      42  




 
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PART I

FORWARD-LOOKING INFORMATION

This 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 organic growth-oriented 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 have designated the “Cornerstone Project” or “CP”, 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 completion and seismic technology. We believe that our management team is uniquely familiar with the history and geology of the CP area based on their collective experience in the region as well as through our ownership of a large proprietary database which details the drilling history of the CP area over the previous 29 years. We believe our drilling strategy combined with the application of 3-D seismic imaging technology and the application of new drilling and completion techniques will enable us to find significant gas and oil reserves in the CP area. Our management team will also use its extensive experience and industry relationships to grow our company through new leasing and farm-in opportunities.

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 21,000 gross acres (approximately 14,000 net acres) as of December 2009. We have an 80% working interest in the acreage. 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. TR Energy currently maintains a 20% interest in the Cornerstone Project properties. Since initiating operations in 2000, we have drilled nine 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, 109 drilling locations have been identified on our present leased acreage. We are currently focusing on an initial well drilling program.
 
 
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If we are able to obtain funding, our initial 12-month vertical well drilling program will be to drill horizontal wells in the Bossier formation at the depths around 10,000 feet. We also 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 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 an aggressive drilling program. We will focus our near-term efforts on development drilling on existing acreage.
 
·
Apply management expertise in the CP 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.  The decision to complete in this manner will be determined after an evaluation of the electric logs and other open-hole logs are run in the well. 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 our management anticipates these wells will yield higher hydrocarbon flow rates than our vertical wells.
 
·
Continue to lease underdeveloped acreage in the Cornerstone Project area. We intend to use our 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 CP 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

We plan to initially drill vertical wells to approximately 10,500 feet targeting the lower Cotton Valley formation (primarily gas). The estimated future development cost expected to be incurred relative to the proved reserves in this formation totals approximately $12.4 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 6.6 billion cubic feet (“bcf”) and 0.16 million barrels of oil (“MMBO”) of proved undeveloped reserves, 1.4 bcf and .03 MMBO of proved behind-pipe reserves, 0.04 bcf and 0.03 MMBO of proved developed non-producing reserves and 0.3 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.
 
 
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Cotton Valley Vertical Well Economics
Estimated Future Development Costs   
~$12.4 mil
Estimated Ultimate Recovery:   
~9.5 bcfe
Finding and Development Costs:   
~$1.31 / mcfe 
% Gas: 
~86%  
 
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 $7 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 12.0 bcf and 0.55 MMBO of proved undeveloped reserves, 5.5 bcf and 0.22 MMBO of proved behind-pipe reserves, 0.4 bcf and 0.004 MMBO of proved developed non-producing reserves and 0.12 bcf and 0.009 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 
~$7 mil
Estimated Ultimate Recovery:  
~22.4 bcfe
Finding and Development Costs:  
~$0.31 / mcfe 
% Gas:  
~79%  
 
 
 
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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 three years ended December 31
 
     
2009
     
2008
     
2007
 
Production                        
Average sales price per mcf
  $ 3.25     $ 7.95     $ 5.96  
Average sales price per bbl
  $ 56.62     $ 100.76     $ 68.42  
Average production cost per mcfe
  $ 3.95     $ 2.84     $ 1.95  
Net oil production (barrels)
    5,719       7,429       4,964  
Net gas production (mcf)
    64,003       62,979       92,533  
Productive wells – oil
                       
Gross
    2       2       2  
Net
    2       2       1  
Productive wells – gas
                       
Gross
    3       3       5  
Net
    2       2       4  
Developed acreage
                       
Gross acreage
    2,767       2,767       1,387  
Net acreage
    2,760       2,760       1,387  
Undeveloped acreage
                       
Gross
    18,268       17,895       17,090  
Net
    11,580       11,303       11,722  
Drilling activity
                       
Net productive exploratory wells drilled
    -       -       -  
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, 2009

   
Reserves
 
   
Oil
   
Natural Gas
 
Reserves category
 
(bbls)
   
(mcf)
 
PROVED
           
  Developed
           
    United States
    45,656       772,470  
  Undeveloped
               
    United States
    963,243       25,537,685  
TOTAL PROVED
    1,008,899       26,310,155  

There were no material changes in our proved undeveloped reserves (“PUDs”) during 2009. See “Management's Discussion and Analysis of Financial Condition and Results of Operations” and “Note 16 – Subsequent Events” regarding our progress to convert our PUDS to proved developed reserves. We do not have material concentrations of PUDs in individual fields or countries that have remained undeveloped for five years or more after disclosure as PUDs. 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.

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.
 
 
 
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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.
 
 
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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.
 
 
8

 
 
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.
 
 
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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.


 
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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 1, 2010, 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.

 
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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 $2,811,950 and $684,923 for the years ended December 31, 2009 and 2008, 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.
 
 
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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 $1.65 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.
 
 
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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.

Our management team does not have extensive experience in public company matters, which could impair our ability to comply with legal and regulatory requirements.

Our management team has had limited public company management experience or responsibilities.  This could impair our ability to comply with legal and regulatory requirements such as the Sarbanes-Oxley Act of 2002 and applicable federal securities laws including filing required reports and other information required on a timely basis.  There can be no assurance that our management will be able to implement and affect programs and policies in an effective and timely manner that adequately respond to increased legal, regulatory compliance and reporting requirements imposed by such laws and regulations.  Our failure to comply with such laws and regulations could lead to the imposition of fines and penalties and further result in the deterioration of our business.


 
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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.  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.
 
 
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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 $72.34 in 2007, $99.67 in 2008, and $61.95 in 2009, and the average wellhead price per thousand cubic feet of natural gas was $6.25 in 2007, $7.96 in 2008, and $3.71 in 2009 (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.

 
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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.


 
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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.
 
 
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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 the Company's common stock on the National Association of Securities Dealers' 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.

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 the investors following registration of the shares of common stock issued in our initial offering in December 2007, and/or 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.
 
 
19

 

 
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 59.19% 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.

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 is for a five-year period expiring August 31, 2010 with an option to renew for two one-year periods on the same terms with inflation adjustments.  
 
 
  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 Houston, Texas office is located at 710 N. Post Oak Road, Suite 315, Houston, Texas 77024, and the phone number is (713) 824-0895.  The lease was on an annual basis expiring July 31, 2009.  Due to damage sustained during Hurricane Ike in October 2008 we are no longer able to occupy this office and therefore we are no longer paying rent.  We are unsure at this time if this property will be rebuilt.  We currently lease a total of approximately 7,500 square feet of office space in Tyler and Jefferson and believe that suitable additional space to accommodate our anticipated growth will be available in the future on commercially reasonable terms.

Our oil and gas assets are located in Cass and Marion counties in northeast Texas. As of December 31, 2009 we operated nine wells.
 
 
20

 
 
As of December 31, 2009, we held leases on approximately 21,000 gross acres, with us owning approximately 14,000 net acres. We have an 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.
          
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.  RESERVED.

 
21

 

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”.  Prior to February 6, 2008, our common stock was quoted on the OTCBB under the symbol “MPXP”.

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, 2008
 
   
High
   
Low
 
First Quarter
  $ 2.15     $ 1.20  
Second Quarter
  $ 2.95     $ 1.67  
Third Quarter
  $ 3.05     $ 1.75  
Fourth Quarter
  $ 2.05     $ 0.60  
                 
   
   
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  

HOLDERS

As of March 10, 2010, we had approximately 39 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.


 
22

 

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 10, 2010.

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
900,000
 
$
1.20
 
850,000
Equity compensation plans not approved by shareholders
-
 
$
-
 
-
           
Total
900,000
 
$
1.20
 
850,000

ITEM 6.  SELECTED FINANCIAL DATA.

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


 
23

 

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

The following information should be read in conjunction with the consolidated financial statements and the notes thereto contained elsewhere in this report. The Private Securities Litigation Reform Act of 1995 provides a "safe harbor" for forward-looking statements. Information in this Item 7, "Management's Discussion and Analysis of Financial Conditions and Results of Operations," and elsewhere in this 10-K that does not consist of historical facts, are "forward-looking statements." Statements accompanied or qualified by, or containing words such as "may," "will," "should," "believes," "expects," "intends," "plans," "projects," "estimates," "predicts," "potential," "outlook," "forecast," "anticipates," "presume," and "assume" constitute forward-looking statements, and as such, are not a guarantee of future performance. The statements involve factors, risks and uncertainties including those discussed in the “Risk Factors” section contained elsewhere in this report, the impact or occurrence of which can cause actual results to differ materially from the expected results described in such statements. Risks and uncertainties can include, among others, fluctuations in general business cycles and changing economic conditions; changing product demand and industry capacity; increased competition and pricing pressures; advances in technology that can reduce the demand for our products, as well as other factors, many or all of which may be beyond our control. Consequently, investors should not place undue reliance on forward-looking statements as predictive of future results. We disclaim any obligation to update the forward-looking statements in this report.

Overview

We are an organic growth-oriented 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 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 over the previous 30 years.  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.
 
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.

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.  In 2008, TR Rodessa expanded the capacity of its system through the construction of a new 9,238 foot 8”  trunkline. A total in excess of one mile of 4” laterals were constructed to the Childers #2, Harris #2, Huntington #4 and Childers # 3 well sites. These gathering lines have been tied into the central gathering point at the Huntington location.

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


 
24

 


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 an aggressive drilling program.  We will focus our near-term efforts on development drilling on existing acreage concentrating on oil potential.  We expect this drilling program to increase our proved reserve and cash flow profile.
 
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.
 
Continue to lease underdeveloped acreage in the Cornerstone Project area.  We plan to use 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 project area are held by smaller independent companies that lack the resources to exploit them fully.  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 to focus 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 may also consider farmout 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 $0.8 million.

Our oil and gas assets are located in Cass and Marion counties in northeast Texas.  As of December 31, 2009, we operated nine wells.  We did have a major workover on the 59 Disposal plant disposal well where the tubing was replaced and the well refurbished.  The work began early December 2009 and was completed in January 2010.

As of December 31, 2009, our leasehold position is approximately 21,000 gross acres and 14,000 net acres.  We have an 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.  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.  This would include 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 will pay 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.  There were no amounts paid at signing or guaranteed or conditional payments.

In addition to the operating of the 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.  The pipeline system was extended to connect to the Harris #2 and the Childers #2.  In 2008, we expanded our pipeline system by 9,238 feet by building a new eight-inch high pressure line to accommodate our production. Additional work is anticipated on the pipeline to enhance transportation of third-party gas.  

We are seeking to raise additional capital.  However, we currently do not have any other contracts or commitments for funding and there are no guarantees that we will be able to raise funds on terms acceptable to us.  Effective March 1, 2010, we executed an agreement with an independent investor relations consultant.  In return for the consultant’s services, he will receive Director and Officer insurance as our spokesperson, 20,000 shares of our common stock, and a monthly fee of $3,500 plus any approved expenses incurred related to work performed on our behalf.  One half of the shares pursuant to this agreement are due August 1, 2010 and the remaining shares are due on March 1, 2011.
 
 
25

 

 
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, 2009 Compared to Year Ended December 31, 2008

Summarized Consolidated Results of Operations

   
2009
   
2008
   
Increase (Decrease)
 
Total revenues
  $ 1,006,118     $ 2,601,236     $ (1,595,118 )
Total other operating expenses
    1,148,693       1,628,851       (480,158 )
Total general and administrative expense
    2,201,044       2,553,471       (352,427 )
Loss from operations
    (2,343,619 )     (1,581,086 )     762,533  
Total other expenses
    (474,033 )     (201,223 )     272,810  
Loss before income tax benefit
    (2,817,652 )     (1,782,309 )     1,035,343  
Income tax benefit
    5,702       1,097,386       (1,091,684 )
Net loss
  $ (2,811,950 )   $ (684,923 )   $ 2,127,027  

Revenues:  Total revenues for the year ended December 31, 2009 totaled $1,006,118, compared to $2,601,236 for the year ended December 31, 2008.  Production revenues of oil and gas decreased $720,637 to $537,410 for the year ended December 31, 2009 compared to $1,258,047 for the year ended December 31, 2008.  Approximately $553,000 of this decrease in revenues reflects the impact of a drop in sales prices from production on our operated wells, for natural gas of about 59% and oil of about 44%.  Approximately $164,000 of the decrease is due to a drop in production from our operated wells.  The remaining $3,000 decrease is related to production from wells in which we do not operate.  Transportation and gathering revenue decreased $596,014 to $246,264 for the for the year ended December 31, 2009, compared to $842,278 for the year ended December 31, 2008 due to the drop in sales price for natural gas.
 
Expenses:  Total other operating expenses for the year ended December 31, 2009 were $1,148,693, compared to $1,628,851 for the year ended December 31, 2008.  This change is comprised of decreases in cost of gas purchased for resale offset by an increase in lease operating expenses.  In addition, general and administrative expenses for the year ended December 31, 2009 were $2,201,044 compared to $2,553,471 for the year ended December 31, 2008.

Cost of Gas Purchased for Resale:  The $560,088 decrease in cost of gas purchased for resale to $148,054 for the year ended December 31, 2009 from $708,142 for the year ended December 31, 2008 is due to a drop in the purchase price for natural gas and volumes purchased from operators.

 
Lease Operating Expenses:  The $83,008 increase in lease operating expenses to $388,548 for the year ended December 31, 2009 from $305,540 for the year ended December 31, 2008 is primarily due to workover costs on the Bramlett and Ralph #1 wells and the operating costs of the Childers #2 and Harris #2 wells.  The Childers #2 and Harris #2 were not operating during the first six months of 2008.

General and Administrative Expense:  The $352,427 decrease in general and administrative expense to $2,201,044 for the year ended December 31, 2009 from $2,553,471 for the year ended December 31, 2008 is primarily due to decreased audit and accounting fees.  The decrease in audit and accounting fees of $259,565 was mainly due to work performed during the first nine months of 2008 related to the preparation of the S-1 registration statement, the 2007 10-K, and the restatement of the Form 10-Q for the three-month period ended March 31, 2008.  In addition, due to the decrease in revenue during 2009, we made a concerted effort to decrease expenses such as contract labor, automobile, and travel.
 
 
26

 

 
Other Income (Expenses):  Total other expenses for the year ended December 31, 2009 was $474,033, compared to $201,223 for the year ended December 31, 2008.  The primary reason for this $272,810 increase was primarily due to a $71,383 decrease in interest income and a $91,944 increase in interest expense.  Interest income decreased from $73,814 for the year ended December 31, 2008 to $2,431 for the year ended December 31, 2009 due to the significant decrease in cash as well as lower interest rates.  Interest expense increased from $364,775 for the year ended December 31, 2008 to $456,719 for the year ended December 31, 2009 due to an increase in the note payable, related party balance.  The remaining increase was partially due to an over accrual in 2008 of the liquidated damages expense that was corrected in the third quarter of 2008.

Income Tax Expense:  During the year ended December 31, 2009, we recognized an income tax benefit of $5,702 as compared to an income tax benefit of $1,097,386 for the year ended December 31, 2008.  The $1,091,684 difference is primarily due to a change in the valuation allowance at the end of 2008 because of the likelihood that we would not be liable for any deferred tax liabilities.

Operating Loss:  As a result of the above described revenues and expenses, we incurred a net operating loss of $2,811,950 in the year ended December 31, 2009 as compared to an operating loss of $684,923 in the year ended December 31, 2008.

Liquidity and Capital Resources

We held approximately $127,000 in cash and cash equivalents at December 31, 2009, compared to approximately $792,000 at December 31, 2008.  The decrease in cash and cash equivalents is related to purchases of lease 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.

Cash Flows

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

   
2009
   
2008
 
Total cash provided by (used in):
           
Operating activities
 
$
(1,643,875)
   
$
(2,710,683)
 
Investing activities
   
(489,615)
     
(4,687,328)
 
Financing activities
   
1,468,411
     
(745,017)
 
Decrease in cash and cash equivalents
 
$
(665,079)
   
$
(8,143,028)
 
  
Cash used in operating activities for the year ended December 31, 2009 totaled $1,643,875, compared to $2,710,683 used in operating activities for the year ended December 31, 2008.  The change is primarily due to an additional $2,034,777 provided by changes in connection with operating assets and liabilities offset by an increase in the net loss. The net loss was $2,811,950 for the year ended December 31, 2009, an increase from the net loss of $684,923 for the year ended December 31, 2008.  The changes in operating assets and liabilities are primarily due to changes in accounts receivable, related parties, other current assets, accounts payable, related parties, joint-interest deposits, related parties, and interest payable, related party.

Cash used in investing activities for the year ended December 31, 2009 was $489,615, compared to $4,687,328 for the year ended December 31, 2008.  The change is due primarily to decreased drilling activities during the year ended December 31, 2009.  Drilling and completion of the Harris #2 and Childers #2 wells were finished in January and February 2008, respectively.  We spent approximately $459,000 on lease and well equipment and leasehold costs in 2009, compared to approximately $4,500,000 on lease and well equipment, leasehold costs, and intangible drilling and completion costs in 2008.  Finally, property and equipment purchases were approximately $30,000 in 2009 compared to approximately $221,000 in 2008.

Cash provided by financing activities for the year ended December 31, 2009 totaled $1,468,411, compared to $745,017 of cash used in financing activities for the year ended December 31, 2008.  In 2009, we received cash proceeds of $1,475,000 on a related party note payable.  In January 2008, we made a payment of $742,544 of principal on that same related party note payable.
 
 
27

 

 
Sources of Liquidity

Our main source of liquidity continues to be from funds generated by production from our wells.  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 additional financing available from related parties will be sufficient to finance our operations for 2010. However, we have no additional commitments from related parties beyond those already in place. 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 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 have aggressively contacted many potential investors both within the industry as well as institutional investors to secure additional financing.  Additional financing would be use for in 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 also entered into a credit agreement with lenders led by Amegy Bank, N.A. in November 2007.  Pursuant to the terms of the credit agreement, the aggregate commitment is $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 will be $5 million and the initial monthly borrowing base reduction will be determined on the initial funding date.  As of December 31, 2009, these conditions had not been met.

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.
 
 
28

 
 
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.

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 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 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 July 2009, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, which replaces SFAS No, 162, The Hierarchy of Generally Accepted Accounting Principles.  As of September 15, 2009, the date that SFAS No. 168 became effective, the new name for this standard is, FASB ASC Topic No. 105, Generally Accepted Accounting Principles.  FASB ASC Topic No. 105 establishes the FASB ASC (the “Codification”) as the source of authoritative U.S. GAAP.  Now that the Codification is in effect, all of its content carries the same level of authority.  FASB ASC Topic No. 105 became effective September 15, 2009.  The FASB does not expect that FASB ASC Topic No. 105 will result in a change in current practice, and the Company does not believe that FASB ASC Topic No. 105 will have an impact on its consolidated operating results, financial position, or cash flows.
 
 
29

 

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

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

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


 
30

 

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, 2009 and 2008
    F-3  
         
Consolidated Statements of Operations for the years ended December 31, 2009 and 2008
    F-5  
         
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2009 and 2008
    F-6  
         
Consolidated Statements of Cash Flows for the years ended December 31, 2009 and 2008
    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

We have audited the accompanying consolidated balance sheets of Pegasi Energy Resources Corporation as of December 31, 2009 and 2008, 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 as of December 31, 2009 and 2008, 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.

/s/ Whitley Penn LLP
 
Fort Worth, Texas
March 29, 2010


 
F-2

 

PEGASI ENERGY RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS

       
   
December 31,
 
   
2009
   
2008
 
Assets
           
Current assets:
           
Cash and cash equivalents
 
$
127,176
   
$
792,255
 
Accounts receivable, trade
   
98,578
     
249,651
 
Accounts receivable, related parties
   
13,002
     
69,408
 
Joint interest billing receivable, related parties, net
   
17,983
     
58,249
 
Other current assets
   
128,483
     
166,972
 
Total current assets
   
385,222
     
1,336,535
 
                 
Property and equipment:
               
Equipment
   
601,759
     
573,188
 
Pipelines
   
700,765
     
701,806
 
Buildings
   
19,916
     
19,916
 
Leasehold improvements
   
7,022
     
7,022
 
Vehicles
   
50,663
     
50,663
 
Office furniture
   
137,071
     
134,407
 
Website
   
15,000
     
15,000
 
Total property and equipment
   
1,532,196
     
1,502,002
 
Less accumulated depreciation
   
(515,101
   
(368,878
)
Property and equipment, net
   
1,017,095
     
1,133,124
 
                 
Oil and gas properties:
               
Oil and gas properties, proved
   
11,928,985
     
11,905,413
 
Oil and gas properties, unproved
   
9,150,426
     
8,714,577
 
Capitalized asset retirement obligations
   
220,237
     
220,237
 
Total oil and gas properties
   
21,299,648
     
20,840,227
 
Less accumulated depletion and depreciation
   
(900,275
   
(806,303
)
Oil and gas properties, net
   
20,399,373
     
20,033,924
 
                 
Total assets
 
$
21,801,690
   
$
22,503,583
 

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

 
F-3

 


PEGASI ENERGY RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS (continued)

 
   
December 31,
 
   
2009
   
2008
 
             
Liabilities and Stockholders' Equity
           
Current liabilities:
           
Accounts payable
 
$
251,336
   
$
202,710
 
Accounts payable, related parties
   
874,076
     
684,996
 
Revenue payable
   
104,366
     
194,560
 
Interest payable, related parties
   
840,052
     
385,160
 
Liquidated damages payable
   
142,083
     
121,579
 
Other payables
   
35,795
     
54,061
 
Current portion of notes payable
   
6,570
     
6,575
 
Current portion of notes payable, related parties
   
6,352,303
     
-
 
Total current liabilities
   
8,606,581
     
1,649,641
 
                 
Notes payable
   
4,803
     
11,387
 
Notes payable, related parties
   
-
     
4,857,303
 
Asset retirement obligations
   
300,311
     
283,307
 
Total liabilities
   
8,911,695
     
6,801,638
 
                 
Commitments and contingencies (Note 15)
               
                 
Stockholders' equity:
               
Common stock: $0.001 par value; 75,000,000 shares authorized; 33,610,801 shares issued and outstanding
 
  
33,611
 
 
 
33,611
 
Additional paid-in capital
 
   
19,673,102
 
 
 
19,673,102
 
Accumulated deficit
 
 
(6,816,718
 
 
(4,004,768
)
Total stockholders' equity
 
  
12,889,995
 
 
 
15,701,945
 
         
 
     
Total liabilities and stockholders' equity
 
$
21,801,690
   
$
22,503,583
 
 
 

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,
 
     
2009
     
2008
 
Revenues:
               
  Oil and gas
 
$
537,410
   
$
1,258,047
 
  Condensate and skim oil
   
89,416
     
242,947
 
  Transportation and gathering
   
246,264
     
842,278
 
  Saltwater disposal income
   
133,028
     
257,964
 
Total revenues
   
1,006,118
     
2,601,236
 
Operating expenses:
               
   Lease operating expenses
   
388,548
     
305,540
 
   Saltwater disposal expenses
   
293,150
     
261,233
 
   Pipeline operating expenses
   
78,746
     
171,892
 
   Cost of gas purchased for resale
   
148,054
     
708,142
 
   Depletion and depreciation  
   
240,195
     
182,044
 
   General and administrative
   
2,201,044
     
2,553,471
 
   Total operating expenses
   
3,349,737
     
4,182,322
 
Loss from operations
   
(2,343,619
   
(1,581,086
                 
Other income (expenses):
               
  Interest income
   
2,431
     
73,814
 
  Interest expense
   
(456,719
   
(364,775
  Dividend income
   
-
     
311
 
  Other income (expense)
   
(19,745
   
89,427
 
Total other expenses
   
(474,033
   
(201,223
                 
Loss before income tax benefit
   
(2,817,652
   
(1,782,309
                 
Income tax benefit
   
5,702
     
1,097,386
 
Net loss
 
$
(2,811,950
 
$
(684,923
                 
Basic and diluted loss per share
 
$
(0.08
 
$
(0.02
                 
Weighted average shares outstanding
   
33,610,801
     
30,361,295
 

 

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, 2009 and 2008

               
Additional
             
   
Common Stock
   
Paid-in
   
Accumulated
       
   
Shares
   
Amount
   
Capital
   
Deficit
   
Total
 
                               
Balance at January 1, 2008
    29,378,482     $ 29,378     $ 11,206,945     $ (3,319,845 )   $ 7,916,478  
                                         
     Shares issued for legal services
    35,000       35       76,965       -       77,000  
     Shares issued for asset acquisition
    4,200,000       4,200       8,395,800       -       8,400,000  
     Shares cancelled
    (2,681 )     (2 )     (6,608 )     -       (6,610 )
     Net loss
    -       -       -       (684,923 )     (684,923 )
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  


 

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,
 
   
2009
   
2008
 
Operating Activities
           
Net loss
 
$
(2,811,950
 
$
(684,923
Adjustments to reconcile net loss to net cash used in operating activities:
               
Depletion and depreciation
   
240,195
     
182,044
 
Accretion of discount on asset retirement obligations
   
17,004
     
11,864
 
Stock issued for legal services
   
-
     
77,000
 
Deferred income taxes
   
-
     
(1,097,934
(Gain) loss from liquidated damages
   
20,504
     
(29,177
Other
   
-
     
(25,152
Changes in operating assets and liabilities:
               
  Accounts receivable, trade
   
151,073
     
19,749
 
  Accounts receivable, related parties
   
56,406
     
37,518
 
  Joint interest billing receivable, related parties, net
   
40,266
     
64,293
 
  Other current assets
   
38,489
     
155,138
 
  Accounts payable
   
48,626
     
(775,047
  Accounts payable, related parties
   
209,080
     
104,901
 
  Revenue payable
   
(90,194)
     
16,446
 
  Interest payable, related parties
   
454,892
     
85,997
 
  Joint interest deposits, related parties
   
-
     
(849,619
  Other payables
   
(18,266
   
(3,781
Net cash used in operating activities
   
(1,643,875
   
(2,710,683
                 
Investing Activities
               
Purchases of property and equipment
   
(30,194
   
(220,928
Purchases of oil and gas properties
   
(459,421
   
(4,466,400
Net cash used in investing activities
   
(489,615
   
(4,687,328
                 
Financing Activities
               
Proceeds from notes payable
   
-
     
9,521
 
Payments on notes payable
   
(6,589
   
(5,384
Borrowings on notes payable, related party
   
1,475,000
     
-
 
Payments on notes payable, related party
   
-
     
(742,544
Payments for cancelled shares of common stock1
   
-
     
(6,610
Net cash provided by (used in) financing activities
   
1,468,411
     
(745,017
                 
Net decrease in cash and cash equivalents
   
(665,079
   
(8,143,028
Cash and cash equivalents at beginning of year
   
792,255
     
8,935,283
 
Cash and cash equivalents at end of year
 
$
127,176
   
$
792,255
 
 
1    2,681 net shares of common stock were cancelled by investors in the year ended December 31, 2008.
 
See Note 3 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, 2009 AND 2008


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.


 
F-8

 
PEGASI ENERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008


a)  Consolidation and Use of Estimates - continued
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
Cash and cash equivalents include cash in banks, money market accounts, and all highly-liquid investments with an original maturity of three months or less.   At December 31, 2009 and 2008, the Company had no cash equivalents.

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, 2009 or 2008.  Accounts receivables from three customers approximated 44%, 37%, and 15% of the Company’s total trade receivables at December 31, 2009.  As of December 31, 2008, four customers, three of which are the same customers, totaled approximately 27%, 22%, 21%, and 11% 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 $146,223 and $123,874 for the years ended December 31, 2009 and 2008, 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, 2009 and 2008.

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 period.

 
F-9

 
PEGASI ENERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008


e)  Oil and Gas Properties - continued
The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2009, 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 majority of the evaluation activities are expected to be completed within five to ten years.

                 
2006
 
 
Total
 
2009
 
2008
 
2007
 
and Prior
 
 
(In thousands)
 
Property acquisition costs
 
$
9,150
   
$
435
   
$
4,679
   
$
919
   
$
3,117
 
 
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.
 
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)  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.

j)  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, 2009 and 2008 the Company had potentially dilutive shares of approximately 10,462,484 and 10,738,293, respectively,  which are not included in the calculation of the net loss per share, because the effect would be anti-dilutive. For the years ended December 31, 2009 and 2008, the diluted loss per share is the same as basic loss per share, as the effect of common stock equivalents are anti-dilutive.
.
 
F-10

 
PEGASI ENERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008

 
 
k)  Fair Value of Financial Instruments
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.  

l)  New Accounting Pronouncements
In July 2009, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, which replaces SFAS No, 162, The Hierarchy of Generally Accepted Accounting Principles.  As of September 15, 2009, the date that SFAS No. 168 became effective, the new name for this standard is, FASB ASC Topic No. 105, Generally Accepted Accounting Principles.  FASB ASC Topic No. 105 establishes the FASB ASC (the “Codification”) as the source of authoritative U.S. GAAP.  Now that the Codification is in effect, all of its content carries the same level of authority.  FASB ASC Topic No. 105 became effective September 15, 2009.  The FASB does not expect that FASB ASC Topic No. 105 will result in a change in current practice, and the Company does not believe that FASB ASC Topic No. 105 will have an impact on its consolidated operating results, financial position, or cash flows.

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


3.     SUPPLEMENTAL CASH FLOW AND NON-CASH INFORMATION
 
The following non-cash transactions were recorded during the years ended December 31:
 
   
2009
   
2008
 
Shares issued for legal services
   
-
     
77,000
 
Shares issued for asset acquisition
   
-
     
8,400,000
 
Accounts payable, related parties converted into notes payable, related parties
 
$
20,000
   
$
-
 

The following is supplemental cash flow information for the years ended December 31:
   
2009
   
2008
 
Cash paid during the year for income taxes
  $ -     $ -  
Cash paid during the year for interest
  $ 1,827     $ 278,778  
.
 
F-11

 
PEGASI ENERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008


 

4.   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


5.  LINE-OF-CREDIT

Amegy Bank, N.A.
On November 28, 2007, PERC entered into a credit agreement with a group of lenders led by Amegy Bank, N.A. (“Amegy”), as administrative agent and as issuing lender.  Pursuant to the terms of the credit agreement, the aggregate commitment is $50 million and the maturity date is November 28, 2010.  There is no initial borrowing base and no initial monthly borrowing base reduction under the Agreement.  Upon satisfaction of various conditions precedent to the initial credit extension, the borrowing base will be $5 million and the initial monthly borrowing base reduction will be determined on the initial funding date.  As of December 31, 2009, these conditions had not been met.

The borrowing base and the monthly borrowing base reduction will be determined using proved reserves and will be redetermined every six months with one additional redetermination possible during the various six-month periods between scheduled redeterminations.

At the Company's option, interest is based on either (i) the prime rate plus the applicable margin not to exceed the highest lawful rate or (ii) the LIBOR rate applicable to the interest period plus the applicable margin, not to exceed the highest lawful rate.  For base rate loans, interest is due monthly.  For LIBOR loans that are three months or less in maturity, interest is due on the maturity date of such loan.  For LIBOR loans that are in excess of three months, interest is due every three months.
 
The credit agreement imposes certain restrictions, subject to specific exceptions, on the Company and its wholly-owned subsidiaries including, but not limited to, the following:  (i) incurring additional liens; (ii) incurring additional debt; (iii) making certain payments, including cash dividends to stockholders; (iv) making any loans, advances, or making any investment in, or purchasing, or committing to purchase any stock or other securities or evidences of indebtedness or interests in any person or any oil and natural gas properties or activities related to oil and natural gas properties unless with regard to new oil and natural gas properties, such properties are mortgaged to Amegy, as administrative agent; (v) incurring additional leases; (vi) entering into affiliate transactions on terms that are not at least as favorable to the Company as comparable arm’s length transactions; and (vii) merging or consolidating or selling, transferring, assigning, farming-out, conveying or otherwise disposing of any property.

The obligation under the credit agreement will be secured by a lien on: (i) all of the mortgaged properties; (ii) accounts receivable, notes receivable, inventory, contract rights, general intangibles and other personal property; (iii) subsidiary equity interests, and (iv) other collateral as provided in the agreement.  In addition, each of the Company’s wholly-owned subsidiaries guaranteed all of the Company’s obligations.



 
F-12

 
PEGASI ENERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008


6.   NOTES PAYABLE AND CAPITAL LEASES
 
Notes payable and capital leases consisted of the following at December 31:
   
2009
   
2008
 
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
  $ 6,664     $ 8,418  
                 
                 
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,
               
maturing November 7, 2010.
    4,709       9,544  
                 
                             Total notes payable
    11,373       17,962  
                             Less current portion
    6,570       6,575  
                 
 Total long term (notes payable and capital leases)
  $ 4,803     $ 11,387  
 
Future annual maturities of notes payable and capital leases at December 31, 2009 are as follows:

Year Ended
     
    2010
 
$
6,570
 
    2011
   
1,977
 
    2012
   
2,098
 
    2013
   
728
 
         
Total
 
$
11,373
 
 

 
F-13

 
PEGASI ENERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008


7.    NOTES PAYABLE. RELATED PARTIES

Notes payable, related parties consisted of the following at December 31:
   
2009
   
2008
 
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.
 
$
5,952,303
   
$
4,857,303
 
                 
Promissory note payable in the amount of $1 million dated October 14, 2009 to Teton. Accrued interest of 6.25% per annum on the principal amount, which is the sum of all advances made, is due July 1, 2010.  The remaining accrued
               
interest and outstanding principal balance are due on the maturity date of October 14, 2010.
   
400,000
     
-
 
                 
Total notes payable, related parties
   
6,352,303
     
4,857,303
 
Less current portion
   
6,352,303
     
-
 
Total long-term notes payable, related parties
 
$
-
   
$
4,857,303
 
                 
 
Future annual maturities of notes payable at December 31, 2009 are as follows:

Year Ended
     
    2010
 
$
6,352,303
 
         

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.

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 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.




 
F-14

 
PEGASI ENERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008


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 $220,237 at both December 31, 2009 and 2008.

The liability has been accreted to its present value as of the end of each year.  The Company evaluated 13 wells, and has determined a range of abandonment dates through June 2022.

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

   
2009
   
2008
 
             
    Asset retirement obligations at beginning of year
 
$
283,307
   
$
271,443
 
    Asset retirement obligations incurred in the current year
   
-
     
-
 
    Revisions to estimates
   
-
     
-
 
    Accretion of discount
   
17,004
     
11,864
 
    Asset retirement obligations at end of year
 
$
300,311
   
$
283,307
 

In order to ensure current costs are reflected in the estimation of retirement costs, the Company obtained assurance from its independent petroleum engineer in 2009 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.

On December 31, 2007, pursuant to the 2007 Plan, the Company issued stock options for 900,000 shares of common stock to various managers and directors, in exchange for certain financial and management consulting services.  Each option entitles the holder to acquire one common share at an exercise price of $1.20.  These options vested immediately upon issuance at December 31, 2007, and are exercisable at any time, in whole or part, until December 31, 2012.
 
On December 26, 2008, the Company adopted the 2008 Incentive Stock Option Plan (the “2008 Plan”) for employees, directors, executives, and consultants to reward them for making major contributions to the success of the Company by issuing long-term incentive awards under the 2008 Plan thereby providing them with an interest in the growth and performance of the Company.  The 2008 Plan reserves 5,000,000 shares of common stock for issuance by the Company as stock options, stock awards or restricted stock purchase offers.
 
There were no stock options granted during the year ended December 31, 2009, under either the 2008 or 2007 plans.


 
F-15

 
PEGASI ENERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008


A summary of options granted during the years ended December 31, 2009 and 2008 is as follows:
 
   
Options
   
Weighted Average
Exercise Price
   
Weighted Average Grant Date Fair Value
 
                   
Outstanding at January 1, 2008
    900,000     $ 1.20     $ 0.70  
Options granted
    -       -       -  
Options exercised
    -       -       -  
Outstanding at December 31, 2008
    900,000     $ 1.20     $ 0.70  
Options granted
    -       -       -  
Options exercised
    -       -       -  
Outstanding at December 31, 2009
    900,000     $ 1.20     $ 0.70  

 
The following is a summary of stock options outstanding at December 31, 2009:
                     
Exercise
   
Options
   
Contractual
   
Options
 
Price
   
Outstanding
   
Lives (Years)
   
Exercisable
 
$
1.20
     
900,000
     
3
     
900,000
 
 
Based on the Company's stock price of $0.31 at December 31, 2009, the options outstanding had no intrinsic value.
  
Total options exercisable at December 31, 2009 amounted to 900,000 shares and had a weighted average exercise price of $1.20.  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, 2009 and 2008:
 
         
Weighted Average
 
   
Shares
   
Exercise Price
 
December 31, 2009
   
900,000
   
 $
1.20
 
December 31, 2008
   
900,000
   
 $
1.20
 
 
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.
 

 
F-16

 
PEGASI ENERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008



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.  There were no changes in the Company’s non-vested stock options that occurred during the years ended December 31, 2009 and 2008. 

As of December 31, 2009 and 2008, the Company had no unrecognized compensation expense related to non-vested stock-based compensation arrangements.  There were no options granted or vested during the years ended December 31, 2009 and 2008.  The 2007 options have a remaining weighted average contractual term of 3 years.
 
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 cashlessly 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 4,187,892 shares of common stock exercisable until December 31, 2012 in connection with a securities purchase agreement.  The warrants have an exercise price of $1.60 per share.

 A summary of warrants granted during the years ended December 31, 2009 and 2008 is as follows:
 
   
Warrants
   
Weighted Average Exercise Price
 
Outstanding at December 31, 2007
   
9,213,634
   
1.60
 
Warrants issued
   
9,615
     
1.60
 
Warrants exercised
   
-
     
-
 
Outstanding at December 31, 2008
   
9,223,249
     
1.60
 
Warrants issued
   
-
     
-
 
Warrants exercised
   
-
     
-
 
Outstanding at December 31, 2009
   
9,223,249
   
$
1.60
 
 

11.     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:
   
2009
   
2008
 
Deferred income tax benefit:
           
U.S. Federal
 
$
-
   
$
1,097,934
 
Current income tax benefit (expense):
               
State and local
   
5,702
     
(548
Income tax benefit
 
 $
5,702
   
$
1,097,386
 
 
 
F-17

 
PEGASI ENERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008

 
 
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:

   
2009
   
2008
 
             
Computed “expected” tax benefit
 
$
958,002
   
$
605,985
 
State and local income taxes, net of federal income tax benefit
   
3,763
     
(362)
 
Change in valuation allowances
   
(1,054,242
)
   
486,611
 
Non-deductible expenses
   
(4,551
)
   
(5,325)
 
Other
   
102,730
     
10,477
 
Income tax benefit
 
$
5,702
   
$
1,097,386
 

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:
 
   
2009
   
2008
 
Deferred tax assets:
 
         
    Net operating loss carry forwards
 
$
2,524,420
   
$
1,390,470
 
    Deferred interest expense
   
285,618
     
130,954
 
    Liquidated damages payable
   
48,308
     
41,337
 
    Accretion expense
   
27,225
     
21,444
 
    Contributions carry forward
   
605
     
442
 
    Accrued salaries
   
161,500
     
80,750
 
    Valuation allowance
   
(1,292,363)
     
(238,121)
 
Total deferred tax assets
   
1,755,313
     
1,427,276
 
                 
Deferred tax liabilities:
               
     Oil and gas properties
   
(1,514,020)
     
(1,200,768)
 
     Fixed assets and organization costs
   
(241,293)
     
(226,508)
 
Total deferred tax liabilities
   
(1,755,313)
     
(1,427,276)
 
                 
Net deferred tax liability
 
$
-
   
$
-
 

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 $7,425,000 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.  The Company accrued $15,093 for margin tax payable at December 31, 2008.  No margin tax accrual was necessary at December 31, 2009


 
F-18

 
PEGASI ENERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008



12.      SEGMENT INFORMATION

The following information is presented in accordance with FASB ASC Topic No. 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, 2009 and 2008:
  
 
Year Ended December 31,
 
   
2009
   
2008
 
             
Business segment revenue:
           
    Oil and gas sales
 
$
537,410
   
$
1,258,047
 
    Condensate and skim oil
   
89,416
     
242,947
 
    Transportation and gathering
   
246,264
     
842,278
 
    Saltwater disposal sales
   
133,028
     
257,964
 
Total revenues
 
$
1,006,118
   
$
2,601,236
 
                 
Business segment profit (loss):
               
  Oil and gas sales
 
$
(467,559)
   
$
266,488
 
  Condensate and skim oil
   
89,416
     
242,947
 
  Transportation and gathering
   
(36,907)
     
(99,538
)
  Saltwater disposal sales
   
(258,099)
     
(99,635
)
  General corporate
   
(1,670,470)
     
(1,891,348
)
Loss from operations
 
$
(2,343,619)
   
$
(1,581,086
)
 
 
 
 

 
 
F-19

 
PEGASI ENERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008



   
 
 
Year Ended December 31,
 
   
2009
   
2008
 
Depletion and depreciation:
           
  Oil and gas sales
 
$
105,601
   
$
66,693
 
  Transportation and gathering
   
30,401
     
24,555
 
  Saltwater disposal sales
   
67,522
     
59,696
 
  General corporate
   
36,671
     
31,100
 
Total depletion and depreciation
 
$
240,195
   
$
182,044
 
                 
Capital expenditures:
               
Oil and gas sales
 
$
458,380