UNITED STATES
 SECURITIES AND EXCHANGE COMMISSION
 WASHINGTON, D.C. 20549
 
 FORM 10-Q
 
 (Mark One)
 
 x

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2011
  OR
 
  ̈

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 FOR THE TRANSITION PERIOD FROM ____________ TO ____________
 
 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)

(I.R.S. Employer

Identification Number)
 
 218 N. Broadway, Suite 204

Tyler, Texas 75702(Address of principal executive offices) (Zip Code)
 
 Registrant’s telephone number, including area code: 903- 595-4139
 
 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  ̈
 
 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 (§232.405 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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a small reporting company.  See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
 Large accelerated filer o
Accelerated filer oNon-accelerated filer o
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 in Rule 12b-2) of the Act. Yes   ̈ No   x .
 
 There were 44,438,601 shares of the registrant's common stock outstanding as of August 18, 2011.
 
 
 
 1
 
 
 PEGASI ENERGY RESOURCES CORPORATION
 CONSOLIDATED FINANCIAL STATEMENTS
 FOR THE QUARTER ENDED JUNE 30, 2011
 
 TABLE OF CONTENTS
 
 PagePART I - FINANCIAL INFORMATIONItem 1. Financial Statements
3Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
15Item 3. Quantitative and Qualitative Disclosures About Market Risk
22Item 4. Controls and Procedures
23PART II - OTHER INFORMATIONItem 1. Legal Proceedings
25Item 1A. Risk Factors
25Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
25Item 3. Defaults Upon Senior Securities
25Item 4. (Removed and Reserved)
25Item 5. Other Information
25Item 6. Exhibits
25SIGNATURES
26
    
 2
 
 PART I - FINANCIAL INFORMATION
 
 Item 1. Financial Statements.
 PEGASI ENERGY RESOURCES CORPORATION
 CONSOLIDATED BALANCE SHEETS
 
 June 30,


December 31,2011


2010(Unaudited)AssetsCurrent assets:Cash and cash equivalents

$
442,480


$
249,802Accounts receivable, trade


447,727



186,669Accounts receivable, related parties


13,002



13,002Joint-interest billings receivable, related parties, net


72,342



192,700Joint-interest billings receivable, net


53,470



29,627Assets held for sale


300,347



300,347Other current assets


56,670



52,440Total current assets


1,386,038



1,024,587Property and equipment:Equipment


73,099



83,711Pipelines


722,809



722,937Leasehold improvements


7,022



7,022Vehicles


50,663



50,663Office furniture


135,689



135,689Website


15,000



15,000Total property and equipment


1,004,282



1,015,022Less accumulated depreciation


(361,973
)


(334,668
)Property and equipment, net


642,309



680,354Oil and gas properties:Oil and gas properties, proved


11,775,650



11,762,909Oil and gas properties, unproved


9,291,183



9,044,960Capitalized asset retirement obligations


219,040



219,040Total oil and gas properties


21,285,873



21,026,909Less accumulated depletion


(1,112,638
)


(1,018,100
)Oil and gas properties, net


20,173,235



20,008,809Other assets:Restricted cash – leasing program


20,291



394,693Restricted cash – drilling program


721,038



793,611Deferred financing costs


20,000



-Certificates of deposit


78,128



77,947Total other assets


839,457



1,266,251Total assets

$
23,041,039


$
22,980,001
 
 The accompanying notes are an integral part of these consolidated financial statements.
 
 
 3
 
 
 PEGASI ENERGY RESOURCES CORPORATION
 CONSOLIDATED BALANCE SHEETS (CONTINUED)
 
 June 30,


December 31,2011


2010(Unaudited)Liabilities and Stockholders’ EquityCurrent liabilities:Cash overdraft

$
660,432


$
340,118Accounts payable


1,086,536



658,316Accounts payable, related parties


1,643,148



1,321,979Revenues payable


385,867



124,723Interest payable, related party


710,862



394,704Liquidated damages payable


189,972



173,802Other payables


34,580



27,893Current portion of notes payable


2,037



1,976Current portion of notes payable, related party


-



8,160,646Total current liabilities


4,713,434



11,204,157Lease program deposits


20,291



394,693Drilling prepayments


721,038



793,611Notes payable


1,793



2,826Notes payable, related party


8,160,646



-Asset retirement obligations


327,974



317,279Derivative warrant liability


2,022,203



3,638,311Total liabilities


15,967,379



16,350,877Commitments and contingencies (Note 10)Stockholders' equity:Preferred stock: $0.001 par value; 5,000,000 shares authorized;None issued and outstanding


-



-Common stock; $0.001 par value; 125,000,000 sharesAuthorized; 33,660,801 shares issued and outstanding atJune 30, 2011 and 33,610,801 shares at December 31, 2010


33,661



33,611Additional paid-in capital


19,923,354



19,903,404Accumulated deficit


(12,883,355
)


(13,307,891
)Total stockholders' equity


7,073,660



6,629,124Total liabilities and stockholders' equity

$
23,041,039


$
22,980,001
 
 
 The accompanying notes are an integral part of these consolidated financial statements.
  
 4
 
 PEGASI ENERGY RESOURCES CORPORATION
 CONSOLIDATED STATEMENTS OF OPERATIONS
 (UNAUDITED)
 
 
 
 
 Three Months

Ended June 30,


Six Months

Ended June 30,2011


2010


2011


2010Revenues:Oil and gas

$
234,468


$
127,603


$
435,634


$
305,319Condensate and skim oil


12,472



17,725



21,171



24,363Transportation and gathering


53,242



64,232



200,699



131,620Total  revenues


300,182



209,560



657,504



461,302Operating expenses:Lease operating expenses


108,468



75,242



209,968



151,503Pipeline operating expenses


37,635



28,182



76,667



47,341Cost of gas purchased for resale


-



39,437



94,814



86,495Depletion and depreciation


70,742



37,023



132,455



78,218General and administrative


474,795



445,165



1,062,381



960,479Total operating expenses


691,640



625,049



1,576,285



1,324,036Loss from operations


(391,458
)


(415,489
)


(918,781
)


(862,734
)Other income (expenses):Interest income


79



195



181



386Interest expense


(160,857
)


(142,936
)


(322,035
)


(277,032
)Liquidated damages


(8,221
)


(5,126
)


(16,170
)


(10,252
)Changes in fair value of warrant derivative liability


2,497,311



-



1,616,108



-Other income (expense)


-



-



5,068



(5,723
)Total other income (expenses)


2,328,312



(147,867
)


1,283,152



(292,621
)Income (loss) from continuing operations before income tax expense


1,936,854



(563,356
)


364,371



(1,155,355
)Income tax benefit


11,092



-



21,051



-Income (loss) from continuing operations


1,947,946



(563,356
)


385,422



(1,155,355
)Income (loss) from discontinued operations (net of tax expenses of $11,092, $-0-, $21,051 and $-0-, respectively)


20,620



(15,295
)


39,114



(106,174
)Net income (loss)

$
1,968,566


$
(578,651
)

$
424,536


$
(1,261,529
)Basic and diluted income (loss) per share:Income (loss) from continuing operations


0.06



(0.02
)


0.01



(0.04
)Income (loss) from discontinued operations


0.00



(0.00
)


0.00



(0.00
)Net income (loss)

$
0.06


$
(0.02
)

$
0.01


$
(0.04
)Weighted average shares outstanding-basic and diluted


33,660,801



33,610,801



33,644,503



33,610,801
 
 
 The accompanying notes are an integral part of these consolidated financial statements.
    5
  PEGASI ENERGY RESOURCES CORPORATION
 CONSOLIDATED STATEMENTS OF CASH FLOWS
 (UNAUDITED)
 
 
 
 Six Months Ended June 30,2011


2010Operating ActivitiesNet income (loss)

$
424,536


$
(1,261,529
)Adjustments to reconcile net income (loss) to net cash used in operating activities:Depletion and depreciation


132,455



117,861Accretion of discount on asset retirement obligations


10,695



9,012Stock issued for consulting services


20,000



-Loss on abandonment of equipment


-



5,727Gain on sale of equipment


(4,872
)


-Changes in fair value of warrant derivative liability


(1,616,108
)


-Changes in operating assets and liabilities:Accounts receivable, trade


(261,058
)


(1,512
)Accounts receivable, related parties


-



1,728Joint-interest billings receivable, net


(23,843
)


-Joint-interest billings receivable, related parties, net


120,358



7,308Other current assets


(4,230
)


46,480Accounts payable


428,220



131,473Accounts payable, related parties


321,169



253,233Revenues payable


261,144



(8,822
)Interest payable, related party


316,158



273,988Liquidated damages payable


16,170



10,252Drilling prepayments


-



145,458Other payables


6,687



(16,221
)Net cash provided by (used in) operating activities


147,481



(285,564
)Investing ActivitiesAdditions to certificate of deposit


(181
)


(386
)Proceeds from sale of working interest


-



265,565Purchases of property and equipment


-



(85,221
)Purchases of oil and gas properties


(258,964
)


(48,327
)Proceeds from sale of property and equipment


5,000



-Net cash provided by (used in) investing activities


(254,145
)


131,631Financing ActivitiesPayments on notes payable


(972
)


(3,459
)Cash overdraft


320,314



-Proceeds from borrowing on notes payable, related party


-



723,000Payments for stock issuance costs


(20,000
)


-Net cash provided by financing activities


299,342



719,541Net increase in cash and cash equivalents


192,678



565,608Cash and cash equivalents at beginning of period


249,802



127,176Cash and cash equivalents at end of period

$
442,480


$
692,784Supplemental Disclosure of Cash Flow InformationCash paid during the period for interest

$
6,807


$
4,630Non-cash disclosure – stock issued for consulting services

$
20,000


$
-Non-cash financing activity relating to addition of accrued and unpaid interest into notes payable, related party

$
-


$
1,035,343
 
 The accompanying notes are an integral part of these consolidated financial statements.
    6
   PEGASI ENERGY RESOURCES CORPORATION
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 JUNE 30, 2011 AND 2010
 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.
 
 2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
 a)  Basis of Presentation
 
 The accompanying unaudited interim consolidated financial statements of PERC have been prepared in accordance with accounting principles generally accepted (“GAAP”) in the United States of America and the rules of the Securities and Exchange Commission (the “SEC”), and should be read in conjunction with PERC’s audited consolidated financial statements for the year ended December 31, 2010, and notes thereto, which are included in the Company’s amended annual report on Form 10-K/A filed with the SEC on August 22, 2011.  In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of the Company’s consolidated financial position and the consolidated results of operations for the interim periods presented have been reflected herein.  The consolidated results of operations for interim periods are not necessarily indicative of the results to be expected for the full year.  The notes to consolidated financial statements, which would substantially duplicate the disclosures required in the Company’s 2010 annual consolidated financial statements, have been omitted.
 b)  New Accounting Pronouncements
 
 In January 2010, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.  This standard requires reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy established by SFAS No. 157 (FASB ASC 820).  The guidance is effective for any interim and annual reporting periods that begin after December 15, 2009.  The Company adopted ASU No. 2010-06 in the first quarter of 2010 and the adoption did not have a material impact on the Company’s disclosures.  The standard also requires entities to provide a reconciliation of purchases, sales, issuance, and settlements of anything valued with a Level 3 method.  This guidance is effective for fiscal years beginning after December 15, 2010, and for interim and periods within those fiscal years. The Company adopted the guidance in the first quarter of 2011 and the adoption did not have a material impact on the Company’s disclosures.
 
 In May 2011, the FASB issued additional guidance regarding fair value measurement and disclosure requirements.  The most significant change will require for Level 3 fair value measurements, a disclosure of quantitative information about unobservable inputs used, a description of the valuation processes used, and a qualitative discussion about the sensitivity of the measurements.  The guidance is effective for interim and annual periods beginning on or after December 15, 2011.  The Company does not expect adoption of the additional fair value measurement and disclosure requirements to have a material impact on its financial position or results of operations.


c)  Reclassifications
 
 Certain reclassifications have been made to the comparative consolidated financial statements to conform to the current period’s presentation.
 
 d)  Net Gain (Loss) per Common Share
  Basic net gain (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 gain (loss) per share by application of the if-converted method. Under this method, conversion shall not be assumed for the purposes of computing diluted gain (loss) per share if the effect would be anti-dilutive. For the three months and six months ended June 30, 2011 and June 30, 2010, the diluted gain (loss) per share is the same as basic gain (loss) per share, as the effect of common stock equivalents are anti-dilutive.  For the three months ended June 30, 2011 and June 30, 2010, the Company had potentially dilutive shares of 30,298,411 and 11,546,672, respectively.  For the six months ended June 30, 2011 and June 30, 2010, the Company had potentially dilutive shares of 30,298,411 and 11,546,672, respectively.
 7
 
 PEGASI ENERGY RESOURCES CORPORATION
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 JUNE 30, 2011 AND 2010
 3.  NOTES PAYABLE, RELATED PARTY
 
 Notes payable, related party consisted of the following at:

June 30,

2011


December 31,

2010Note payable to Teton (the “Teton Renewal Note”) in the amount of $6,987,646 dated June 23, 2011, including interest at 8%, with all principal and interest due on the maturity date of June 1, 2015.    Renewed prior amended note which matured June 1, 2011.  Secured by a stock pledge and security agreement.

$
6,987,646


$
6,987,646Original unsecured promissory note payable in the amount of $1 million dated October 14, 2009 to Teton (the “Teton Promissory”).  Additional funds added by amendment two to the note results in funds available of $1.5 million, including interest of 6.25%, with all interest and principal due on the maturity date of June 1, 2015.


1,173,000



1,173,000Total notes payable, related party


8,160,646



8,160,646Less current portion


-



(8,160,646)Total long-term notes payable, related party

$
8,160,646


$
-
 
 On June 1, 2010, a Promissory (Teton Renewal Note) note was executed to renew and extend the original note payable (Teton Note) which matured May 21, 2010.  The renewal note’s principal balance of $6,987,646 is the total of the outstanding principal of $5,952,303 and accrued and unpaid interest of $1,035,343 on the original note.  Interest payments were due on the note on October 1, 2010; January 12, 2011; and April 1, 2011. Effective October 1, 2010 an amendment to the Teton Renewal Note was executed to eliminate the October 1, 2010 interest payment.  Effective January 2, 2011, a second amendment was executed which eliminated the January 1, 2011 interest payment.  The final maturity date of the Teton Renewal Note was unchanged and remained June 1, 2011.  Teton has the right, but not the obligation to convert all or a portion of the indebtedness at any time after May 1, 2008, unless the debt is repaid before such date.  This option will continue in existence as long as any balance remains outstanding on the note.
 
 On April 1, 2011, a third amendment was executed which eliminated the April 1, 2011 interest payment and extended the maturity date of the note from June 1, 2011 to June 1, 2013 at which time all outstanding principal and accrued and unpaid interest of the note will be due.  The amendment also added an event of default whereby Teton may declare default on the note if the Company does not raise funds during or as a result of their engagement with a placement agent whom they initially engaged on March 25, 2011.  No default was declared on this note prior to its subsequent amendment below.
 
 On June 23, 2011, a fourth amendment was executed which extended the maturity date of the note from June 1, 2013 to June 1, 2015, at which time all outstanding principal and accrued and unpaid interest of the note will be due.  The event of default section remained the same as in the third amendment.
 
 The Teton Promissory note was amended effective January 1, 2010 to eliminate the requirement of interest payments to be made on January 1, 2010; April 1, 2010; and October 1, 2010.  A second amendment was executed which increased the available balance to $1,500,000 effective March 2, 2010.  Effective July 1, 2010, a third amendment to the Teton Promissory was executed to eliminate the interest payment required on July 1, 2010 and to extend the maturity date of the note to January 2, 2011. Effective January 2, 2011, a fourth amendment was executed to extend the maturity date of the note from January 2, 2011, to April 2, 2011 at which time all outstanding principal and accrued  and unpaid interest will be due.
    8
  PEGASI ENERGY RESOURCES CORPORATION
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 JUNE 30, 2011 AND 2010
 On April 2, 2011, a fifth amendment was executed which eliminated the April 2, 2011 interest payment and extended the maturity of the note from April 2, 2011 to June 1, 2013 at which time all outstanding principal and accrued and unpaid interest of the note will be due.  The amendment also added an event of default whereby Teton may declare default on the note if the Company does not raise funds during or as a result of their engagement with a placement agent whom they initially engaged on March 25, 2011.   In addition, the amendment granted Teton the right, to convert the outstanding balance on the Promissory note into shares of PERC’s common stock at a fixed conversion price of $0.60 per share.
 
 On June 23, 2011, a sixth amendment was executed which extended the maturity date of the note from June 1, 2013 to June 1, 2015, at which time all outstanding principal and accrued and unpaid interest of the note will be due.  The event of default section and conversion of debt to equity section remained the same as in the fifth amendment.
 
 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 to its execution, and a fixed conversion price of $1.60 was agreed upon for conversion of the additional funds.
 
 In May 2009, the third and fourth amendments to the Teton Note were executed.  The third amendment deferred the May 21, 2009 interest payment to September 21, 2009 and the fourth amendment added $350,000 of additional funds to the outstanding balance of the Teton Note.  In September 2009, the fifth amendment was executed, which added $175,000 of additional funds to the outstanding balance of the Teton Note and deferred the interest payment due date from September 21, 2009 to October 21, 2009.  In February 2010, the seventh amendment to the Teton Note, dated May 21, 2007, was executed.  This amendment amended the sixth amendment, executed in October 2009, to defer the October 21, 2009 interest payment to February 21, 2010.  The seventh amendment eliminated the February 21, 2010 interest payment.  The final maturity date of the Teton Note was unchanged and remained May 21, 2010.  Upon maturity, the outstanding principal and accrued and unpaid interest on this note was renewed and extended to a maturity date of June 1, 2011.  See the Teton Renewal Note above.  The maturity date was subsequently extended to June 1, 2015.
  4.  SEGMENT INFORMATION
 
 The following information is presented in accordance with FASB ASC Topic 280, Segment Reporting.  The Company is engaged in oil and gas exploration and production, saltwater disposal and pipeline transportation.  PERC is engaged in the exploration and production of natural gas and oil.  Pegasi Operating, Inc. (“POI”), a wholly-owned subsidiary of PERC, conducts the exploration and production operations.  TR Rodessa, Inc. 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 assets of this company were sold effective July 1, 2011 and we have reported it as a discontinued operation (see Footnote 9).  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 as of June 30, 2011 and December 31, 2010 and for the three and six months ended June 30, 2011 and 2010.
  Three Months Ended

June 30, 2011


Three Months Ended

June 30, 2010


Six Months

Ended

June 30, 2011


Six Months

Ended

June 30, 2010Business segment revenue:Oil and gas

$
234,468


$
127,603


$
435,634


$
305,319Condensate and skim oil


12,472



17,725



21,171



24,363Transportation and gathering


53,242



64,232



200,699



131,620Total revenues

$
300,182


$
209,560


$
657,504


$
461,302
    9
 PEGASI ENERGY RESOURCES CORPORATION
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 JUNE 30, 2011 AND 2010
  Three Months Ended

June 30, 2011


Three Months Ended

June 30, 2010


Six Months

Ended

June 30, 2011


Six Months

Ended

June 30, 2010Business segment profit (loss):Oil and gas

$
(15,663
)

$
(20,249
)

$
(111,150
)

$
(4,616
)Condensate and skim oil


12,472



17,725



21,171



24,363Transportation and gathering


(1,487
)


(22,766
)


(5,684
)


(42,676
)General corporate


(386,780
)


(390,199
)


(823,118
)


(839,805
)Loss from operations

$
(391,458
)

$
(415,489
)

$
(918,781
)

$
(862,734
)Depreciation and depletion:Oil and gas

$
52,512


$
21,768


$
98,122


$
47,708Transportation and gathering


13,753



7,491



25,552



14,983Assets held for sale


-



19,821



-



39,643General corporate


4,477



7,764



8,781



15,527Total depletion and depreciation

$
70,742


$
56,844


$
132,455


$
117,861
 
 Six Months Ended

June 30, 2011


Six Months Ended

June 30, 2010Capital expenditures:Oil and gas

$
258,964


$
48,327Transportation and gathering


-



300Assets held for sale


-



84,921General corporate


-



-Total capital expenditures

$
258,964


$
133,548June 30, 2011


December 31, 2010Business segment assets:Oil and gas

$
21,072,367


$
20,538,826Transportation and gathering


621,367



712,561Assets held for sale


300,347



300,347General corporate


1,046,958



1,428,267Total assets

$
23,041,039


$
22,980,001
 
 5.  FAIR VALUE OF FINANCIAL INSTRUMENTS
 
 ASC Topic 825 requires certain disclosures regarding the fair value of financial instruments.  Fair value of financial instruments is made at a specific point in time, based on relevant information about financial markets and specific financial instruments.  As these estimates are subjective in nature, involving uncertainties and matters of significant judgment, they cannot be determined with precision. Changes in assumptions can significantly affect estimated fair values.
  ASC Topic 820 defines fair value as the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  When determining the fair value measurements for assets and liabilities required or permitted to be recorded at fair value, the Company considers the principal or most advantageous market in which it would transact and it considers assumptions that market participants would use when pricing the asset or liability.
  ASC Topic 820 establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.  A financial instrument’s categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  ASC Topic 820 establishes three levels of inputs that may be used to measure fair value:
  10
  PEGASI ENERGY RESOURCES CORPORATION
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 JUNE 30, 2011 AND 2010
 Level 1 - Level 1 applies to assets or liabilities for which there are quoted prices in active markets for identical assets or liabilities.
  Level 2 - Level 2 applies to assets or liabilities for which there are inputs other than quoted prices included within Level 1 that are observable for the asset or liability such as quoted prices for similar assets or liabilities in active markets; quoted prices for identical assets or liabilities in markets with insufficient volume or infrequent transactions (less active markets); or model-derived valuations in which significant inputs are observable or can be derived principally from, or corroborated by, observable market data.
  Level 3 - Level 3 applies to assets or liabilities for which there are unobservable inputs to the valuation methodology that are significant to the measurement of the fair value of the assets or liabilities.
  The following table sets forth our estimate of fair value of our financial instruments that are liabilities as of June 30, 2011:
 
 Quoted Prices in Active Markets for Identical Assets


Significant Other Observable Inputs


Significant Unobservable Inputs(Level 1)


(Level 2)


(Level 3)


Total2007 Warrants

$
-


$
2,022,203


$
-


$
2,022,203
  The following table sets forth a summary of changes in fair value of our derivative liability for the six months ended June 30, 2011:
  Balance, December 31, 2010

$
3,638,311Net gain included in earnings


(1,616,108
)Balance, June 30, 2011

$
2,022,203
 
 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.
 
 6.  DERIVATIVE WARRANT LIABILITY
 
 As of June 30, 2011, and December 31, 2010, the Company had derivative warrant liabilities of $2,022,203 and $3,638,311, respectively.
 
 The Company used the Black-Scholes valuation model to estimate the fair value of the derivative warrant liability.  Significant assumptions used at June 30, 2011 were as follows:
  Market value of stock on reporting date (1)

$
0.40Risk-free interest rate (2)


0.31
%Dividend yield (3)


0.00
%Volatility factor


134.81
%Expected life (4)

1.5 years
  (1)
The market value of the stock on the date of reporting was based reported public market prices.
 (2)
The risk-free interest rate was determined by management using the U.S. Treasury zero-coupon yield over the contractual term of the warrant on June 30, 2011.
 (3)
Management determined the dividend yield to be 0% based upon its expectation that there will not be earnings available to pay dividends in the near term.
 (4)
Expected life is remaining contractual life of the warrants.
 
  11
   PEGASI ENERGY RESOURCES CORPORATION
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 JUNE 30, 2011 AND 2010
 Under ASC 815, the fair value of the warrants is recorded as a derivative liability.  Each reporting period, the derivative liability is fair valued with the non-cash gain or loss recorded in the period as Other Income/Expense.  Since the exercise price of the Warrants can be potentially decreased and the number of shares to settle the Warrants increased each time a trigger event occurs that results in a new adjusted exercise price below the adjusted exercise price then in effect, there could be a potentially infinite number of shares required to settle the warrant agreement.  However, the Company has the capability of limiting the occurrence of such events.
 
 7.  WARRANTS OUTSTANDING
 
 In December 2007, the Company issued warrants to placement agents to purchase 837,850 shares of common stock, of which 346,850 could be exercised cashless and 491,000 exercised at a price of $1.60 per share until December 31, 2012, as part of a securities purchase offering.  On January 24, 2008, the Company issued an additional 9,615 warrants to a placement agent under the same terms as the original warrants.  Also in December 2007, the Company issued 8,375,784 warrants to purchase 4,187,901 shares of common stock exercisable until December 31, 2012 in connection with a securities purchase agreement.  The warrants had an exercise price of $1.60 per share.
 
 The 2007 Warrant Agreement contains anti-dilution protection rights (“ratchet provision”) which require an adjustment to the exercise price of the warrants and a proportional adjustment to the number of shares of common stock issuable upon exercise of the warrants in the event the Company issues common stock, stock options, or securities convertible into or exercisable for common stock, at a price per share lower than such exercise price.  On December 24, 2010, the Company issued non-excluded stock options to a third party with an exercise price of $0.42 which was below the original exercise of $1.60 contained in the agreement which triggered the ratchet provision.  The effect of the anti-dilution provision resulted in an adjustment to the number of shares of common stock issuable upon exercise of the warrants from 5,035,367 shares with an exercise price of $1.60 per share to 19,182,350 shares with an exercise price of $0.42 per share.  On March 1, 2011, the Company issued common shares at the then current market value of $0.40 to a consultant for the fair value of services rendered which also triggered the ratchet provision.  The effect of the anti-dilution provision resulted in an adjustment to the number of shares of common stock issuable upon exercise of the warrants from 19,182,350 shares with an exercise price of $0.42 per share to 20,141,468 with an exercise price of $0.40 per share during the quarter ended March 31, 2011.  There were no anti-dilution events during the quarter ended June 30, 2011.
 
 A summary of warrant activity and shares issuable upon exercise of the warrants during the quarter ended June 30, 2011 is as follows:
 
 Warrants

Shares Issuable Under Warrants

Weighted Average Exercise PriceOutstanding at March 31, 2011


9,223,249

20,141,468

$
0.40Warrants issued


-

-


-Warrants exercised


-

-


-Outstanding at June 30, 2011


9,223,249

20,141,468

$
0.40
 
 No warrants were issued during the quarter ended June 30, 2011.
  8.  RESTRICTED CASH – LEASING PROGRAM
 
 Leasing Program
 
 During the first quarter of 2010, the Company executed agreements with two independent oil and gas companies regarding leasing specific areas on the Cornerstone Project.  The agreements include both extensions and renewals of existing leaseholds that the Company currently holds and acquisitions of new leaseholds in order to expand the Company’s acreage position.  Funds received from these companies are restricted to the leasing programs and are considered released when they are spent in accordance with the agreements.  Total funds of $5,438,000 were received on these programs, $5,217,941 was spent on leasing activities and $199,768 was refunded leaving a balance of $20,291 in restricted cash and lease program deposits at June 30, 2011.
    12
  PEGASI ENERGY RESOURCES CORPORATION
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 JUNE 30, 2011 AND 2010
 Drilling Program
 
 During the last quarter of 2010, the Company executed participation and operating agreements with various independent oil and gas companies regarding the drilling of the Norbord and Swamp Fox wells.   Funds received from these companies are restricted to the drilling programs and are considered released when they are spent in accordance with the agreements.  Total funds of $2,249,980 were received on these programs and $1,528,942 was spent on drilling activities leaving a balance of $721,038 in restricted cash and drilling prepayments at June 30, 2011.
  9.  DISCONTINUED OPERATIONS
 
 The Company’s wholly-owned subsidiary, 59 Disposal Inc., operates a saltwater disposal facility which disposes saltwater and flow-back waste into subsurface storage.  The disposal activities have diminished over the past twelve months and in January 2011, the Company offered for sale certain assets of the subsidiary.  It held a letter of intent from a potential buyer for the purchase of certain of 59 Disposal’s assets which was valid for thirty days after its signing on March 1, 2011.   Although the letter of intent expired, negotiations continued with the potential purchaser and the sale was closed effective July 1, 2011 at a gross sale price of $1.3 million of which the Company’s portion is $1.04 million.
 
 At June 30, 2011, assets of 59 Disposal to be included in the sale have a net book value of $300,347 and have been included in the consolidated balance sheets as assets held for sale.  The Company’s portion of the negotiated sales price was their 80% interest which amounted to $1.04 million.  Since the proceeds from the sale were more than the net book value of the equipment no impairment has been recorded.  Current assets and liabilities of 59 Disposal, including accounts receivable of $75,648, accounts payable of $68,816, related party payables of $123,290, interest payable of $2,015 and notes payable, related party, of $23,244 as of June 30, 2011, will be retained by the Company under the negotiated sale provisions.
 
 The following schedule details 59 Disposal’s property and equipment to be included in the sale as of June 30, 2011:
 
 Cost


Accumulated

Depreciation


June 30, 2011

Net Book ValueLease & well equipment

$
597,740


$
318,916


$
278,824Buildings


19,916



2,353



17,563Office furniture & equipment


6,550



2,590



3,960$
624,206


$
323,859


$
300,347
 
 As a result of the discontinued operations accounting treatment, the Consolidated Statement of Operations reflects 59 Disposal as a discontinued operation for all periods presented. Following is summarized information regarding the discontinued operations:
 Revenues of discontinued operations amounted to $92,172 and $45,709 for the three months ended June 30, 2011 and 2010.
  Three Months EndedJune 30,


June 30,2011


2010Income (loss) from discontinued operations

$
31,712


$
(15,295
)Income tax expense – discontinued operations


(11,092
)


-Income (loss) from discounted operations, net of tax

$
20,620


$
(15,295
)
 
 
 
 13
 
 
 PEGASI ENERGY RESOURCES CORPORATION
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 JUNE 30, 2011 AND 2010
 
 Revenues of discontinued operations amounted to $174,822 and $82,213 for the six months ended June 30, 2011 and 2010.
  Six Months EndedJune 30,


June 30,2011


2010Income (loss) from discontinued operations

$
60,165


$
(106,174
)Income tax expense – discontinued operations


(21,051
)


-Income (loss) from discounted operations, net of tax

$
39,114


$
(106,174
)
 
 10. COMMITMENTS AND CONTINGENCIES
 
 Along with the Company's counsel, management monitors developments related to legal matters and, when appropriate, makes adjustments to record liabilities to reflect current facts and circumstances.  Management has recorded a liability related to its registration rights agreement with investors that provides for the filing of a registration statement for the registration of the shares issued in the offering in December 2007, as well as the shares issuable upon exercise of related warrants.  The Company failed to meet the deadline for the effectiveness of the registration statement and therefore was required to pay liquidated damages of approximately $100,000 on the first day of effectiveness failure, or July 18, 2008.  An additional $100,000 penalty was required to be paid by the Company every thirty days thereafter, prorated for periods totaling less than thirty days, until the effectiveness failure was cured, up to a maximum of 18% of the aggregate purchase price, or approximately $1,800,000.  The Company’s registration became effective on August 21, 2008.  At June 30, 2011, management reevaluated the status of the registration statement and determined an accrual of $189,972 was sufficient to cover any potential payments for liquidated damages.  The damages are reflected as liquidated damages payable of $189,972 and $173,802 in the accompanying consolidated balance sheets as of June 30, 2011 and December 31, 2010, respectively.
 
 11.  SUBSEQUENT EVENTS
 
 On July 1, 2011, the Company sold certain assets of their subsidiary, 59 Disposal, Inc. for proceeds of $1.04 million.  See Note 9 – Discontinued Operation for further details.
 On July 28, 2011, the Company sold in a private placement a total of 5,388,900 Units (the “Units”), each Unit consisting of two shares of common stock for a total of 10,777,800 shares, $0.001 par value and a three-year warrant to purchase one share of common stock at an exercise price of $0.60 per share, for an aggregate purchase price of $5,388,900.  From the proceeds received $5.0 million has been placed into a reserve bank account to be used in drilling horizontal wells.  The remaining gross proceeds, less offering expenses, will be used for working capital purposes.
 
 In connection with the private placement transaction, the Company engaged various placement/selling agents.  Such agents were paid $56,605 cash and issued 964,570 three-year warrants to acquire common stock at an exercise price of $0.60 per share.  In addition, the Company paid $29,000 in legal and escrow fees on the financing.
 
 The Company is currently in negotiations to sell a portion of a pipeline they own.  Negotiations are continuing with the potential purchaser with an anticipated closing of the sale in 2011.  Current plans are to use the proceeds to refurbish a pipeline near the Norbord well which is expected to potentially double production from that well.
   14
  
 Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
 Forward Looking Statements
 
 This Management's Discussion and Analysis of Financial Condition and Results of Operations includes a number of forward-looking statements that reflect management's current views with respect to future events and financial performance. You can identify these statements by forward-looking words such as “may,” “will,” “expect,” “anticipate,” “believe,” “estimate” and “continue,” or similar words.  Those statements include statements regarding the intent, belief or current expectations of us and members of our management team as well as the assumptions on which such statements are based. Prospective investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve risk and uncertainties, and that actual results may differ materially from those contemplated by such forward-looking statements.
 
 Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC.  The following Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Company should be read in conjunction with the Consolidated Financial Statements and notes related thereto included in this Quarterly Report on Form 10-Q. Important  factors not  currently  known  to management  could  cause  actual  results  to differ  materially  from  those in forward-looking  statements.  We undertake no obligation to update or revise forward-looking statements to reflect changed assumptions, the occurrence of unanticipated events or changes in the future operating results over time. We believe that our assumptions are based upon reasonable data derived from and known about our business and operations.  No assurances are made that actual results of operations or the results of our future activities will not differ materially from our assumptions.  Factors that could cause differences include, but are not limited to, expected market demand for our products, fluctuations in pricing for materials, and competition.
 
 Company Overview
 
 We are an independent energy company engaged in the exploration and production of natural gas and oil through the development of a repeatable, low-geological risk, high-potential project in the active East Texas oil and gas region.  We currently hold interests in properties located in Marion and Cass County, Texas, home to the Rodessa oil field.  The field has historically been the domain of small independent operators and is not a legacy field for any major oil company.
 
 Our business strategy, which we designated as the “Cornerstone Project”, is to identify and exploit resources in and adjacent to existing or indicated producing areas within the Rodessa field area. We intend to develop and produce reserves at a low cost and will take an aggressive approach to exploiting our contiguous acreage position through utilization of “best in class” drilling, (i.e. using the latest drilling techniques available and seismic technology).  We believe that we are uniquely familiar with the history and geology of the Cornerstone Project area based on our collective experience in the region as well as through our ownership of a large proprietary database which details the drilling history of the Cornerstone Project area since 1980.  We believe implementing our drilling strategy and using new drilling and completion techniques will enable us to find significant gas and oil reserves in the Cornerstone Project area.
 
 We conduct our main exploration and production operations through our wholly-owned subsidiary, POI.  We conduct additional operations through another wholly-owned subsidiary, TR Rodessa.
 
 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.
 
 Effective July 1, 2011, the assets of our wholly-owned subsidiary, 59 Disposal, were sold for a total of $1.3 million, of which we received $1,037,000.  59 Disposal owned an 80% undivided interest in a saltwater disposal facility which disposes saltwater and flow-back waste into subsurface storage.  These funds are being allocated to general expenses.  Our recent emphasis on drilling horizontal oil prospects which historically do not have as much associated water to dispose together with diminished disposal activities over the past twelve months were factors in the decision to sell of the assets of 59 Disposal.
  15
 
 Plan of Operations
 
 We intend to continue to use our competitive strengths to advance our corporate strategy.  The following are key elements of that strategy:
 
 ·
Develop the Cornerstone Project in East Texas through a lease renewal and lease acquisition program along with a drilling program.We will focus our near-term efforts on our leasing program and development drilling on existing acreage.  We expect this drilling program to increase our proved reserve and cash flow profile. In late 2010, we completed drilling the Norbord #1 well to 7,005 feet in the Travis Peak formation.  The deliverability rate is estimated at 3,381 MCF (a thousand cubic feet) per day and 55.2 BBLSPD (barrels per day).  Based on the success of this well, we will begin a developmental drilling program in late 2011. We have a gross working interest of 25% in the well as we have been carried for the cost of the well.



The Swamp Fox #1 test well was drilled to a total depth of 7,000 foot and has been completed at 6,500 feet in a Cretaceous aged reservoir.  After a specialized fracture treatment, the well swab tested 82 bbls of 35.1 degree API gravity oil and 118 bbls of associated saltwater.  Testing on the well continues.  We have a 28% working interest in the well.



We received $5.0 million from a private placement that closed on July 28, 2011 which is to be used for the drilling of horizontal wells.  We expect to commence drilling of the first horizontal well on existing acreage within the next quarter.·
Apply management expertise in the Cornerstone Project area and recent developments in drilling and completion technology to identify new drilling opportunities and enhance production.We plan to maximize the present value of our vertical wells by utilizing a shotgun dual or sawtooth production technique. We will also implement the latest drilling, fracturing, and completion techniques, including shotgun duals, to develop our properties as well as horizontal drilling.  These horizontal wells will primarily target the Bossier formation and we anticipate these wells will yield significantly higher hydrocarbon flow rates than our vertical wells.  We plan to begin our horizontal drilling programs in the second half of 2011.·
Continue to lease underdeveloped acreage in the Cornerstone Project area.We are continuing our leasing program to support our present and future drilling plans with funding up to $8.7 million budgeted with our two partners. The partners pay 100% of the cost for a 50% interest.  In the event that our partners does not pay their portion of expenses in connection with drilling wells, they will forfeit their working interest in the well to us.  If that occurs, we will either need to pay all the expenses in connection with the well or sell a portion of our working interest to another partner.  The program includes renewing existing leasehold and acquiring new leaseholds. We are using our extensive proprietary database to help optimize additional drilling locations and to acquire additional acreage.  We intend to target acreage with exploitation and technology upside within the Cornerstone Projectarea.  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 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.  On July 28, 2011, we closed a private placement for a total of 5,388,900 Units for an aggregate purchase price of $5,388,900, each unit consisting of two shares of common stock and a three-year warrant to purchase one share of common stock at an exercise price of $0.60 per share.  We currently do not have any contracts or commitments for funding and there are no guarantees that we will be able to raise additional funds on terms acceptable to us, if at all.  We may also consider farm-out agreements, whereby we would lease parts of our properties to other operators for drilling purposes and we would receive payment based on the production.  We anticipate the cost of a horizontal oil well will be approximately $5 million and a vertical shallow gas well to be approximately $1 million.
 
 Our oil and gas assets are located in Cass and Marion counties in northeast Texas.  As of June 30, 2011, we operated 11 wells.
 16
  As of July 1, 2011, our leasehold position is approximately 25,362 gross acres and 16,359 net acres, of which our net acres are approximately 9,280.  Our leasing program consists of renewing expiring leases and leasing previously unleased acreage. We entered leasing agreements with two independent oil and gas companies during the first quarter of 2010 regarding leasing specific areas on the Cornerstone Project which could potentially result in up to $4,000,000 and $4,700,000, respectively, in lease acquisitions. We spent approximately $5.2 million of the funds in the leasing program which is basically complete at this time.  The program included 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 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.  We also finalized drilling agreements with various independent oil and gas companies in 2010 that provided approximately $1.5 million in funds towards the drilling of the Norbord and Swamp Fox wells.
 
 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.  If sufficient funds are raised, they 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.
 
 Results of Operations
 
 Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010.
 
 Summarized Results of Operations
 
 2011


2010


Increase (Decrease)Total revenues

$
300,182


$
209,560



90,622Total operating expenses


691,640



625,049



66,591Loss from operations


(391,458
)


(415,489
)


(24,031
)Total other income (expenses)


2,328,312



(147,867
)


2,476,179Income (loss) from continuing operations before income tax benefit


1,936,854



(563,356
)


2,500,210Income tax benefit


11,092



-



11,092Income (loss) from continuing operations


1,947,946



(563,356
)


2,511,302Income (loss) from discontinued operations, net of tax expense


20,620



(15,295
)


35,915Net income (loss)

$
1,968,566


$
(578,651
)


2,547,217
  Revenues:  Total revenues for the three months ended June 30, 2011 totaled $300,182, compared to $209,560 for the three months ended June 30, 2010.  Oil and gas revenue for the three months ended June 30, 2011 was $234,468 compared to $127,603 for the three months ended June 30, 2010.  Oil prices increased for the three months ended June 30, 2011 compared to the three months ended June 30, 2010, and our oil production increased, resulting in a $36,020 increase in oil revenue.  Also there was an increase in gas production from the Norbord well which began production in December 2010.  Gas prices increased from the three months ended June 30, 2010 to the three months ended June 30, 2011, this increase, along with the increase in production from the Norbord well, resulted in an overall $70,845 increase in gas revenues. Condensate and skim oil for the three months ended June 30, 2011 was $12,472 compared to $17,725 for the three months ended June 30, 2010.  Transportation and gathering for the three months ended June 30, 2011 was $53,242 compared to $64,232 for the three months ended June 30, 2010.
  17
  Expenses:  Total operating expenses for the three months ended June 30, 2011 were $691,640, compared to $625,049 for the three months ended June 30, 2010, resulting in a total increase of $66,591.  This increase is comprised of an increase in lease operating expenses, depletion and depreciation, and general and administrative expenses, which was offset by a decrease in cost of gas purchased for resale for the three months ended June 30, 2011.
  Lease Operating Expenses:Total lease operating expenses for the three months ended June 30, 2011 were $108,468 compared to $75,242 for the three months ended June 30, 2010 which resulted in an increase of $33,226.  The primarily reason for the increase was the Norbord well starting production in December 2010, which resulted in lease operating expenses for the Norbord well during the three months ended June 30, 2011 compared to none in the three months ended June 30, 2010.
 
 Depletion and Depreciation:  The $33,719 increase in depletion and depreciation to $70,742 for the three months ended June 30, 2011 from $37,023 for the six months ended June 30, 2010 was primarily due to a decrease in the reserves amount used in the depletion calculation.  The 2010 reserve report showed the reserves at approximately 5.4 million compared to 2.9 million in 2011.  This decrease in the reserves caused the percentage of depletion taken to increase, which in turn increased depletion expense.
  General and Administrative Expense:  The $29,630 increase in general and administrative expense to $474,795 for the three months ended June 30, 2011 from $445,165 for the three months ended June 30, 2010 was primarily due to an increase in accounting.  The increase in accounting fees was due to issues in obtaining required reports in a timely manner for the 10-K.
 
 Cost of Gas Purchased for Resale:For the three months ended June 30, 2011, we had no cost of gas purchased for resale compared to $39,437 for the three months ended June 30, 2010, which resulted in a decrease of $39,437.  In February 2011, a third party operator began collecting the revenue from other companies’ gas that went through our pipelines, which eliminated our need to record cost of gas purchased for resale.
 
 Other Income (Expenses):Total other income for the three months ended June 30, 2011 was $2,328,312, compared to $147,867 of other expenses for the three months ended June 30, 2010 resulting in an increase of $2,476,179.  The primary reason for this increase was due to a $2,497,311 non-cash gain resulting from the change in fair value of our warrant derivative liability. This change was caused by a decrease in the stock price between March 31, 2011 and June 31, 2011, which resulted in a non-cash gain from the decrease in the fair value of the stock. The remaining change was due to the addition of the accrued and unpaid interest on the Teton note being added to the principal balance of the Teton Renewal Note on June 1, 2010, which resulted in higher interest expense.
 
 Income (Loss) from Discontinued Operations:  The gain from discontinued operations for the three months ended June 30, 2011 was $20,620, compared to a loss of $15,295 for the three months ended June 30, 2010.  This $35,915 increase was due to an increase in disposal activity.  In the second quarter of 2011, disposal activity increased to the point that the well was running twenty-four hours a day.
 
 Net Income (Loss):As a result of the above described revenues and expenses, we had net income of $1,968,566 for the three months ended June 30, 2011 as compared to a net loss of $578,651 for the three months ended June 30, 2010.
 
 Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010.
 
 Summarized Results of Operations
 
 2011


2010


Increase (Decrease)Total revenues

$
657,504


$
461,302



196,202Total operating expenses


1,576,285



1,324,036



252,249Loss from operations


(918,781
)


(862,734
)


56,047Total other income (expenses)


1,283,152



(292,621
)


1,575,773Income (loss) from continuing operations before income tax benefit


364,371



(1,155,355
)


1,519,726Income tax benefit


21,051



-



21,051Income (loss) from continuing operations


385,422



(1,155,355
)


1,540,777Income (loss) from discontinued operations, net of tax expense


39,114



(106,174
)


145,288Net income (loss)

$
424,536


$
(1,261,529
)


1,686,065
 
 Revenues:  Total revenues for the six months ended June 30, 2011 totaled $657,504, compared to $461,302 for the six months ended June 30, 2010.  Oil and gas revenue for the six months ended June 30, 2011 was $435,634 compared to $305,319 for the six months ended June 30, 2010, resulting in an increase of $130,315. Oil prices increased for the six months ended June 30, 2011 compared to the six months ended June 30, 2010, and our oil production increased, resulting in a $25,901 increase in oil revenue.  Also there was an increase in gas production from the Norbord well, which began production in December 2010.  The increase in production from the Norbord well resulted in a $104,414 increase in gas revenues.  Transportation and gathering revenue increased $69,079 to $200,699 for the six months ended June 30, 2011 compared to $131,620 for the six months ended June 30, 2010.  The increase was mainly due to the Norbord gas being carried on the pipeline beginning in December 2010.
  18
 
 Expenses:  Total operating expenses for the six months ended June 30, 2011 were $1,576,285, compared to $1,324,036 for the six months ended June 30, 2010, resulting in a total increase of $252,249.  This increase is comprised of an increase in lease operating expenses, depletion and depreciation, and general and administrative expenses.
 
 Lease Operating Expenses:Total lease operating expenses for the six months ended June 30, 2011 were $209,968 compared to $151,503 for the six months ended June 30, 2010, which resulted in an increase of $58,465.  The primary reason for the increase was the Norbord well starting production in December 2010, which resulted in lease operating expenses for the Norbord well during the six months ended June 30, 2011 compared to none in the six months ended June 30, 2010.
 
 Depletion and Depreciation:  The $54,237 increase in depletion and depreciation to $132,455 for the six months ended June 30, 2011 from $78,218 for the six months ended June 30, 2010 was primarily due to a decrease in the reserves amount used in the depletion calculation.  The 2010 reserve report showed the reserves at approximately 5.4 million compared to 2.9 million in 2011.  This decrease in the reserves caused the percentage of depletion taken to increase and in turn increased depletion expense.
 
 General and Administrative Expense:  The $101,902 increase in general and administrative expense to $1,062,381 for the six months ended June 30, 2011 from $960,479 for the six months ended June 30, 2010 was primarily due to an increase in accounting and consulting fees.  The increase in accounting fees was due to issues in obtaining required reports in a timely manner for the 10-K.  The increase in consulting fees is related to fees paid with the issuance of shares of stock.
 
 Other Income (Expenses):Total other income for the six months ended June 30, 2011 was $1,283,152 compared to $292,621 of other expenses for the six months ended June 30, 2010 resulting in an increase of $1,575,773.  The primary reason for this increase was due to a $1,616,108 non-cash gain resulting from the change in fair value of our warrant derivative liability.  This change was caused by a decrease in the stock price between December 31, 2010 and June 30, 2011, which resulted in a non-cash gain from the decrease in the fair value of the stock. The remaining change was due to the addition of the accrued and unpaid interest on the Teton note being added to the principal balance of the Teton Renewal Note on June 1, 2010 which resulted in higher interest expense.
 
 Net Income(Loss):As a result of the above described revenues and expenses, we had net income of $424,536 in the six months ended June 30, 2011 as compared to a net loss of $1,261,529 in the six months ended June 30, 2010.
 Liquidity and Capital Resources
 
 We held $442,480 in cash at June 30, 2011, made up of a majority of our cash accounts.  However, at June 30, 2011, several cash accounts had an overdraft which totaled $660,432, resulting in a net overdraft of $217,952.  We also had a cash overdraft of $340,118 at December 31, 2010.  The increase in the cash overdraft is related to purchases of oil and gas properties and using cash to cover operating expenses.  In addition, our trade accounts payable have increased by $428,220, due primarily to the drilling activity on the Norbord #1 and Swamp Fox #1 wells beginning in the last quarter of 2010 and continuing in 2011 and secondarily to accounting fees outstanding on the preparation of the form 10-K for 2010 and the form 10-Q for March 31, 2011.
 Cash Flows
 
 The following table summarizes our cash flows for the six months ended June 30, 2011 and 2010:
 
 Six Months Ended

June 30,2011


2010Total cash provided by (used in):Operating activities

$
147,481


$
(285,564
)Investing activities


(254,145
)


131,631Financing activities


299,342



719,541Increase in cash and cash equivalents

$
192,678


$
565,608
  Cash provided by operating activities for the six months ended June 30, 2011 totaled $147,481, compared to $285,564 used in operating activities for the six months ended June 30, 2010.  The increase of $433,045 in cash provided is due to additional cash provided by decreases of $259,546 in accounts receivable and $145,458 in drilling prepayments, and increases in joint interest billing receivables, related parties of $113,050, accounts payable of $296,747, accounts payable related parties of $67,936 and revenue payable of $269,966.
 
 Cash used by investing activities for the six months ended June 30, 2011 was $254,145, compared to cash provided of $131,631 for the six months ended June 30, 2010, resulting in a net change of $385,776. There were no property and plant purchases in the first six months of 2011, however, we spent $85,221 in property and equipment purchases in the first six months of 2010 for the workover done on the Whitfield well. This decrease was partially offset by an increase in lease and well equipment, and intangible drilling and completion costs for work done on the Norbord and Swamp Fox wells.   These costs increased from $48,327 for the first six months of 2010 to $258,964 for the first six months of 2011. In addition, in the first six months of 2010, we received $265,565 of proceeds on the sale of working interests in new wells.  No proceeds were received in 2011.
 19
 
 Cash provided by financing activities for the six months ended June 30, 2011 totaled $299,342, compared to $719,541 for the six months ended June 30, 2010, resulting in a decrease in cash of $420,199.  No advances were received on the related party note payable during the six months ended June 30, 2011; however, we received proceeds of $723,000 on it during the six months ended June 30, 2010.  This decrease in cash received was offset by an increase of $320,314 in our cash overdrafts for the six months ended June 30, 2011.  There were no cash overdrafts at June 30, 2010.
 
 Sources of Liquidity
 
 Our main source of liquidity continues to be from funds generated by production promotion fees and restricted cash received on our leasing and drilling programs as detailed in Footnote 8. Also, during 2010, we received promotion fees which paid for a portion or all of our cost in a proposed drilling well as well as prospect fees associated with the transactions. Any shortfall in revenue to cover costs through the end of June 2011 was covered by delaying payment of accounts payable.  On July 1, 2011 we sold our interest in certain assets of our wholly-owned subsidiary, 59 Disposal, Inc. for proceeds of $1.04 million.  We believe that the proceeds from production, the sale of 59 Disposal assets and working capital proceeds raised through the private placement offering detailed below will be sufficient to finance our operations for the remainder of 2011.  We anticipate that we will need an additional $725,000 of funds to operate for the next twelve months.  However, future acquisitions and future exploration, development, production and marketing activities, as well as administrative requirements (such as salaries, insurance expenses, general overhead expenses, legal compliance costs and accounting expenses) will require a substantial amount of additional capital and cash flow.
 
 We are pursuing sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means.  We have aggressively contacted many potential investors both within the industry as well as institutional investors to secure additional financing.  Additional financing would be used for drilling opportunities and additional lease funding in the near future, along with working capital purposes.
 
 On July 28, 2011, we sold in a private placement a total of 5,388,900 Units (the “Units”), each Unit consisting of two (2) shares of common stock, $0.001 par value (the “Common Stock”) and a three-year warrant to purchase one (1) share of common stock at an exercise price of $0.60 per share (the “Warrants”), for an aggregate purchase price of $5,388,900.
 
 In connection with the private placement transaction, we engaged Beaufort International Associates Limited (“Beaufort”), a UK registered broker-dealer as our placement agent, which engaged Nicquel Limited (“Nicquel”), a company incorporated in the British Virgin Islands, as a selling agent.  As consideration for services provided, we (i) paid Beaufort $56,605.00 and issued Beaufort three-year warrants to acquire 113,210 shares of Common Stock, at an exercise price of $0.60 per share, and (ii) issued Nicquel three-year warrants to acquire 851,360 shares of Common Stock, at an exercise price of $0.60 per share (collectively, the warrants issued to Beaufort and Nicquel are referred to as the “PA Warrants”).
 
 The exercise price of the Warrants and PA Warrants is subject to customary adjustments provisions for stock splits, reverse stock splits, stock dividends and recapitalization.
 
 In connection with the private placement and pursuant to the transaction agreements:
 
 ●
We agreed to file a registration statement covering the shares of common stock issuable upon exercise of the Warrants and the PA Warrants.  We are required to file the registration statement within 60 days following the final closing of the private placement and will use our commercially reasonable best efforts to effect the registration; and
 
 ●
We placed $5,000,000 of the net proceeds from the offering into a reserve bank account, to be used for drilling of horizontal wells, on which Oliver Waldron, our recently appointed director, is a required signatory.  The remaining proceeds are to be used for working capital purposes.
 
 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.
 
 
 20
 
 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 included in our annual report on Form 10-K filed with the SEC on March 31, 2011.  These policies have been consistently applied in all material respects and address such matters as revenue recognition and depreciation methods.  The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the recorded amounts of revenues and expenses during the reporting period.  Actual results could differ from these estimates.
 
 Accounts Receivable
 
 We perform ongoing credit evaluations of our customers’ financial condition and extend credit to virtually all of our customers.  Collateral is generally not required, nor is interest charged on past due balances.  Credit losses to date have not been significant and have been within management’s expectations.  In the event of complete non-performance by our customers, our maximum exposure is the outstanding accounts receivable balance at the date of non-performance.
 
 Property and Equipment
 
 Property and equipment are stated at cost and depreciated using the straight-line method over the estimated useful lives of the assets, which range from five to thirty-nine years.  Expenditures for major renewals and betterments that extend the useful lives are capitalized.  Expenditures for normal maintenance and repairs are expensed as incurred.  Upon the sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts and any gains or losses thereon are recognized in the operating results of the respective period.
 
 Oil and Gas Properties
 
 We use the full-cost method of accounting for our oil and gas producing activities, which are all located in Texas.  Accordingly, all costs associated with the acquisition, exploration, and development of oil and gas reserves, including directly-related overhead costs, are capitalized.
 
 All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the units-of-production method using estimates of proved reserves.  Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs.  If the results of an assessment indicate that the properties are impaired, the amount of the impairment will be added to the capitalized costs to be amortized.
 
 In addition, the capitalized costs are subject to a “ceiling test,” which limits such costs to the aggregate of the “estimated present value,” discounted at a ten percent interest rate, of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties and less the income tax effects related to the properties.
 
 Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the operating results of the respective period.
 
 Derivative Instruments
 
 For derivative instruments that are accounted for as liabilities, the derivative instrument is initially recorded at its fair value and is then re-valued at each reporting date, with changes in fair value recognized in earnings each reporting period. For warrant derivative instruments, the Company uses the Black-Scholes model to value the derivative instruments at inception and subsequent valuation dates. The classification of derivative instruments, including whether such instruments should be recorded as a liability or as equity, is re-assessed at the end of each reporting period, in accordance with FASB ASC Topic 815, Derivatives and Hedging. Derivative instrument liabilities are classified in the balance sheet as current or non-current based on whether or not the net-cash settlement of the derivative instrument could be required within 12 months of the balance sheet date.
   21
 
 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 interests 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 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.
 
 Item 3.   Quantitative and Qualitative Disclosures about Market Risk
 
 Not required under Regulation S-K for “smaller reporting companies.”
 
   22
 
 Item 4.  Controls and Procedures.
 
 (a) Evaluation of disclosure controls and procedures.
 
 Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of June 30, 2011. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.
 
 Based on management’s evaluation, our chief executive officer and chief financial officer concluded that, as a result of the material weaknesses described below, our disclosure controls and procedures are not designed at a reasonable assurance level and are ineffective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure.  The material weaknesses, which relate to internal control over financial reporting, that were identified are:
 
 a)
We did not maintain sufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of GAAP commensurate with our complexity and our financial accounting and reporting requirements. We have limited experience in the areas of financial reporting and disclosure controls and procedures.  Also, we do not have an independent audit committee.  As a result, there is a lack of monitoring of the financial reporting process and there is a reasonable possibility that material misstatements of the consolidated financial statements, including disclosures, will not be prevented or detected on a timely basis.  For example, on August 4, 2011, we became aware that we had failed to recognize a warrant derivative liability with respect to the impact of an anti-dilution provision on our warrants and the subsequent measurement of fair value of the warrant derivative, as required by Accounting Standards Codification 815-40.  As a result, we determined that our consolidated financial statements for the year ended December 31, 2010 filed in the annual report on Form 10-K and our consolidated financial statements as of and for the three month period ended March 31, 2011 filed in the quarterly report on Form 10-Q (collectively, the “Reports”) should not be relied upon and needed to be restated; and
 
 b)
Due to our small size, we do not have a proper segregation of duties in certain areas of our financial reporting process.  The areas where we have a lack of segregation of duties include cash receipts and disbursements, approval of purchases and approval of accounts payable invoices for payment. This control deficiency, which is pervasive in nature, results in a reasonable possibility that material misstatements of the consolidated financial statements will not be prevented or detected on a timely basis.
  We are committed to improving our financial organization. As part of this commitment, in August 2011, we adopted additional controls to strengthen our internal controls over financial reporting as a result of the failure in recognizing the warrant derivative liability issued that resulted in the amendment to our Reports. If the issuance of any securities is contemplated, we will consult with legal counsel and appropriate accounting resources to evaluate the financial statement impact that the issuance of such warrants or other derivative financial instruments may have prior to issuance. Additional measures may be implemented as we evaluate the effectiveness of these efforts.  We cannot assure you that these remediation efforts will be successful or that our internal control over financial reporting will be effective in accomplishing the control objectives.
 
 In addition, we will look to increase our personnel resources and technical accounting expertise within the accounting function to resolve non-routine or complex accounting matters. In addition, when funds are available,  we will take the following action to enhance our internal controls: Hiring additional knowledgeable personnel with technical accounting expertise to further support our current accounting personnel, which management estimates will cost approximately $100,000 per annum.   As our operations are relatively small and we continue to have net cash losses each quarter, we do not anticipate being able to hire additional internal personnel until such time as our operations are profitable on a cash basis or until our operations are large enough to justify the hiring of additional accounting personnel.  We currently engage an outside accounting firm to assist us in the preparation of our consolidated financial statements and anticipate doing so until we have a sufficient number of internal accounting personnel to achieve compliance.  As necessary, we will engage consultants in the future in order to ensure proper accounting for our consolidated financial statements.
  23
  Management believes that hiring additional knowledgeable personnel with technical accounting expertise will remedy the following material weakness: insufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of GAAP commensurate with our complexity and our financial accounting and reporting requirements.
 
 Management believes that the hiring of additional personnel who have the technical expertise and knowledge with the non-routine or technical issues we have encountered in the past will result in both proper recording of these transactions and a much more knowledgeable finance department as a whole. Due to the fact that our internal accounting staff consists solely of a Chief Financial Officer, additional personnel will also ensure the proper segregation of duties and provide more checks and balances within the department. Additional personnel will also provide the cross training needed to support us if personnel turn over issues within the department occur. We believe this will greatly decrease any control and procedure issues we may encounter in the future.
  (b) Changes in internal control over financial reporting.
 
 We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes. There were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
  24
 
 PART II - OTHER INFORMATION
 
 Item 1. 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 1A. Risk Factors.
 
 Not required under Regulation S-K for “smaller reporting companies.”
 
 Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
 
 None.
 
 Item 3. Defaults Upon Senior Securities.
 
 None
 
 Item 4. (Removed and Reserved)
  Item 5. Other Information.
 
 (a) Form 8-K Information
 
 Effective July 1, 2011, the assets of our wholly-owned subsidiary, 59 Disposal, were sold to Trinity Disposal & Trucking LLC for a total of $1.3 million, of which we received $1,037,000.  59 Disposal owned an 80% undivided interest in a saltwater disposal facility which disposes saltwater and flow-back waste into subsurface storage.
 
 (b) Director Nomination Procedures
 
 We do not have a standing nominating committee nor are we required to have one. We do not have any established procedures by which security holders may recommend nominees to our Board of Directors, however, any suggestions on directors, and discussions of board nominees in general, is handled by the entire Board of Directors.
 
 Item 6. Exhibits.
 10.01
Form of Fourth Amendment to Promissory Note, effective as of June 23, 2011, by and among Pegasi Energy Resources Corporation, Pegasi Operating Inc., TR Rodessa, Inc., 59 Disposal, Inc. and Teton, Ltd.
 
 10.02
Form of Sixth Amendment to Promissory Note, effective as of June 23, 2011, by and among Pegasi Energy Resources Corporation, Pegasi Operating Inc., TR Rodessa, Inc., 59 Disposal, Inc. and Teton, Ltd.
 
 10.03
Form of Asset Purchase Agreement, effective as of July 1, 2011, by and among Trinity Disposal & Trucking LLC, Pegasi Energy Resources Corporation, 59 Disposal, Inc., TR Energy Inc. and Marion Swamp Fox L.P.
 
 31.01
Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 31.02
Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 32.01
Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
   25
 
 SIGNATURES
 
 Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 PEGASI ENERGY RESOURCES CORPORATIONDate:  August 22, 2011
By: /s/ MICHAEL NEUFELDMichael NeufeldChief Executive Officer (Principal Executive Officer)Date:  August 22, 2011
By: /s/ RICHARD LINDERMANISRichard LindermanisChief Financial Officer (Principal Financial Officer and Principal Accounting Officer)