corresp.htm

SICHENZIA ROSS FRIEDMAN FERENCE LLP

61 BROADWAY, NEW YORK NY 10006

TEL 212 930 9700 FAX 212 930 9725 WEB WWW. SRFF.COM

July 9, 2008

BY EDGAR AND

FACSIMILE TRANSMISSION 202-772-9368

Securities and Exchange Commission

100 F Street, N.E.

Washington, D.C. 20549

Attention: Jennifer O’Brien, Esq.

Mail Stop 7010

Re: Pegasi Energy Resources Corporation (the “Company”)

Registration Statement on Form S-1

File No. 333-149241 (the “Registration Statement”)

Dear Ms. O’Brien:

On behalf of the Company, we are hereby enclosing two copies of Amendment No. 2 to the Company’s registration statement on Form S-1 (the “Registration Statement”) that was filed on February 14, 2008.

By letter dated May 23, 2008, the staff of the Securities and Exchange Commission (the “Staff”) issued comments on Amendment No. 1 to the Registration Statement. Following are the Company’s responses to the Staff’s comments. For ease of reference, each response is preceded by the Staff’s comment.

Amendment No. 1 to Registration Statement on Form S-1

Corporate History, page 24

We note from your disclosure that “Marion traded its 30% partnership interest in 59 Disposal, LP for 30% ownership in 59 Disposal’s assets.” Please tell us and expand your disclosure to explain the accounting impact of this transaction, if any. We note your related disclosure within footnote 15 on page F-28. Please advise.

The Company has expanded the related disclosures in accordance with the Staff’s comment. See page 22 of the Registration Statement.

The transaction resulted in an increase in accounts payable, related parties of approximately $258,000 on the Company’s December 31, 2007 consolidated balance sheets and a distribution of Marion’s total partnership capital invested in 59 Disposal, which also approximated $258,000. The distribution is reflected on the Company’s consolidated statement of changes in stockholders’ equity for the year ended December 31, 2007.

Well Economics, page 26

We note from your response to prior comment number 12 that you revised the disclosures to comply with FAS 69. However, we were unable to determine how your revisions included the additional disclosures requested by the prior comment. Therefore, we reissue prior comment number 12 in its entirety. Please expand your disclosure accordingly or otherwise explain to us how you have complied with prior comment number 12.

The Company has expanded the disclosures relating to the well economics section to include the additional disclosures pertaining to how management uses the finding and development costs measure, the limitations of the measure and whether or not the measure is comparable to other like measures disclosed by other companies. See page 24 of the Registration Statement.

Certain Relationships and Related Party Transactions, page 41

We note your disclosure that TR Energy owed you $539,805 for its proportionate share of the operating losses incurred by 59 Disposal and a jointly owned pipeline. Based on this disclosure, it appears that, prior to your acquisition of 59 Disposal in December 2007, you were accounting for the operations of this entity and a certain jointly owned pipeline under the proportionate method of accounting. If our understanding is correct, please tell us and expand your accounting policy footnote to explain how you complied with EITF 00-1, which allows for proportionate gross financial statement presentation for equity method investments in either the construction or extractive industry and not in such activities as refining, marketing or transporting extracted mineral resources, or otherwise advise.

The Company has corrected its accounting of the amounts owed from TR Energy and has revised its disclosure accordingly. Of the $539,805 originally disclosed, $485,311 represented receivables that were improperly booked to capital contributions. The Company has corrected the Accounts receivable, related parties and Additional paid-in capital for this amount.

The remaining amounts owed by TR Energy to the Company included $32,609, which represented that entity’s portion of certain shared expenses (which included rent, contract labor, and other general and administrative type expenses) and $21,885, representing TR Energy’s 30% working interest share of the losses of the jointly owned pipeline. The accounting prescribed by EITF 00-1, “Investor Balance Sheet and Income Statement Display under the Equity Method for Investments in Certain Partnerships and Other Ventures” does not apply to the Company, as the Company is accounting for a working interest owned by a related party, not an equity method investment.

Consolidated Statements of Operations, page F-4

We note that you present stock-based compensation as a separate component of operating expenses. Please modify your presentation to include the expense related to share-based payments arrangements in the same line item or lines as cash compensation paid to the same employees. Refer to SAB Topic 14:F for further guidance.

The Company has revised the December 31, 2007 consolidated statements of operations to include stock-based compensation in the same line as general and administrative expenses.

Consolidated Statements of Changes in Stockholders’ Equity, page F-5

5.	Please expand your footnote disclosure to explain the nature of transaction that resulted in the capital distribution during 2007 of $257,942.

The Company has expanded the footnote disclosure to explain the nature of the transaction that resulted in the capital distribution of $257,942 during 2007.

Note 3. Restatement of Consolidated Financial Statements, page F-12

We note from your disclosure that one of your restatements was to “properly present net loss and capital attributable to Marion’s minority interest in 59 Disposal.” Based on this disclosure, please explain where you have reported the referenced minority interest in your consolidated financial statements.

The Company has restated its 2007 and 2006 consolidated financial statements to address the minority interest issue that was previously unaccounted for. Please see the new restatement footnote located at note 3 in the notes to the consolidated financial statements.

Note 11. Stock-Based Compensation, Page F-23

We note from your disclosure on page F-24 that you used an expected term of 5 years in your Black-Scholes valuation model. Given that you granted stock options for the first time in 2007, please tell us how you determined that the expected term of these options was 5 years. Refer to SAB Topic 14:D:2 concerning the use of expected term in the Black-Scholes model.

The expected term was determined through researching similar oil and gas companies’ disclosures. In all cases the expected term was found to be the maximum term of the options.

Note 13. Income Taxes, page F-25

We note from your response to prior comment number 25 that you report the Texas franchise taxes on a gross basis. We further note your expanded disclosure on page F-26, which states, “As the tax base for computing Texas margin tax is derived from 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;” and that this amount “is reflected in the income tax expense in the accompanying consolidated statement of operations.” Please confirm, if true, that your response with respect to Texas franchise tax relates to your disclosure concerning the Texas margin tax or otherwise advise. In addition, please clarify in your disclosure whether you are reporting your Texas margin tax on a gross or net basis, as contemplated by paragraph four of EITF 06-3.

The Company confirms that its response with respect to Texas franchise tax relates to its disclosure concerning the Texas margin tax. Also, upon further review, the Company does not believe that the Texas margin tax falls under the guidance directed by EITF 06-3. The Texas margin tax is not a tax imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer. The Company has expanded its Income Tax disclosure in order to better clarify how the Texas margin tax is derived.

Costs Incurred

We note your inclusion of a separate line for asset retirement costs. Please modify your presentation so that amounts incurred related to asset retirement obligations are included in the balance of the line items required to be disclosed as there is no provision for this line item in paragraph 21 and illustration 2 of FAS 69.

The Company advises the Staff that it included the asset retirement costs in this disclosure due to the February 24, 2004 sample letter sent to oil and gas producers regarding FAS 69 and FAS 143, located at http://www.sec.gov/divisions/corpfin/guidance/oilgasletter.htm. This letter notes that “the Costs Incurred disclosures in a given period should include asset retirement costs capitalized during the year.”

Well Economics, page 26

10.	We have reviewed your response to prior comment 32. Please revise your document and disclose the average sales price received for oil and for gas in both 2006 and 2007. Please see Industry Guide 2.

The Company has revised its disclosure to reflect the average sales price for oil and for gas in both 2006 and 2007.

Reserve Quantity Information, page F-32

11.

Please revise your document to disclose that the independent engineer that determined your reserves also planned and supervised the drilling and completion of the four wells that you have drilled in the East Texas project. Separately disclose the compensation that you provided for the drilling work and for the reserve estimation work for each of the last two years. Also, tell us his background in estimation of reserves.

The Company has revised its disclosure to include that James Smith supervised the drilling of its wells and also determined the reserve estimations. The compensation paid to James E. Smith & Associates for the last two years has also been included in the revised disclosure. In regards to James E. Smith’s background in estimation of reserves, his resume is attached as Annex B.

Changes in proved developed and underdeveloped reserves, page F-32

12.	We have reviewed your response to comment 34. As new reserves were added due to the drilling of the wells, these increases should be described as discoveries and extensions and not revisions. Please see paragraph 11 of SFAS 69. Please revise your document as necessary.

The Company advises the Staff that it inadvertently used a reserve report which included reserves added during January 2008 that resulted from the drilling of the wells. The reserve report has been corrected for the proper cutoff date of December 31, 2007. The new reserves will be reflected in 2008 as discoveries and extensions.

13.	Please confirm that the recent drilling and testing which justified the increase in reserves took place as of December 31, 2007.

The Company advises the Staff that it inadvertently used a reserve report which included reserves added during January 2008 that resulted from the drilling of the wells. The reserve report has been corrected for the proper cutoff date of December 31, 2007. Accordingly, the Company has made revisions to the Registration Statement.

14.

We have reviewed your response to prior comment 35 and re-issue our prior comment as you still report twice the reserves and your production has decreased significantly from 2006 to 2007. Your production in the first two months of 2008 will only provide annual production of 5232 barrels of oil and 58,056 mcf of gas from your proved developed reserves assuming this production rate is constant throughout the year, which it will not be. This volume is still significantly lower than that produced in both 2006 and 2007. Please tell us the basis for maintaining and increasing your proved developed reserves when your production is declining at such a significant rate or alternatively revise your reserves as necessary.

The Company advises the Staff that it inadvertently used a reserve report which included reserves added during January 2008. The reserve report has been corrected for the proper cutoff date of December 31, 2007 and, as a result, the reserves show a decrease from the end of 2006 to the end of 2007.

15.

We have reviewed your response to prior comment 37. We do not believe that the supplemental information you cite supports the long reserve lives and note that the revised reserve volumes increase the reserve lives to 79 years for your proved developed oil reserves and to 56 years for your proved developed gas reserves. Therefore we re-issue our prior comment and with a view towards disclosure please provide sufficient reasons for these long reserve lives or reduce your reserves accordingly.

The reserve report has been corrected for the proper cutoff date of December 31, 2007. The Company also has moved its proved behind pipe reserves to the proved undeveloped classification due to what the Company believes to be significant future costs to produce the reserves, as a result, the estimated reserve lives are 7 years for our proved developed oil reserves and 7 years for its proved developed gas reserves.

16.

We have reviewed your response to prior comment 38. Proved developed reserves that require significant costs in the future to bring on production should be classified as proved undeveloped reserves but only if they are scheduled to be completed in a reasonable time frame of approximately five years. However, we note projects that are not scheduled to be completed until beyond 2022. Please tell us why you believe these undeveloped reserves meet the definition of proved reserves or revise your document to remove them.

The Company advises the Staff that all lower Cotton Valley PUD’s will be developed within 5 years. These wells have approximately 20 year lives, which limits wellbore utilization for recompletion in the upper Cotton Valley/upper Travis Peak/Pettit zones to beyond the 20 year life.

17.	For clarification purposes, please provide summary information from the reserve report that shows the following in tabular format as of December 31, 2007 with NPV at 10% of all reserve categories shown below after you have made any necessary reserve adjustments due to the other comments:

·	Proved developed producing net oil reserves;

·	Proved developed producing net gas reserves;

·	Proved developed non-producing net oil reserves;

·	Proved developed non-producing net gas reserves;

·	Proved developed behind-pipe net oil reserves;

·	Proved developed behind-pipe net gas reserves;

·	Proved undeveloped net oil reserves;

·	Proved undeveloped net gas reserves.

Please find the summary information attached as Annex B.

18.

In Book 1 of the reserve report the evaluator stated that the forecast production profiles for Proved undeveloped vertical wells were based on cumulative production versus time curve analysis of new Cotton Valley (Taylor) wells currently or recently being completed in the nearby Woodlawn field. Please tell us how near the Woodlawn field is to your wells and the length of production history as of December 31, 2008 you had from the new wells used as an analogy.

The Company advises the Staff that reserves related to the Woodlawn field were those that were inadvertently included in the prior reserve report. A new reserve report, with the correct cutoff date, has been drafted. This report omits disclosures regarding the Woodlawn field.

19.

In Book 1 of the reserve report the evaluator stated that the forecast production profiles for horizontal wells were based on three times the average vertical well cumulative production profile for Bossier C Sand wells in the Kildare and E. Linden fields. Please tell us the basis for this estimate and how it meets the definition of proved reserves. Tell us if any horizontal wells have been drilled into the Bossier Sand in this area and if so what the results have been.

The Company advises the Staff that there are no horizontal wells included in the proved classification. The commentary related to the forecast production for horizontal wells was inadvertently included in the prior reserve report. This information was related to probable reserves and was included in a reserve report that had an incorrect cutoff date. A new reserve report, with only proved reserves and a correct cutoff date, has been drafted and our SEC reports have been restated accordingly.

Form 10-KSB for the Fiscal Year Ended December 31, 2007

Controls and Procedures, page 30

Disclosure Controls and Procedures

20.	We note you have not concluded as to the effectiveness of your disclosure controls and procedures as of the end of the period covered by this report. Please modify your disclosure as appropriate under the guidance in Item 307 of Regulation S-K.

The Company advises the Staff that it will amend the Form 10-KSB to modify its disclosures as follows (new language is underscored).

Item 8A (T). Controls and Procedures

Disclosure Controls and Procedures

We maintain “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that are designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our relevant officers have made conclusions as to the effectiveness of our disclosure controls and procedures at the reasonable assurance level.

Management’s Report on Internal Control Over Financial Reporting

Pegasi Energy Resources Corporation is exempt from the requirements of the Exchange Act Rule 13a-15(f) for the fiscal year ended December 31, 2007, due to the December 12, 2007 reverse merger date with Maple Mountain, a publicly traded shell company. Maple Mountain, however, is not exempt. The management of Maple Mountain is responsible for establishing and maintaining adequate internal control over financial recorting. This internal control system has been designed to provide reasonable assurance to the Company’s management and board of directors regarding the preparation and fair presentation of the Company’s published financial statements.

A material weakness in internal control is a significant deficiency or an aggregation of significant deficiencies that preclude the entity’s internal control from providing reasonable assurance that material misstatements in the financial statements will be prevented or detected on a timely basis by employees in the normal course of performing their assigned functions. A significant deficiency is an internal control deficiency in a significance control or an aggregation of such deficiencies that could result in a misstatement of the financial statements that is more than inconsequential.

The management of Pegasi Energy Resources Corporation has assessed the effectiveness of Maple Mountain's internal control over financial reporting as of December 12, 2007, and this assessment identified the following material weakness in the Company’s internal control over financial reporting:

During our assessment several significant internal control deficiencies became evident. In the aggregate a material weakness resulted from control deficiencies that included no segregation of duties, whistleblower program not in place, the Company did not have an audit committee, and the board of directors did not oversee management’s process for defining responsibilities for key financial reporting roles due to the fact that a member of the board prepared the financial statements. As a result of this material weakness, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2007, we were not effective in maintaining (i) disclosure controls and procedures, or (ii) internal control over financial reporting.

To make this assessment, we used the criteria for effective internal control over financial reporting described in Internal Control – Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that, as of December 12, 2007 the Company’s internal control over financial reporting was not effective.

This report does not include an attestation report by Whitley Penn, our independent registered public accounting firm, regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the SEC that permits the Company to only provide management’s report in this Form 10-KSB.

21.

In addition, please confirm, if true, that your disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and that your relevant officers have concluded as to the effectiveness of your disclosure controls and procedures at the reasonable assurance level or otherwise advise and so state. In this regard, we note your statement that “In designing and evaluating our disclosure controls and procedures, management recognized that disclosure controls and procedures, no matter how well conceived and operated, can provide only reasonable assurance of achieving the desired control objectives, and we necessarily are required to apply our judgment in evaluating the cost-benefit relationship of possible disclosure controls and procedures.”

See the Company's response to the previous comment.

Please contact the undersigned at 212-981-6766 with any questions or comments you may have with respect to the foregoing.

Very truly yours,

/s/ Louis A. Brilleman

President, James E. Smith & Associates, Inc., Spartan Operating Company, Inc., and Peak Oil & Gas Company, Inc.

A leader in the field of petroleum engineering; plan, drill, operate, supervise, and complete wells; develop and review geological prospects; monitor Railroad Commission hearings; consult as an expert witness, with experience on more than 500 cases.

1978 - 1981

President, Smith & Harman Engineering Company, Inc., Safety Management Associates, Inc., S-H-K Operating Company, Inc., and Streetman Salt Water Disposal, Inc.

Planned and supervised drilling and completion of over 100 wells ranging in depths from 5,000 to 16,000 feet; planned and developed Streetman Salt Water Disposal, Inc.; managed numerous oil and gas properties in the East Texas area.

1976 - 1978

Vice President, Petro-Management, Inc.

Planned and supervised over 20 wells down to depths of 15,000 feet, including high pressure sour gas wells; conducted operations on day work basis; planned and supervised rig selection, bit program, hydraulics, mud system, H2S safety training, casing programs, log evaluations, completion recommendations and supervision.

1974 - 1976

State Field Operations Director, Railroad Commission, Austin,

Texas.

Reviewed wells being drilled and completed in the State of Texas; acted as State Field Monitor on oil well fires and blowouts; monitored operators' programs with "Authority to Proceed,” conducted extensive investigation into Hydrogen Sulfide, “Sour Gas,” oil and gas operations; developed the Texas Rule 36 Regulation for sour gas production, drilling and completion operations; directed "East Texas Field Study," developed an on-line computer system for the State of Texas; organized the Statewide Radio Network; completed numerous official projects.

1967 - 1974

District Director, Railroad Commission, Kilgore, Texas.

Directed Railroad Commission review of the drilling and completion of all wells in the District; organized planning, logistics and well-site supervision for re-entry and re-plugging of over 300 abandoned wells, two of which were located in 40 foot of water in Toledo Bend Reservoir; reorganized Railroad Commission Districts 5 and 6, which became the model plan for Railroad Commission Statewide Operations.

1962 - 1967

District Director, Railroad Commission, Abilene, Texas.

Directed the re-entry and clean out of over 200 wells leaking saltwater and oil to ground level; reorganized Abilene office; supervised the Hubbard Creek Pollution Abatement Program, a pioneer Railroad Commission effort, and forerunner of the Statewide Railroad Commission "No Pit" order; completed extensive projects involving fluid injection problems and well plugging.

1962 - 1962

Project Engineer, Railroad Commission, Kilgore, Texas

Supervised all field activity for Railroad Commission District 4; conducted slant well investigation; planned field logistics and well-site supervision of the re-entry and clean out of over 200 wells which had been intentionally junked to avoid investigation.

1960 - 1962

Assistant District Director, Railroad Commission, Corpus Christi, Texas.

Supervised and trained all Railroad Commission field personnel inland and offshore drilling and completion operations.

1958 - 1960

Field Engineer, Railroad Commission, Abilene, Texas.

Supervised drilling and completion reviews; conducted well tests, lease inspections, and regulatory investigations.

Education

1958	Texas A&M University, B.S. Petroleum Engineering Recipient of Minnie Piper Stephens Scholarship

1955 - 1957

Arlington State College

Freshman Honor Society - 1955

Distinguished Student Award - 1956-57

Post Graduate Achievements

1999	Hydrocarbon Economics and Evaluation Symposium - Energy in the Next Millennium, Society of Petroleum Engineers, Dallas, Texas.

1999	Formation Damage: Mechanisms, Diagnosis, and Prevention, Society of Petroleum Engineers, Houston, Texas.

1999	Applied Technology Workshop – Probabilistic Assessment of Reserves, Society of Petroleum Engineers; Houston, Texas.

1997	3-D Seismic for Engineers, Society of Petroleum Engineers; Dallas, Texas.

1991	Safety and Compliance Seminar, Department of Transportation, Kilgore College; Kilgore, Texas.

1991	Train-the-Trainer Hydrogen Sulfide (H2S) Instructor Training Course, American Society of Safety Engineers; Midland, Texas.

1990	Overview of Horizontal Drilling and Completions, Society of Petroleum Engineers; New Orleans, Louisiana.

1986	East Texas Regional Meeting, Society of Petroleum Engineers.

1977	Annual Technical Meeting, Society of Petroleum Engineers; New Orleans, Louisiana.

1976	Interstate Oil Compact Commission Meeting; Wichita, Kansas.

1976	Annual Gas Conditioning Conference; Norman, Oklahoma.

1976	Drilling and Production Institute, University of Kansas; Liberal, Kansas.

1974	East Texas Regional Meeting, Society of Petroleum Engineers.

1967	Advanced Reservoir Engineering, Graduate Seminar, Texas A & M University; College Station, Texas.

Professional Affiliations

Texas Board of Professional Engineers

American Society of Safety Engineers

East Texas Gas Producers Association (ETGPA)

Independent Petroleum Association of America (IPAA)

National Academy of Forensic Engineers (NAFE)

National Association of Royalty Owners (NARO)

National Association of Corrosion Engineers (NACE)

National Society of Professional Engineers (NSPE)

Society of Independent Professional Earth Scientists (SIPES)

Society of Petroleum Engineers (SPE)

Society of Petroleum Evaluation Engineers (SPEE)

Society of Petrophysicists and Well Log Analysts

Texas Independent Producers & Royalty Owners Association (TIPRO)

Past Chairman, East Texas Chapter of Society of Petroleum Engineers

Past Chairman, Abilene Chapter of Society of Petroleum Engineers

Past Chairman, West Central Texas Waterflood Association

Past Chairman, East Texas Chapter Joint Engineers Banquet

Past Chairman, East Texas Symposium on Hydrogen Sulfide Operations

Awards and Honors

Certificate of Appreciation, West Texas Oil & Gas Association

Certificate of Appreciation, West Central Texas Municipal Water District

Certificate of Appreciation, Desk & Derrick Club

Certificate of Appreciation, National Professional Engineers Hall of Fame

Certificate of Appreciation, Lubbock Area Firemen’s Conference

Certificate of Appreciation, West Central Texas Society of Petroleum Engineers, (SPE)

Certificate of Appreciation, West Central Texas Waterflood Association Certificate of Appreciation, East Texas Section, Society of Petroleum Engineers, (SPE)

Honorary Citizen, City of Kilgore

Who's Who in the Southwest - 1975

Who's Who in Engineering and Science - 1993

Civic Affiliations

Past Member, Abilene Chapter, Lions Club

Past Member, Kilgore Chapter, Lions Club

Sponsor, Ducks Unlimited

Sponsor, Boy Scouts of America

Sponsor, Desk & Derrick Club of Tyler

Sponsor, Deck & Derrick Club Region IV

Former Scout Master, Boy Scouts of America

Wood Badge Training Certificate Instructor, Boy Scouts of America

Texas A & M University Alumni member Tyler Chamber of Commerce

Century Club Member, Texas A & M University

Presentations and Publications

Smith, J.E.; “The Search for the Right Way: A Review of Engineering and Operational Dichotomies Currently Operative in the Development of the Barnett Shale,” presented to Strategic Research Institute sponsored conference “Gas Shales: Production & Potential”; Denver, Colorado (July 2004).

Smith, J.E., Neufeld, M.H. and Sorrells, D.C.; “Development of the Cotton Valley Geopressure Zone in Panola County, Texas, Using Air/N2 Drilling and Openhole Completion Techniques;” paper SPE 14657 presented at East Texas Regional Meeting of the Society of Petroleum Engineers; Tyler, Texas (April 1986).

Smith, J.E.; “H2 S Regulations in Deep Well Drilling;” presented to the Society of Petroleum Engineers, Deep Well Drilling Conference; Amarillo, Texas, (April 1977).

Smith, J.E.; “The Effect of Rule 36 (H2S Service) on Material Selection;” presented to the Houston Chapter, American Society for Metals; Houston, Texas (January 4, 1977).

Smith, J.E.; “A History of the Development of Rule 36;” Journal of Petroleum Technology; (1977) 1227-1234.

Smith, J.E.; “A Review of Texas Railroad Commission Rule 36 for Operation in Hydrogen Sulfide Areas;” paper, SPE 6147, presented to American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. (1976).

Smith, J.E.; “H2S Regulation in Perspective;” presented to the 12th Annual Pipeline & Maintenance Institute; University of Kansas (November 16-17, 1976).

Smith, J.E.; “History of the Development of Rule 36;” paper presented to the Society of Petroleum Engineers, Annual Technical Conference, New Orleans, Louisiana (October 1976).

Smith, J.E.; “Development of Texas Hydrogen Sulfide Public Safety Regulation (Rule 36);” paper presented at Interstate Oil Compact Commission Meeting, Wichita, Kansas (June 28, 1976).

Smith, J.E.; “The Relationship of New Texas Sour Gas Rules to Gas Conditioning Operations;” paper presented at 26th Annual Gas Conditioning Conference, Norman, Oklahoma (March 6-10, 1976).

Smith, J.E.; “New Texas Railroad Commission Regulation on Sour Gas (Hydrogen Sulfide);” paper presented at Drilling and Production Institute, U. of Kansas, Liberal, Kansas (February 3-4, 1976).

Smith, J.E.; “Cooperation is Key to Pollution Control in East Texas;” Petroleum Engineer (November 1971).

Raschke, Alvin, Smith, James E. and Wills, M.E.; “Let Engineering Know-How Solve Salt-Pollution Problems;” The Oil and Gas Journal (August 9, 1965).

Landrum, Bobby L., Smith, James E. and Crawford, Paul B.; “Calculation of Crude-Oil Recoveries by Steam Injection;” Petroleum Transactions; (1960) Vol. 219, p.251-6.

Landrum, Bobby L., Smith, James E. and Crawford, Paul B.; “Calculation of Crude-Oil Recoveries by Steam Injection;” Summary of T.P.8 130; Journal of Petroleum Technology (1959) p. 237-A.

Annex B

Pegasi Energy Resources
Reserve Report
As of Date: 12/2007
			PERC'S
	100% WI		70% WI

Proved developed producing oil reserves (bbls)	$	46,700	$	32,690
Proved developed behind-pipe oil reserves (bbls)		256,356		179,449
Proved undeveloped oil reserves (bbls)		347,045		242,932
Total proved developed & undeveloped oil reserves (bbls)	$	650,101	$	455,071

Proved developed producing gas reserves (mcf)	$	1,009,655	$	706,759
Proved developed behind-pipe gas reserves (mcf)		7,412,932		5,189,052
Proved undeveloped gas reserves (mcf)		8,140,410		5,698,287
Total proved developed & undeveloped gas reserves (mcf)	$	16,562,997	$	11,594,098


Total proved developed & undeveloped equivalent bbls	$	3,410,601	$	2,387,420

Total proved developed oil reserves	$	46,700	$	32,690

Total proved developed gas reserves	$	1,009,655	$	706,759
				-
Proved developed producing future cash inflows	$	9,558,942	$	6,691,259
Proved developed behind-pipe future cash inflows		62,274,656		43,592,259
Proved undeveloped future cash inflows		74,375,695		52,062,987
Total future cash inflows	$	146,209,293	$	102,346,505

Proved developed producing future production costs	$	3,824,433	$	2,677,103
Proved developed behind pipe future production costs		15,576,113		10,903,279
Proved undeveloped future production costs		17,487,324		12,241,127
Total future production costs	$	36,887,870	$	25,821,509

Proved developed producing future development costs	$	-	$	-
Proved developed behind pipe future development costs		3,900,000		2,730,000
Proved undeveloped future development costs		7,800,000		5,460,000
Total future development costs	$	11,700,000	$	8,190,000

Proved developed producing future net revenue	$	5,734,508	$	4,014,156
Proved developed behind pipe future net revenue		42,798,551		29,958,986
Proved undeveloped future net revenue		49,088,375		34,361,863
Total future revenue, net	$	97,621,434	$	68,335,004

Proved developed producing discounted future net revenue	$	3,541,676	$	2,479,173
Proved developed behind pipe discounted future net revenue		12,713,671		8,899,570
Proved undeveloped discounted future net revenue		7,174,957		5,022,470
Total discounted future net revenue	$	23,430,304	$	16,401,213