Parallel Petroleum CORRESP Correspondence with SEC

LYNCH, CHAPPELL & ALSUP
A PROFESSIONAL CORPORATION
ATTORNEYS
THE SUMMIT, SUITE 700
300 NORTH MARIENFELD
MIDLAND, TEXAS 79701
(432) 683-3351
TELECOPIER (432) 683-8346

June 10, 2009

Via Edgar and Federal Express

Securities and Exchange Commission
100 F Street, N.E.
Washington, D.C. 20549-7010

Attention: Tracey L. McNeil, Division of Corporation Finance

Re: Parallel Petroleum Corporation
From 10-K for the Fiscal Year Ended December 31, 2008
Filed February 23, 2009
Response Letter filed May 12, 2009
File No. 000-13305

Dear Ladies and Gentlemen:

     We write this letter on behalf of Parallel Petroleum Corporation (the “Company”) to respond to the comment letter received from the Staff on May 28, 2009 (the “Comment Letter”), relating to Parallel’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008 (“Parallel’s 10-K”) and to our response letter filed May 12, 2009.

     We have numbered each of the responses to correspond to the numbering of the comments in the Comment Letter. For your convenience, we have repeated each comment (in bold type) immediately preceding the corresponding response.

Securities and Exchange Commission
June 10, 2009
Page 2

Form 10-K for the Fiscal Year Ended December 31, 2008

Engineering Comments

Business, page 1

About Our Business and Strategy, page 5

1. We have reviewed your responses to prior comments one and two, indicating that you intend to refrain from disclosing reserve replacement figures in future filings, rather than provide clarifying disclosure. We understood from your earlier response to comments four and six that you would disclose annual reserve replacement percentages or ratios in future filings because you believed this would be helpful and would serve to clarify your prior disclosure. Tell us if you have concluded that reserve replacement is no longer a meaningful concept for describing your results of operations; and if so how you would address this change in transitioning away from prior disclosure.

Response No. 1

The Staff’s understanding of the Company’s previous response to comments four and six in the Staff’s March 31, 2009 letter is correct. As the Staff further correctly points out, the Company, in response to comments one and two in the Staff’s April 28, 2009 letter, subsequently proposed to delete all references to reserve replacement ratios and percentages. This reversal in the Company’s response to the Staff’s comments was not the result of a determination by the Company that reserve replacement measures are not a useful internal tool for helping gauge the Company’s drilling success, but instead was the result of the Company’s belief, after having prepared drafts of additional clarifying disclosures, that the additional clarifying disclosures (including descriptions of measures such as relative exploratory, development and property acquisition costs, changes in reserves associated with changes in commodity prices and other factors) seemed to add more confusion than clarity, in comparison to the more traditional disclosures presented in accordance with SFAS No. 69, “Disclosures about Oil and Gas Producing Activities”. Additionally, and as described in the Company’s response to comment two in the Staff’s April 28, 2009 letter, the absolute year-over-year reserve quantities since 2000 will be disclosed, which reveals the trend in the Company’s reserves, along with the reasons for the changes in proved reserves from year to year. These disclosures, while not expressed in ratios or percentages, will provide investors with essentially the same type of information as the ratios and percentages which the Company proposes to omit. Consequently, Parallel believes that removing the reserve replacement ratios and not using the measure in future filings would be the most appropriate course of action.

Securities and Exchange Commission
June 10, 2009
Page 3

For transition purposes, the Company would note that part of its internal evaluation of success in growing and maintaining reserves is based upon internally prepared reserve measures, without referencing specific percentages or ratios.

Financial Statements

Supplemental Oil and Natural Gas Reserve Data, page F-45

2. We have reviewed your response to prior comment three, regarding the delay in producing the secondary reserves from the “second” waterflood project, explaining that the unitization process is still underway. Tell us why you believe that such reserves meet the test of reasonable certainty, given that you have not yet obtained the necessary approvals from the co-owners and royalty owners for the unitization agreement. Please tell us also the incremental reserves associated with this project, indicate your position on materiality, and submit any information that you believe should be considered in support of your reserve determination.

Response No. 2

The Company believes that it has met the test of reasonable certainty contained in Rule 4-10(a) of Regulation S-X for reserves associated with its Carm-Ann waterflood project because of having established that the reserves exist to a reasonable certainty by performing two separate waterflood studies and the Company intends to complete the waterflood, with or without unitization.

Reserve Existence- The Company has two studies on its planned Carm-Ann field waterflood, one of which was commissioned by the Company. The two studies were prepared by separate independent reservoir engineering firms, including T. Scott Hickman and Associates (“Hickman”), Midland, Texas, and Bill Cobb and Associates (“Cobb”), Dallas, Texas. The study prepared by Cobb was commissioned by the Company. In each case, the firms utilized volumetric analysis, decline curve analysis and field analogous performance to arrive at anticipated secondary to primary reserve ratios. Cobb, who performed the engineering for the unitization effort, also incorporated reservoir computer modeling. The reports of both firms show secondary to primary ratios in excess of the level at which the Company recognized proved reserves in its December 31, 2008 reserve estimates. Based on the evaluations provided by these respected consulting firms and the extensive secondary recovery experience of the Company’s own technical staff, the Company has a very high level of confidence that the waterflood reserves, as currently reflected in its reserve estimates, will be recovered.

Waterflood Implementation- There are two avenues by which waterflood implementation

Securities and Exchange Commission
June 10, 2009
Page 4

may occur. The first would be through unitization whereby royalty and working interests are normalized across a multi-lease project area. The advantages derived from unitization or lease consolidation are simplification of production reporting, revenue distribution and joint interest billing since it results in a single accounting entity. Operational efficiencies are also gained since consolidation of multiple surface fluid handling facilities is permitted. Delays incurred to date have been the result of the complexity and volume of ownership title confirmation work. Despite these delays, the Company believes that unitization will be successful.

The Company continues to proceed with the process of preparing the properties for waterflood and the unitization process. To date, preparatory work has included the drilling of 33 new wells and 25 well workovers. In addition, reservoir engineering work has been completed, as has mineral and working interest title work. Ownership participation factors have been determined and mineral owner and working interest owner election ballots are scheduled for mailing within the next few weeks. Upon receiving sufficient working interest and mineral interest approval the Company will apply to the Texas Railroad Commission for unitization. The Company anticipates full approval and initiation of water injection before March 1, 2010. As most mineral owners and working interest owners are well aware of the economic advantages of waterflood operations in this area, the Company is highly confident that unitization will be approved.

Majority working interest ownership, operatorship and control of the Carm-Ann Field assets was acquired by the Company in 2004 expressly for the ultimate purpose of waterflood implementation. If the Company does not achieve unitization, which is not a prerequisite to waterflood, the Company still intends to proceed with the Carm-Ann waterflood on a lease basis, whereby all individual leases in the project area remain as independent operational, reporting and accounting entities. From a technical standpoint, there is no difference in ultimate reserve recovery. However, the disadvantages of this second avenue are the loss of the operational and accounting efficiencies described above. Mineral interest approval is not required under this second avenue. From a regulatory standpoint, the only approvals required from the Texas Railroad Commission will be for individual well injection permits. Accordingly, under commodity pricing and cost levels at December 31, 2008, as well as current pricing and costs, the Company has no reason to believe that the certainty of waterflood implementation is anything other than absolute.

The following table illustrates the proved undeveloped reserves associated with this project

Securities and Exchange Commission
June 10, 2009
Page 5

and their relative materiality in comparison to the Company’s total proved reserves as of December 31, 2008:

	Oil			Natural Gas			BOE			PV 10 Value
	(mbbls)			(mmcf)			(mbbls)			(in thousands)
Total Proved Reserves		21,206			71,833			33,179		$	309,607
Carm-Ann reserves associated with waterflood		2,191			1,198			2,391		$	10,623
Percentage of Proved Reserves		10.3	%		1.7	%		7.2	%		3.4	%

For the Staff’s further assistance, a copy of the Cobb waterflood study is enclosed with this letter.

          If any member of the Staff has questions regarding the foregoing, please contact Tommy Ortloff at (432) 683-3351 (main number) or (432) 688-1304 (direct line).

Very truly yours,

/s/ Thomas W. Ortloff

Thomas W. Ortloff

Enclosures

cc: Tracey L. McNeil (SEC) (via Federal Express)
James Murphy (SEC) (via Federal Express)

WATERFLOOD UNITIZATION STUDY

OF THE

SAN ANDRES RESERVOIR

LOCATED IN

CARM-ANN FIELD

GAINES COUNTY, TEXAS

PREPARED FOR

PARALLEL PETROLEUM CORPORATION

MARCH 11, 2009

WILLIAM M. COBB & ASSOCIATES, INC.
Worldwide Petroleum Consultants

WILLIAM M. COBB & ASSOCIATES, INC.
Worldwide Petroleum Consultants

12770 Coit Road, Suite 907	(972) 385-0354
Dallas, Texas 75251	Fax: (972) 788-5165
	E-Mail: office@wmcobb.com

March 11, 2009

Mr. Jerry W. Nevans
Parallel Petroleum Corporation
1004 N. Big Spring Street, Suite 400
Midland, Texas 79701

Re: Waterflood Unitization Study
Carm-Ann Field
Gaines County, Texas

Dear Mr. Nevans:

At your request, William M. Cobb & Associates, Inc. has performed a waterflood unitization study for certain leases located in Gaines County, Texas. The purpose of the study was to develop an equitable participation formula for sixteen leases such that they might be unitized to maximize remaining primary and secondary (waterflood) oil recovery for the productive San Andres reservoir.

We have performed a detailed geological and engineering study of these leases and propose a two-phase participation formula as presented in Exhibit 1. Phase I honors the remaining primary reserves while Phase II honors secondary, waterflood recovery. The following sections of this report document the methodology and results of our study.

Petrophysical Analysis

We have analyzed well logs from 60 wells on and near the subject leases, usingPETCOM/POWERLOG analytical software. In the course of this analysis, we integrated extensive core data available from the McConal-Clark #8. This well was also the only well with a modern suite of open-hole logs available for detailed analysis. This key well was used to calibrate core porosity to neutron log porosity throughout the field area. The correlation from neutron log porosity (NPHI) to core porosity (NPHI_C) is illustrated in Exhibit 2 and is as follows:

NPHI_C = (4.704124E+01*NPHI+6.064257E-01)/100)

San Andres net pay was defined as intervals above the lowest known oil of -1,625 feet sub-sea where NPHI_C > 0.03 andVcl< 0.485.Vcl(clay volume) was calculated for each well from theGR (gamma ray) curve utilizing thePETCOMcurve equation. Average porosity in the pay intervals from all the analyzed wells is 4.5 percent.

Mr. Jerry W. Nevans
March 11, 2009
Page 2

Resistivity logs needed to calculate water saturations (Sw) were available for the McConal-Clark #8 well only. Consequently, the water saturation for the entire field is assumed to be 32.4 percent, which is the calculated average water saturation for the pay intervals in the McConal-Clark #8 well. Petrophysical data from the analyzed wells are presented in Exhibit 3.

Geological Mapping

A net pay isopach map was prepared for the study area utilizing the net pay data (in feet) calculated from the detailed petrophysical analyses. This map was constructed usingPETRA geological software and is presented in Exhibit 4. The lease tracts for the proposed Carm-Ann Unit are shown on the isopach map.

Original Oil in Place (OOIP)

Total OOIP for the proposed Carm-Ann unit is 21,475 MSTB. OOIP was calculated for each of the 16 tracts using the net acre-feet from the net pay isopach map and the following constant rock and fluid properties:

Porosity = 4.5%

S_wc = 32.4%

B_oi = 1.140 RB/STB

The average porosity value is a result of our analysis of well logs from 60 wells. The average water saturation comes from our analysis of the McConal-Clark #8 well as discussed above. The formation volume factor of 1.140 RB/STB was estimated using industry correlations.

Primary Production

Oil production form the San Andres reservoir was established on the subject leases in November, 1979. The San Andres reservoir is encountered at a depth of approximately 4,600 feet and has produced a total of 1,876 MBO as of January 1, 2009.

Remaining and ultimate oil production for each tract (lease) was determined by analysis of graphs of producing oil rate versus time (rate/time). Individual tract performance curves are contained in Exhibit 5, which also contains a summary curve for the entire proposed Carm-Ann Unit.

The projected ultimate primary oil recovery volumes result in primary recovery factors ranging from 1.67 percent to 19.85 percent of the individual tract OOIP values, as shown in Exhibit 6. The average primary oil recovery for the entire unit is projected to be 11.06 percent OOIP.

Mr. Jerry W. Nevans
March 11, 2009
Page 3

Waterflood Recovery

We have prepared a single pattern simulation model to predict primary and secondary recovery for a “typical” San Andres five-spot pattern in the Carm-Ann field. This simulation study is documented in Appendix A of this report.

The single pattern model is 40 acres in size. For both primary and secondary cases, there are two full wells in the model such that effective well spacing is 20 acres per well. In the primary case, both wells are producers for the entire prediction. In the waterflood case, both wells are producers for 15 years, at which time one well is converted to injection.

Primary oil recovery is predicted to be about 13 percent of the model OOIP. This is consistent with the individual lease recovery values from volumetric analysis and decline curve projections.

The pattern model predicts a waterflood ultimate recovery of about 29 percent of the pattern OOIP, which, in our experience, is a reasonable value. Calculated secondary-to-primary ratio (S/P) is 1.24.

We have calculated incremental secondary oil recovery for the individual Carm-Ann tracts using an S/P ratio of 1.20. These calculations are presented in Exhibit 7.

Unitization Parameters

The goal of this report was to develop a fair and equitable participation formula for the 16 leases in the study area while maximizing future primary and secondary oil recovery from the San Andres reservoir. We have developed a two-phase formula designed to honor remaining primary reserves in Phase I and incremental secondary oil recovery in Phase II. This participation formula was shown previously in Exhibit 1.

The Phase I participation formula gives 10 percent credit to the surface acreage in each lease. Another 10 percent credit is given to each tract’s calculated OOIP. Remaining producing oil reserves (PDP) are given 40 percent credit in the Phase I formula, and 2008 oil production, which is an indication of current productivity, is given 40 percent credit. When the total remaining primary oil reserve volume of 500,171 STB is produced Phase I ends and Phase II begins. The reference point for the remaining oil volume is as of January 1, 2009.

The Phase II formula gives 75 percent credit to the calculated incremental secondary oil volume, by lease. The remaining 25 percent credit is given to useable wellbores, which is intended to recognize past capital contributions to the potential waterflood project.

Mr. Jerry W. Nevans
March 11, 2009
Page 4

We appreciate the opportunity to prepare this waterflood unitization study for Parallel Petroleum Corporation. We wish the Carm-Ann San Andres owners every success with this project.

Sincerely,

WILLIAM M. COBB & ASSOCIATES, INC.
 

/s/ Frank J. Marek  

Frank J. Marek, P. E. 

Senior Vice President 

 

/s/ Brian D. Nicoud  

Brian D. Nicoud, P. G. 

Senior Geological & Petrophysical Advisor 

FJM:jf

EXHIBITS

Carm-Ann Unit Tract Participation Factors

PHASE I :

		Phase I		0.100		0.100		0.400		0.400		1.000
		Tract		Surface		OOIP		Rem. PDP		2008
Tract	Lease	Participation		acres		STB		STB		BBL Oil
1	Simmons		0.02241348		160.0		382,609		7,798		2,019
2	Coast		0.00377633		40.0		291,307		0		0
3	Metzger		0.02135709		80.0		585,065		14,037		1,099
4	PKC		0.30056428		240.0		2,400,335		196,467		50,405
5	Akers		0.02301562		40.0		595,115		18,716		1,223
6	Yeager		0.00622381		40.0		816,904		0		0
7	Mabee		0.00342063		40.0		214,920		0		0
8	McConal-Clark		0.06689226		120.0		2,513,933		22,878		12,684
9	Colgan State “A”		0.04480396		53.0		996,058		20,209		8,903
10	Lawrence “C”		0.08011829		80.0		1,336,105		37,368		16,769
11	Lawrence “D”		0.04321040		80.0		708,407		23,393		7,005
12	PKC “A”		0.06706007		80.0		2,397,209		18,074		15,669
13	Lawrence “B”		0.09465220		80.0		2,360,609		37,681		20,841
14	Lawrence “A”		0.03693574		40.0		852,540		20,973		5,896
15	Thompson “B”		0.10439488		160.0		2,607,196		49,410		18,433
16	Elizabeth Crews Mast		0.08116096		320.0		2,416,766		33,167		10,284
	TOTALS		1.00000000		1,653.0		21,475,079		500,171		171,230

William M. Cobb & Associates, Inc. EXHIBIT 1, page 1

Carm-Ann Unit Tract Participation Factors

PHASE II :

		Phase II		Primary		0.750		0.250		1.000
		Tract		EUR		Sec. STB		Useable
Tract	Lease	Participation		STB		@ S/P = 1.20		Wellbores
1	Simmons		0.01816158		45,891		55,069		1
2	Coast		0.00153624		4,867		5,840		0
3	Metzger		0.01945139		49,977		59,972		1
4	PKC		0.19816719		476,401		571,681		13
5	Akers		0.02621279		71,398		85,677		1
6	Yeager		0.01804206		45,512		54,614		1
7	Mabee		0.01220153		38,656		46,387		0
8	McConal-Clark		0.10569470		241,674		290,009		8
9	Colgan State “A”		0.07077167		189,271		227,125		3
10	Lawrence “C”		0.10285663		255,978		307,173		6
11	Lawrence “D”		0.04768641		116,134		139,361		3
12	PKC “A”		0.09008230		215,507		258,608		6
13	Lawrence “B”		0.08295329		192,921		231,506		6
14	Lawrence “A”		0.02755133		63,991		76,789		2
15	Thompson “B”		0.10254452		220,046		264,056		9
16	Elizabeth Crews Mast		0.07608637		147,871		177,445		8
	TOTALS		1.00000000		2,376,095		2,851,314		68

William M. Cobb & Associates, Inc. EXHIBIT 1, page 2

Neutron Log Porosity Correlated to Core Porosity

Carm-Ann Field — San Andres Formation

William M. Cobb & Associates, Inc. EXHIBIT 2

Carm-Ann Petrophysical Summary — Net Pay Cutoffs: Porosity =/> 0.030 & Vcl </= 0.485

Well	API		KB Elevation		San Andres				SS LKO		MD LKO		Gross Interval		Net-to-Gross		Net Pay		Avg Phi		Avg Sw	PhiH		HPT
Name and Number	Number	Section	Feet		MD Top, Feet		SS Top, Feet		Feet		Feet		Feet		Fraction		Feet		Fraction		Fraction	Feet		Feet
Coast-1	42-165-	11		3221.0		4604.0		-1383.0		-1625.0		4846.0		242.0		0.53099		128.5		0.04155	N/A		5.339	N/A
Cone #2	42-165-333980000	12		3233.0		4628.0		-1395.0		-1625.0		4858.0		230.0		0.23043		53.0		0.05389	N/A		2.856	N/A
Yeager-1	42-165-	12		3228.0		4550.0		-1322.0		-1625.0		4853.0		303.0		0.47195		143.0		0.04124	N/A		5.897	N/A
Yeager-2	42-165-	12		3216.0		4538.0		-1322.0		-1625.0		4841.0		303.0		0.51485		156.0		0.04104	N/A		6.402	N/A
Colgan State #A3	42-165-363490000	19		3213.0		4553.0		-1340.0		-1625.0		4838.0		285.0		0.30526		87.0		0.03880	N/A		3.376	N/A
L.B. Russell #3	42-165-	19		3211.0		4557.0		-1346.0		-1625.0		4836.0		279.0		0.55914		156.0		0.05239	N/A		8.173	N/A
McConal-Clark #5	42-165-363220000	19		3217.0		4556.0		-1339.0		-1625.0		4842.0		286.0		0.40909		117.0		0.04359	N/A		5.100	N/A
McConal-Clark #6	42-165-363230000	19		3214.0		4548.0		-1334.0		-1625.0		4839.0		291.0		0.50859		148.0		0.04403	N/A		6.516	N/A
McConal-Clark #8	42-165-363240000	19		3209.0		4546.0		-1337.0		-1625.0		4834.0		288.0		0.47743		137.5		0.04382	0.32440		6.025	4.071
McConal-Clark #9	42-165-364890000	19		3220.0		4537.0		-1317.0		-1625.0		4845.0		308.0		0.45455		140.0		0.04198	N/A		5.877	N/A
Russell #2	42-165-	19		3217.0		4594.0		-1377.0		-1625.0		4842.0		248.0		0.45161		112.0		0.04462	N/A		4.997	N/A
Russell #4	42-165-	19		3217.0		4567.0		-1350.0		-1625.0		4842.0		275.0		0.22182		61.0		0.04272	N/A		2.606	N/A
Russell #5	42-165-342960000	19		3211.5		4570.0		-1358.5		-1625.0		4836.5		266.5		0.19887		53.0		0.04048	N/A		2.145	N/A
Russell #6	42-165-365380000	19		3214.0		4605.0		-1391.0		-1625.0		4839.0		234.0		0.67094		157.0		0.04724	N/A		7.417	N/A
Lawrence #B5	42-165-363450000	20		3198.0		4573.0		-1375.0		-1625.0		4823.0		250.0		0.72800		182.0		0.04802	N/A		8.740	N/A
Lawrence #B6	42-165-364640000	20		3201.0		4570.5		-1369.5		-1625.0		4826.0		255.5		0.52642		134.5		0.04419	N/A		5.944	N/A
Lawrence #C5	42-165-363150000	20		3199.0		4562.5		-1363.5		-1625.0		4824.0		261.5		0.49331		129.0		0.04367	N/A		5.633	N/A
Lawrence #C6	42-165-364630000	20		3199.0		4579.5		-1380.5		-1625.0		4824.0		244.5		0.46217		113.0		0.04415	N/A		4.989	N/A
PKC #15	42-165-364690000	20		3203.0		4582.5		-1379.5		-1625.0		4828.0		245.5		0.64562		158.5		0.04821	N/A		7.641	N/A
PKC #A10	42-165-364670000	20		3202.0		4590.0		-1388.0		-1625.0		4827.0		237.0		0.46835		111.0		0.04526	N/A		5.024	N/A
PKC #A11	42-165-364650000	20		3196.0		4569.5		-1373.5		-1625.0		4821.0		251.5		0.65805		165.5		0.04669	N/A		7.727	N/A
PKC #A13	42-165-364910000	20		3207.0		4580.5		-1373.5		-1625.0		4832.0		251.5		0.57853		145.5		0.04329	N/A		6.299	N/A

William M. Cobb & Associates, Inc. EXHIBIT 3, page 1

Carm-Ann Petrophysical Summary — Net Pay Cutoffs: Porosity =/> 0.030 & Vcl </= 0.485

Well	API		KB Elevation		San Andres				SS LKO		MD LKO		Gross Interval		Net-to-Gross		Net Pay		Avg Phi	Avg Sw	PhiH	HPT
Name and Number	Number	Section	Feet		MD Top, Feet		SS Top, Feet		Feet		Feet		Feet		Fraction		Feet		Fraction	Fraction	Feet	Feet
PKC #A14	42-165-364980000	20		3212.0		4602.0		-1390.0		-1625.0		4837.0		235.0		0.57447		135.0	0.04527	N/A	6.111	N/A
PKC #A8	42-165-363140000	20		3200.0		4567.0		-1367.0		-1625.0		4825.0		258.0		0.48062		124.0	0.04567	N/A	5.663	N/A
PKC A-4	42-165-	20		3200.5		4560.0		-1359.5		-1625.0		4825.5		265.5		0.66290		176.0	0.03970	N/A	6.987	N/A
Crews Mast #9	42-165-364680000	21		3213.0		4652.0		-1439.0		-1625.0		4838.0		186.0		0.69624		129.5	0.05031	N/A	6.515	N/A
Lawrence #A2	42-165-364880000	21		3195.0		4580.0		-1385.0		-1625.0		4820.0		240.0		0.54375		130.5	0.04623	N/A	6.033	N/A
Thompson #B11	42-165-363190000	21		3198.0		4612.0		-1414.0		-1625.0		4823.0		211.0		0.42891		90.5	0.05134	N/A	4.646	N/A
Thompson #B12	42-165-363170000	21		3193.0		4625.0		-1432.0		-1625.0		4818.0		193.0		0.51554		99.5	0.04811	N/A	4.787	N/A
Thompson #B13	42-165-364900000	21		3196.0		4632.5		-1436.5		-1625.0		4821.0		188.5		0.48541		91.5	0.04891	N/A	4.475	N/A
Thompson B-3	42-165-	21		3200.0		4631.0		-1431.0		-1625.0		4825.0		194.0		0.48454		94.0	0.04144	N/A	3.895	N/A
Thompson B-5	42-165-	21		3199.0		4581.0		-1382.0		-1625.0		4824.0		243.0		0.49383		120.0	0.04294	N/A	5.153	N/A
Thompson B-8	42-165-	21		3195.0		4620.0		-1425.0		-1625.0		4820.0		200.0		0.48500		97.0	0.04150	N/A	4.026	N/A
Winkles-1	42-165-	22		3209.0		4592.0		-1383.0		-1625.0		4834.0		242.0		0.41322		100.0	0.04249	N/A	4.249	N/A
Winkles-2	42-165-	22		3215.0		4636.0		-1421.0		-1625.0		4840.0		204.0		0.50980		104.0	0.03975	N/A	4.134	N/A
Winkles-3	42-165-	22		3217.0		4632.0		-1415.0		-1625.0		4842.0		210.0		0.52381		110.0	0.04218	N/A	4.640	N/A
Metzger #1	42-165-	11		3220.0		4592.0		-1372.0		-1625.0		4845.0		253.0		0.59289		150.0	N/A	N/A	N/A	N/A
Collins #1	42-165-	12		3249.0		4630.0		-1381.0		-1625.0		4874.0		244.0		0.26230		64.0	N/A	N/A	N/A	N/A
Colgan State “A” #2	42-165-	19		3225.0		4566.0		-1341.0		-1625.0		4850.0		284.0		0.24296		69.0	N/A	N/A	N/A	N/A
McConal-Clark-4	42-165-	19		3224.0		4574.0		-1350.0		-1625.0		4849.0		275.0		0.43636		120.0	N/A	N/A	N/A	N/A
Lawrence “C” #1-X	42-165-	20		3209.0		4554.0		-1345.0		-1625.0		4834.0		280.0		0.55357		155.0	N/A	N/A	N/A	N/A
Lawrence “D” #1X	42-165-	20		3209.0		4625.0		-1416.0		-1625.0		4834.0		209.0		0.62201		130.0	N/A	N/A	N/A	N/A
Lawrence “D” #2	42-165-	20		3208.0		4617.0		-1409.0		-1625.0		4833.0		216.0		0.50000		108.0	N/A	N/A	N/A	N/A
Lawrence B-1	42-165-	20		3199.0		4568.0		-1369.0		-1625.0		4824.0		256.0		0.36328		93.0	N/A	N/A	N/A	N/A

William M. Cobb & Associates, Inc. EXHIBIT 3, page 2

Carm-Ann Petrophysical Summary — Net Pay Cutoffs: Porosity =/> 0.030 & Vcl </= 0.485

Well	API		KB Elevation		San Andres				SS LKO		MD LKO		Gross Interval		Net-to-Gross		Net Pay		Avg Phi	Avg Sw	PhiH	HPT
Name and Number	Number	Section	Feet		MD Top, Feet		SS Top, Feet		Feet		Feet		Feet		Fraction		Feet		Fraction	Fraction	Feet	Feet
Lawrence B-2	42-165-	20		3200.0		4564.0		-1364.0		-1625.0		4825.0		261.0		0.54406		142.0	N/A	N/A	N/A	N/A
Lawrence B-3	42-165-	20		3197.0		4578.0		-1381.0		-1625.0		4822.0		244.0		0.69262		169.0	N/A	N/A	N/A	N/A
Lawrence B-4	42-165-	20		3193.0		4588.0		-1395.0		-1625.0		4818.0		230.0		0.55652		128.0	N/A	N/A	N/A	N/A
Lawrence C-3	42-165-	20		3202.0		4574.0		-1372.0		-1625.0		4827.0		253.0		0.56522		143.0	N/A	N/A	N/A	N/A
Lawrence C-4	42-165-	20		3201.0		4580.0		-1379.0		-1625.0		4826.0		246.0		0.58943		145.0	N/A	N/A	N/A	N/A
PKC “A” #3	42-165-	20		3209.0		4572.0		-1363.0		-1625.0		4834.0		262.0	#VALUE!		NDE		N/A	N/A	N/A	N/A
PKC #5	42-165-	20		3213.5		4574.0		-1360.5		-1625.0		4838.5		264.5		0.46125		122.0	N/A	N/A	N/A	N/A
PKC #9	42-165-	20		3201.0		4600.0		-1399.0		-1625.0		4826.0		226.0		0.65044		147.0	N/A	N/A	N/A	N/A
Eliz Crews Mast-1	42-165-	21		3192.0		4608.0		-1416.0		-1625.0		4817.0		209.0		0.49761		104.0	N/A	N/A	N/A	N/A
Eliz Crews Mast-2	42-165-	21		3193.0		4638.0		-1445.0		-1625.0		4818.0		180.0		0.56667		102.0	N/A	N/A	N/A	N/A
Eliz Crews Mast-3	42-165-	21		3204.0		4680.0		-1476.0		-1625.0		4829.0		149.0		0.59060		88.0	N/A	N/A	N/A	N/A
Eliz Crews Mast-4	42-165-	21		3200.0		4670.0		-1470.0		-1625.0		4825.0		155.0		0.65806		102.0	N/A	N/A	N/A	N/A
Eliz. Crews Mast #5	42-165-360310000	21		3199.0		4648.0		-1449.0		-1625.0		4824.0		176.0		0.63068		111.0	N/A	N/A	N/A	N/A
Eliz. Crews Mast #6	42-165-361090000	21		3198.0		4666.0		-1468.0		-1625.0		4823.0		157.0		0.45860		72.0	N/A	N/A	N/A	N/A
Thompson “B” #6	42-165-360630000	21		3201.0		4646.0		-1445.0		-1625.0		4826.0		180.0		0.67778		122.0	N/A	N/A	N/A	N/A
Thompson “B” #7	42-165-361460000	21		3195.0		4636.0		-1441.0		-1625.0		4820.0		184.0		0.73913		136.0	N/A	N/A	N/A	N/A
Thompson B-9	42-165-	21		3195.0		4618.0		-1423.0		-1625.0		4820.0		202.0		0.63366		128.0	N/A	N/A	N/A	N/A
PKC “A” #7	42-165-359700000			3200.0		4630.0		-1430.0		-1625.0		4825.0		195.0		0.69231		135.0	N/A	N/A	N/A	N/A
Weighted Averages				3206.9		4586.1		-1376.5		-1625.0				248.5		0.4885		121.9	0.04466	0.32440	5.446	4.071

William M. Cobb & Associates, Inc. EXHIBIT 3, page 3

EXHIBIT 4

San Andres Net Pay Map
Carm-Ann Field
Gaines County, Texas

William M. Cobb & Associates, Inc.

Proposed Carm-Ann Unit	Cum. =	1,875,924 BBL
	Rem. =	500,171 BBL
	Ult. =	2,376,095 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 1

Tract 1 — Simmons	Cum. =	38,093 BBL
	Rem. =	7,798 BBL
	Ult. =	45,891 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 2

Tract 2 — Coast	Cum. =	4,867 BBL
	Rem. =	0 BBL
	Ult. =	4,867 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 3

Tract 3 — Metzger	Cum. =	35,940 BBL
	Rem. =	14,037 BBL
	Ult. =	49,977 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 4

Tract 4 — PKC	Cum. =	279,934 BBL
	Rem. =	196,467 BBL
	Ult. =	476,401 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 5

Tract 5 — Akers	Cum. =	52,682 BBL
	Rem. =	18,716 BBL
	Ult. =	71,398 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 6

Tract 6 — Yeager	Cum. =	45,512 BBL
	Rem. =	0 BBL
	Ult. =	45,512 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 7

Tract 7 — Mabee	Cum. =	38,656 BBL
	Rem. =	0 BBL
	Ult. =	38,656 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 8

Tract 8 — McConal-Clark	Cum. =	218,796 BBL
	Rem. =	22,878 BBL
	Ult. =	241,674 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 9

Tract 9 — Colgan State ‘A’	Cum. =	169,062 BBL
	Rem. =	20,209 BBL
	Ult. =	189,271 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 10

Tract 10 — Lawrence ‘C’	Cum. =	218,610 BBL
	Rem. =	37,368 BBL
	Ult. =	255,978 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 11

Tract 11 — Lawrence ‘D’	Cum. =	92,741 BBL
	Rem. =	23,393 BBL
	Ult. =	116,134 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 12

Tract 12 — PKC ‘A’	Cum. =	197,433 BBL
	Rem. =	18,074 BBL
	Ult. =	215,507 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 13

Tract 13 — Lawrence ‘B’	Cum. =	155,240 BBL
	Rem. =	37,681 BBL
	Ult. =	192,921 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 14

Tract 14 — Lawrence ‘A’	Cum. =	43,018 BBL
	Rem. =	20,973 BBL
	Ult. =	63,991 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 15

Tract 15 — Thompson ‘B’	Cum. =	170,636 BBL
	Rem. =	49,410 BBL
	Ult. =	220,046 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 16

Tract 16 — Elizabeth Crews Mast	Cum. =	114,704 BBL
	Rem. =	33,167 BBL
	Ult. =	147,871 BBL

William M. Cobb & Associates, Inc. EXHIBIT 5, page 17

Carm-Ann Tracts

			Area		Volume		OOIP1		2008		Tract Oil Recovery from Decline Curve Analysis
Tract		Lease(s)	Acres		Acre-Feet		STB		BBL Oil		BOPM 1/09		De - %/yr			Act. Wells		Rem. STB		Cum. STB		EUR STB		%OOIP
	1	Simmons		160.0		1,848.21		382,609		2,019		175		20.0	%		1		7,798		38,093		45,891		11.99	%
	2	Coast		40.0		1,407.17		291,307		0		0		0.0	%		0		0		4,867		4,867		1.67	%
	3	Metzger		80.0		2,826.18		585,065		1,099		90		5.0	%		1		14,037		35,940		49,977		8.54	%
	4	PKC		240.0		11,594.92		2,400,335		50,405		5,100		25.0	%		13		196,467		279,934		476,401		19.85	%
	5	Akers		40.0		2,874.73		595,115		1,223		110		5.0	%		1		18,716		52,682		71,398		12.00	%
	6	Yeager		40.0		3,946.09		816,904		0		0		0.0	%		1		0		45,512		45,512		5.57	%
	7	Mabee		40.0		1,038.18		214,920		0		0		0.0	%		0		0		38,656		38,656		17.99	%
	8	McConal-Clark		120.0		12,143.66		2,513,933		12,684		800		30.0	%		4		22,878		218,796		241,674		9.61	%
	9	Colgan State “A”		53.0		4,811.50		996,058		8,903		620		27.0	%		3		20,209		169,062		189,271		19.00	%
	10	Lawrence “C”		80.0		6,454.11		1,336,105		16,769		1,160		27.0	%		6		37,368		218,610		255,978		19.16	%
	11	Lawrence “D”		80.0		3,421.99		708,407		7,005		525		20.0	%		3		23,393		92,741		116,134		16.39	%
	12	PKC “A”		80.0		11,579.82		2,397,209		15,669		900		38.0	%		6		18,074		197,433		215,507		8.99	%
	13	Lawrence “B”		80.0		11,403.02		2,360,609		20,841		1,300		30.0	%		6		37,681		155,240		192,921		8.17	%
	14	Lawrence “A”		40.0		4,118.23		852,540		5,896		450		20.0	%		2		20,973		43,018		63,991		7.51	%
	15	Thompson “B”		160.0		12,594.17		2,607,196		18,433		1,400		24.0	%		9		49,410		170,636		220,046		8.44	%
	16	Elizabeth Crews Mast		320.0		11,674.29		2,416,766		10,284		755		17.0	%		8		33,167		114,704		147,871		6.12	%
				1,653.0		103,736.27		21,475,079		171,230		13,385							500,171		1,875,924		2,376,095		11.06	%

1parameters: porosity =	0.0450
Swc =	0.3240
Boi (RB/STB) =	1.1400

William M. Cobb & Associates, Inc. EXHIBIT 6

Secondary Recovery Potential for Carm-Ann Tracts

															S/P = 1.20
			Area		Volume		OOIP1		Primary Recovery from Performance						Secondary
Tract		Lease(s)	Acres		Acre-Feet		STB		Rem. STB		Cum. STB		EUR STB		STB
	1	Simmons		160.0		1,848.21		382,609		7,798		38,093		45,891		55,069
	2	Coast		40.0		1,407.17		291,307		0		4,867		4,867		5,840
	3	Metzger		80.0		2,826.18		585,065		14,037		35,940		49,977		59,972
	4	PKC		240.0		11,594.92		2,400,335		196,467		279,934		476,401		571,681
	5	Akers		40.0		2,874.73		595,115		18,716		52,682		71,398		85,677
	6	Yeager		40.0		3,946.09		816,904		0		45,512		45,512		54,614
	7	Mabee		40.0		1,038.18		214,920		0		38,656		38,656		46,387
	8	McConal-Clark		120.0		12,143.66		2,513,933		22,878		218,796		241,674		290,009
	9	Colgan State “A”		53.0		4,811.50		996,058		20,209		169,062		189,271		227,125
	10	Lawrence “C”		80.0		6,454.11		1,336,105		37,368		218,610		255,978		307,173
	11	Lawrence “D”		80.0		3,421.99		708,407		23,393		92,741		116,134		139,361
	12	PKC “A”		80.0		11,579.82		2,397,209		18,074		197,433		215,507		258,608
	13	Lawrence “B”		80.0		11,403.02		2,360,609		37,681		155,240		192,921		231,506
	14	Lawrence “A”		40.0		4,118.23		852,540		20,973		43,018		63,991		76,789
	15	Thompson “B”		160.0		12,594.17		2,607,196		49,410		170,636		220,046		264,056
	16	Elizabeth Crews Mast		320.0		11,674.29		2,416,766		33,167		114,704		147,871		177,445
				1,653.0		103,736.27		21,475,079		500,171		1,875,924		2,376,095		2,851,314

1parameters: porosity =	0.0450
Swc =	0.3240
Boi (RB/STB) =	1.1400

William M. Cobb & Associates, Inc. EXHIBIT 7

APPENDIX A

Carm-Ann San Andres

Single Pattern Model

William M. Cobb & Associates, Inc. APPENDIX A, Page 1

Model Description

•	Black oil simulation model (Merlin)
•	Single 40 acre pattern
	—Two total wells
	—20 acre spacing
•	20 vertical layers
	—Constant net pay of 2.5 feet per layer
	—Variable porosity and permeability

William M. Cobb & Associates, Inc. APPENDIX A, Page 2

Summary of Results

•	Primary recovery = 50.2 MBO or 12.77% OOIP
•	Waterflood recovery = 112.5 MBO or 28.62% OOIP
•	Incremental secondary recovery:
	—62.3 MBO or 15.9% OOIP
	—S/P ratio = 1.24

William M. Cobb & Associates, Inc. APPENDIX A, Page 3

Carm-Ann Pattern Model

Input Data

William M. Cobb & Associates, Inc. APPENDIX A, Page 4

William M. Cobb & Associates, Inc. APPENDIX A, Page 5

¹/4 well¹/4 well full well Producer in primary run, injector in waterflood run.¹/4 well¹/4 well

William M. Cobb & Associates, Inc. APPENDIX A, Page 6

Model Layer Properties

•	20 model layers
	—50’ total net pay
	—2.5’ per layer
•	One core — McConal Clark 8
•	Layer Perm’s from Dykstra-Parsons graph
	—Air perms
	—Ky = Kx
	—Kz = 0
•	Layer porosity from Por vs Perm plot

William M. Cobb & Associates, Inc. APPENDIX A, Page 7

William M. Cobb & Associates, Inc. APPENDIX A, Page 8

Core — McConal Clark 8 Well V-Factor = 0.71 Max. Perm = 10 md; 119 Perm Data Kmean = 0.5 md 100 Data Log Normal Distribution 10 20-Layer Model 20-Layer Dataset md PERMEABILITY, 1 0.1 0.01 2 4 6 8 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 92 94 96 98 CUMULATIVE PROBABILITY (PERCENT EQUAL TO OR GREATER THAN)

William M. Cobb & Associates, Inc. APPENDIX A, Page 9

McConal Clark 8 y = 0.7312Ln(x) + 4.7074 R² = 0.2753 12.0

10.0 8.0 6.0 4.0 2.0

0.0

0.001 0.010 0.100 1.000 10.000 100.000

William M. Cobb & Associates, Inc. APPENDIX A, Page 10

William M. Cobb & Associates, Inc. APPENDIX A, Page 11

Model PVT Properties

•	From industry correlations using
	—Oil gravity = 28oAPI
	—Gas gravity = 0.880
	—Rsi = 275 scf/STB from early production

William M. Cobb & Associates, Inc. APPENDIX A, Page 12

William M. Cobb & Associates, Inc. APPENDIX A, Page 13

Model Relative Permeability

•	Swc = 0.324 from log analysis
•	Kr curves from correlations
•	Gas/Oil curves
	—Tweaked to match general primary oil recovery factor
•	Oil/Water curves
	–Sorw estimated to be 35%

William M. Cobb & Associates, Inc. APPENDIX A, Page 14

William M. Cobb & Associates, Inc. APPENDIX A, Page 15

William M. Cobb & Associates, Inc. APPENDIX A, Page 16

Carm-Ann Model

Graphical Output

William M. Cobb & Associates, Inc. APPENDIX A, Page 17

William M. Cobb & Associates, Inc. APPENDIX A, Page 18

William M. Cobb & Associates, Inc. APPENDIX A, Page 19

William M. Cobb & Associates, Inc. APPENDIX A, Page 20

William M. Cobb & Associates, Inc. APPENDIX A, Page 21

William M. Cobb & Associates, Inc. APPENDIX A, Page 22

William M. Cobb & Associates, Inc. APPENDIX A, Page 23

William M. Cobb & Associates, Inc. APPENDIX A, Page 24

William M. Cobb & Associates, Inc. APPENDIX A, Page 25