SEC Letter

In response to your letter dated July 26, 2010 regarding PrimeEnergy Corporation (Registrant), the following reply has been prepared to address each of your comments. Each of your comments has been listed below and our response follows in italics. Please note that the Company desires to incorporate the information set forth below on a prospective basis, and respectfully requests that it be permitted to use such information with respect to its quarter ended September 30, 2010 and fiscal year ended December 31, 2010, subject to any further comments from the Staff.

Such disclosure should be set forth in the “Business” and “Risk Factors” section of your annual report and in the MD&A section of your periodic reports, as applicable. Please provide a sample of your proposed disclosure for our review. In responding to this comment, please consider all your current and planned operations, not just those involved in offshore operations.

Response: PrimeEnergy maintains insurance coverage against certain, but not all, hazards that could arise from its operations both onshore and offshore. Such insurance is believed to be reasonable for the hazards and risks faced by the Company.

As of December 31, 2009, the Company maintained for offshore operations total excess liability insurance with limits of $35 million per occurrence covering certain general liability and certain “sudden and accidental” environmental risks with a deductible of $10,000 per Occurrence, subject to all terms, restrictions and sub-limits of the policies.

The Company also maintained for onshore operations total excess liability insurance with limits of $20 million per occurrence covering certain general liability and certain “sudden and accidental” environmental risks with a deductible of $10,000 per Occurrence, subject to all terms, restrictions and sub-limits of the policies

We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include pollution liability in excess of limits sufficient to meet the legal financial responsibility requirement of the Minerals Management Service as prescribed under the Federal Oil Pollution Act and individual state legal financial responsibility requirements.

Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers and contractors. However, customers and contractors who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.

In April 2010, the Deepwater Horizon drilling rig, which was engaged in deepwater Gulf of Mexico drilling operations for another operator, sank after an explosion and fire. In response to this event and the resulting oil spill, certain federal agencies and governmental officials ordered a six-month moratorium on the drilling of new deepwater wells and a suspension of permitted wells currently being drilled in the deepwater Gulf of Mexico. The moratorium is scheduled to expire November 30, 2010. This event and its aftermath have created uncertainty with regard to offshore exploration and production activity, including future regulatory requirements, operational delays and cost increases. This may create some opportunities for acquisitions as other companies leave the Gulf of Mexico due to the perceived tightening of the regulatory environment. Currently none of our operations are conducted in deep water.

2. Describe the internal controls you use in your reserves estimation. Also, disclose the qualifications of the technical person primarily responsible for overseeing the preparation of the reserves estimates.

The Company provides data pertaining to ownership, royalty obligations, pricing, and operating costs along with geological maps and engineering data to the independent petroleum engineer in order to develop reverse estimates as required by guidelines established by the SEC or other required reporting organizations.

The Company compiles the data from various in-house resources and departments. All data is compiled from known historical information and compared or analyzed with current market or contract data. Pricing is obtained from payments received from purchasers which is compared and reviewed to associated contracts. The revenue department, which processes all revenue paid, reviews the prices and volumes paid. These procedures include testing the accuracy of the prices paid against current contractual obligations or current market indexes.

Joint interest bills are reviewed for accuracy and compared to required costs associated with the production and operation of the various wells. All ownership must be appropriately documented, prepared, and reviewed to comply with all necessary authoritative regulations governing land ownership issues.

Initial preparation of the in-house data is usually compiled by Company staff with knowledge and training in the particular area. Review procedures are performed by the appropriate level of management to provide assurance that data obtained and computed is accurate and verified. All data is verified to original source documents or external information sources when applicable. The data is checked for completeness, accuracy in preparation, compiled timely and presented clearly.

This data is then communicated to the independent petroleum engineer to enable them to prepare the reserve estimates the Company uses to satisfy its external requirements.

The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserves estimates can be found in the attached Exhibit A, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates.

3. We note you report proved undeveloped reserves as of December 31, 2009. Please disclose material changes in your proved undeveloped reserves that occurred during 2009, discuss investments and progress you have made during the year to develop these reserves and explain the reasons why material amounts of proved undeveloped reserves remain undeveloped for periods greater than five years to the extent you report such reserves. Refer to Item 1203 of Regulation S-K for additional guidance.

Our proved undeveloped reserves as of December 31, 2008 consisted of one prospect in the Gulf of Mexico awaiting completion. During 2009 this prospect was completed under a farm out agreement whereby the Company’s share of completion costs were carried by the outside working interest partners, therefore no capital expenditure by the Company was required. The Company has no proved undeveloped reserves that remain undeveloped for five years or more.

The Registrant proposes to add the following sentence to the end of each paragraph under District Information by geographical area starting on page 20 and ending on page 21. As of March 31, 2010 the Company has no wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

5. We note that your reserves have been evaluated by Ryder Scott Company, L.P., a third party engineering firm. Please provide the report from Ryder Scott as an exhibit to your filing to comply with Item 1202(a) (8) of Regulation S-K.

Response: See attached Exhibit A for the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates.

6. We note you present the non-GAAP measure PV 10 Value. Please provide a reconciliation of the differences between this non-GAAP measure and the most directly comparable GAAP measure to comply with Item 10(e)(l)(i)(B) of Regulation S-K.

Response: The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for the Company’s proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2009, are summarized as follows (figures rounded):

The PV 10 Value represents the discounted future net cash flows attributable to the Company’s proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with generally accepted accounting principles (GAAP), the Company believes that the presentation of the PV 10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. The Company uses this measure when assessing the potential return on investment related to oil and gas properties. The PV 10 of future income taxes represents the sole reconciling item between this non-GAAP PV 10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 23

7. MD&A requires not only a “discussion” but also an “analysis” of known material trends, events, demands, commitments and uncertainties. Consider revising to include an “Overview” section describing the most important matters on which you are focusing in evaluating your financial condition and operating performance. To enhance an investor’s understanding of your business, you should provide insight regarding material opportunities, challenges and risks on which you are focused in both the short and long changes from period to period, you state that “field service income decreased by 32.65% as a result of reduced utilization of equipment combined with rate decreases.” What were the reasons for the reduced utilization and rate decreases and how does this affect your short term and long term objectives? Quantify the amount of the decrease contributed by reduced utilization of equipment and the amount that was contributed by rate decreases. In all cases where one or more factors contribute to a change, quantify the amount of the change attributable to each factor. In revising your discussion in this section, please refer to the Commission’s Guidance Regarding Management’s Discussion and

Analysis of Financial Condition and Results of Operations. See SEC Release No. 33-8350, http://www.sec.gov/rules/interp/33-8350.htm and Release No. 33-6835, http://www.sec.gov/rules/interp/33-6835.htm. This comment also applies to all subsequently filed Quarterly Reports on Form 10-Q.

We note your comment about revising our discussion regarding the analysis of financial condition and results of operations. We will expand our future disclosures to include additional analysis regarding the variables and factors that affect our field service income. An “Overview” section to be added to the disclosure is shown below.

The Company presently owns producing and non-producing properties located primarily in Texas, Oklahoma, West Virginia, the Gulf of Mexico, New Mexico, Colorado and Louisiana, and owns a substantial amount of well servicing equipment. All of the Company’s oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility.

The Company attempts to assume the position of operator in all acquisitions of producing properties. The Company will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which it owns interests and is actively pursuing the acquisition of producing properties. In order to diversify and broaden its asset base, the Company will consider acquiring the assets or stock in other entities and companies in the oil and gas business. The main objective of the Company in making any such acquisitions will be to acquire income producing assets so as to increase the Company’s net worth and increase the Company’s oil and gas reserve base.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated income statement as changes occur in the NYMEX price indices.

8. We note your statement that there have been no significant changes in your internal controls over financial reporting during the fourth fiscal quarter ended December, 31, 2009. Please comply with Item 308(c) of Regulation S-K, which requires that you disclose any change in your internal control over financial reporting that occurred during the last fiscal quarter that has materially affected, or is reasonable likely to materially affect your internal control over financial reporting.

Response: There have been no changes in our internal controls over financial reporting during the fourth fiscal quarter ended December 31, 2009 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, page F-25

9. We note that you disclosed significant changes in estimates in 2009 and 2008. Please provide explanations for these changes. Refer to FASB ASC Topic 935-235-50-5 for additional guidance.

We revised our previous estimate of proved reserves downward by 17.35 Bcfe from 2008 to 2009. The revision was primarily due to a decrease of 14.65 Bcfe in our primary gas producing districts due to the shortened life of our marginal properties under the lower gas pricing used in the 2009 reserve report. Onshore our Appalachian, Gulf Coast and Mid-Continent districts decreased 4.4 Bcfe, 1.2 Bcfe and 6.6 Bcfe, respectively. Offshore our reserve estimate decreased 2.6 Bcfe.

The Audit Committee, composed of Messrs. Eckenstein, Hurt and Smeets, met once in 2009. The Board of Directors has determined that each member satisfies applicable requirements for independence and financial literacy. The Board of Directors has determined that Mr. Smeets meets the qualifications of an audit committee financial expert as defined by the Securities and Exchange Commission. The Committee selects and engages independent auditors to audit the books, records and accounts of the Company, determines the scope of such audits, and reviews the financial policies and control procedures of the Company. The report of the Audit Committee is included in this Proxy Statement on page 8. The Board of Directors and the Audit Committee have adopted a written charter for the Audit Committee, a copy of which is attached as Annex A to this Proxy Statement.

621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE (303) 623-9147

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of PrimeEnergy Corporation and 100% of its’ Partnership Interests (PrimeEnergy) of December 31, 2009. The subject properties are located in the states of Colorado, Kansas, Louisiana, Montana, Mississippi, New Mexico, Oklahoma, Texas, West Virginia and Wyoming and in the federal waters offshore Louisiana and Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study was prepared for public disclosure by PrimeEnergy Corporation in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The results of our third party study, completed on April 14, 2010, are presented herein. The properties reviewed by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of PrimeEnergy.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2009 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an as “sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C. The program was used solely at the request of PrimeEnergy. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs and development costs. The other deductions consist of net income adjustments supplied by PrimeEnergy and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 61 percent and gas reserves account for the remaining 39 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly.

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The developed non-producing reserves included herein consist of the Shut-In and Behind-Pipe categories.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The gas volumes included herein do not attribute gas consumed in operations as reserves.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The reserves included herein were estimated using deterministic methods.

Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Moreover, estimates of reserves may increase or decrease as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. As a result, the estimates of oil and gas reserves have an intrinsic uncertainty. The reserves included in this report are therefore estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

PrimeEnergy’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include matters relating to land tenure, drilling, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which PrimeEnergy owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 201.4(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The reserve evaluator must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. All quantities of reserves within the same reserve category have the same level of uncertainty under the SEC definitions.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The reserves for the properties included herein were estimated by performance methods, the volumetric method or analogy. Approximately 99 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include, but may not be limited to decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through December, 2009 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by PrimeEnergy Corporation and were considered sufficient for the purpose thereof. Approximately 1 percent of the proved producing reserves were estimated by the volumetric method. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

The proved non-producing and undeveloped reserves included herein were estimated by the volumetric method or analogy. Approximately 82% of the proved non-producing and undeveloped reserves were estimated by analogy. Approximately 18% of the proved non-producing and undeveloped reserves were estimated by the volumetric method. The volumetric analysis utilized pertinent well and seismic data supplied to Ryder Scott by PrimeEnergy Corporation that was available through December, 2009. The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof. In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein.

To estimate economically recoverable oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

PrimeEnergy has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future production and income, we have relied upon data furnished by PrimeEnergy with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, geological structural and isochore maps, well logs, core analyses,

and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data supplied by PrimeEnergy. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

Our forecasts of future production rates are based on historical performance from wells currently on production. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by PrimeEnergy.

The future production rates from wells currently on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates.

As previously stated, the hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described. Product prices which were actually used for each property reflect adjustment for gravity, quality, local conditions, and/or distance from market.

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations

Operating costs for the leases and wells in this report are based on the operating expense reports of PrimeEnergy and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The other deductions consist of net income adjustments supplied by PrimeEnergy and certain abandonment costs net of salvage. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by PrimeEnergy and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. This cost was included as other deductions. The estimates of the net abandonment costs furnished by PrimeEnergy were accepted without independent verification.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled. PrimeEnergy has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by PrimeEnergy were held constant throughout the life of the properties.

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to PrimeEnergy. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical persons primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

This report was prepared for the exclusive use and sole benefit of PrimeEnergy and may not be put to other use without our prior written consent for such use. Ryder Scott has consented to the inclusion of our report as an exhibit in filings by PrimeEnergy with the SEC, as well as to references to our name as necessary in such filings. Our written consent for such use is included as an exhibit to filings made by PrimeEnergy with the SEC.

We have provided PrimeEnergy with a digital version of the original signed copy of this report letter. PrimeEnergy has subsequently converted our digital version of the original document to a digital format as required for submission as part of their filing with the SEC. In the event of any differences between the digital document included in filings made by PrimeEnergy Corporation and the original document, the original document shall be definitive and take precedent over the digital document.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.


Very truly yours,

RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580

/s/ Richard J. Marshall		[SEAL]
Richard J. Marshall, P.E.
Colorado License No. 23260
Vice President

/s/ Michael F. Stell		[SEAL]
Michael F. Stell, P.E.
TBPE License No. 56416
Managing Senior Vice President

* The work performed in this report for properties located in the state of Texas has been reviewed and approved by a licensed Texas professional engineer according to the rules of the Texas Board of Professional Engineers (TBPE).

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Richard J. Marshall was the primary technical person responsible for overseeing the estimate of the future net reserves and income.

Marshall, an employee of Ryder Scott Company L.P. (Ryder Scott) beginning in 1981, is a Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies. Before joining Ryder Scott, Marshall served in a number of engineering positions with Texaco, Phillips Petroleum, and others. For more information regarding Mr. Marshall’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Marshall earned a B.S. in Geology from the University of Missouri in 1974 and a M.S. in Geological Engineering from the University of Missouri at Rolla in 1976. Marshall is a registered Professional Engineer in the State of Colorado. He is a member of the Society of Petroleum Engineers, Wyoming Geological Association, Rocky Mountain Association of Geologists and the Society of Petroleum Evaluation Engineers.

Based on Marshall’s educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Marshall has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Michael F. Stell was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.

Mr. Stell, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1992, is a Managing Senior Vice President and also serves as an Engineering Group Leader responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company and Landmark Concurrent Solutions. For more information regarding Mr. Stell’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.php.

Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Stell fulfills. As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13 hours of formalized training as well as a day-long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Stell attended an additional 15 hours of formalized in-house training as well as an additional five hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and almost 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC Regulations”. The SEC Regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10 (a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein).

Reserves are those estimated remaining quantities of petroleum which are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein.)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.


	Proved Developed			Proved Undeveloped		Total
As of 12-31	Future Net Revenue		Present Value 10 Of Future Net Revenue	Future Net Revenue	Present Value 10 Of Future Net Revenue	Future Net Revenue	Present Value 10 Of Future Net Revenue	Present Value 10 Of Future Income Taxes	Standardized Measure of Discounted Cash flow
2007	$	449,372,000	266,405,000	60,392,000	21,062,000	509,764,000	287,467,000	62,007,000	225,460,000
2008	$	206,400,000	132,654,000	1,502,000	1,515,000	207,902,000	134,169,000	17,635,000	116,534,000
2009	$	178,272,000	110,613,000	44,792,000	10,388,000	223,064,000	121,001,000	18,260,000	102,742,000


	Proved
	Developed				Undeveloped		Other Deductions			Total Proved
	Producing		Non-Producing		Undeveloped		Other Deductions			Total Proved
*Net Remaining Reserves*
Oil/Condensate – Barrels		4,308,355		167,753		1,610,610		0			6,086,718
Gas – MMCF		34,535		3,854		7,024		0			45,413

*Income Data*
Future Gross Revenue	$	393,720,162	$	26,121,650	$	129,262,467	$	0		$	549,104,279
Deductions		209,756,495		14,717,314		84,470,064		17,096,300			326,040,173

Future Net Income (FNI)	$	183,963,667	$	11,404,336	$	44,792,403	$	(17,096,300	)	$	223,064,106

Discounted FNI @ 10%	$	113,786,624	$	5,373,309	$	10,388,346	$	(8,546,750	)	$	121,001,529


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