PRIMEENERGY RESOURCES CORP - Quarter Report: 2011 September (Form 10-Q)

PRIMEENERGY RESOURCES CORP - Quarter Report: 2011 September (Form 10-Q)

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FORM 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended September 30, 2011

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

For the Transition Period From to

Commission File Number 0-7406

PrimeEnergy Corporation

(Exact name of registrant as specified in its charter)

Delaware

84-0637348

(State or other jurisdiction of

incorporation or organization)

(I.R.S. employer

Identification No.)

One Landmark Square, Stamford, Connecticut 06901

(Address of principal executive offices)

(203) 358-5700

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filings required for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The number of shares outstanding of each class of the Registrant’s Common Stock as of November 8, 2011 was: Common Stock, $0.10 par value 2,718,893 shares.

PrimeEnergy Corporation

Index to Form 10-Q

September 30, 2011


	Page
Part I - Financial Information

Item 1. Financial Statements

Condensed Consolidated Balance Sheets – September 30, 2011 and December 31, 2010		3

Condensed Consolidated Statements of Operations – Nine and Three Months Ended September 30, 2011 and 2010		4

Condensed Consolidated Statement of Stockholders’ Equity – Nine Months Ended September 30, 2011		5

Condensed Consolidated Statement of Comprehensive Income – Nine Months Ended September 30, 2011 and 2010		6

Condensed Consolidated Statement of Cash Flows – Nine Months Ended September 30, 2011 and 2010		7

Notes to Condensed Consolidated Financial Statements – September 30, 2011		8-14

Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation		15-18

Item 3. Quantitative and Qualitative Disclosures About Market Risk		18

Item 4. Controls and Procedures		18

Part II - Other Information

Item 1. Legal Proceedings		19

Item 1A. Risk Factors		19

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		19

Item 3. Defaults Upon Senior Securities		19

Item 4. Reserved		19

Item 5. Other Information		19

Item 6. Exhibits		20-21

Signatures		22

PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

PrimeEnergy Corporation

Condensed Consolidated Balance Sheets – Unaudited

(Thousands of dollars)


	September 30, 2011			December 31, 2010
ASSETS
Current assets
Cash and cash equivalents	$	13,048		$	32,792
Restricted cash and cash equivalents		7,267			6,131
Accounts receivable, net		12,706			12,748
Other current assets		6,065			6,082

Total current assets		39,086			57,753

Property and equipment, at cost
Oil and gas properties (successful efforts method), net		128,715			143,034
Field service equipment and other, net		7,990			6,794

Net property and equipment		136,705			149,828
Other assets		3,864			579

Total assets	$	179,655		$	208,160

LIABILITIES and STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	27,434		$	34,376
Accrued liabilities		7,326			7,676
Current portion of asset retirement and other long-term obligations		12,439			2,206
Derivative liability short term		—			3,048
Due to related parties		255			350

Total current liabilities		47,454			47,656

Long-term bank debt		69,500			73,100
Indebtedness to related parties		—			20,000
Asset retirement obligations		7,069			15,285
Derivative liability long term		—			2,587
Deferred income taxes		18,559			16,445
Stockholders’ equity
Common stock, $.10 par value; 2011 and 2010: Authorized: 4,000,000 shares, issued: 3,836,397 shares; outstanding 2011: 2,731,329 shares; outstanding 2010: 2,802,053 shares		383			383
Paid in capital		6,370			5,955
Retained earnings		51,571			46,478
Treasury stock, at cost; 2011: 1,105,068 shares; 2010 1,034,344 shares		(30,529	)		(28,896	)

Total stockholders’ equity – PrimeEnergy		27,795			23,920

Non-controlling interest		9,278			9,167

Total stockholders’ equity		37,073			33,087

Total liabilities and stockholders’ equity	$	179,655		$	208,160

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

PrimeEnergy Corporation

Condensed Consolidated Statements of Operations – Unaudited

(Thousands of dollars, except per share amounts)


	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011		2010
Revenues
Oil and gas sales	$	21,757	$	18,745		$	65,236	$	61,028
Realized gain on derivative instruments, net		4,295		1,012			4,431		2,563
Field service income		5,407		4,349			15,181		12,192
Administrative overhead fees		2,150		2,188			6,488		6,336
Unrealized gain (loss) on derivative instruments, net		12,511		(2,181	)		9,015		7,062
Other income		20		6			69		199

Total revenue		46,140		24,119			100,420		89,380

Costs and expenses
Lease operating expense		9,711		7,724			26,520		25,261
Field service expense		4,393		3,605			12,537		10,138
Depreciation, depletion and amortization and accretion on discounted liabilities		22,899		7,309			40,930		24,238
General and administrative expense		3,179		3,840			10,216		9,817
Exploration costs		7		87			15		92

Total costs and expenses		40,189		22,565			90,218		69,546

Gain on sale and exchange of assets		1,375		1,336			1,608		1,686

Income from operations		7,326		2,890			11,810		21,520

Other income and expenses
Less: Interest expense		685		1,633			3,035		5,266
Add: Interest income		2		10			87		32

Income before provision for income taxes		6,643		1,267			8,862		16,286

Provision for income taxes		1,899		142			2,357		4,776

Net income		4,744		1,125			6,505		11,510

Less: Net income attributable to non-controlling interest		471		327			1,412		1,037

Net income attributable to PrimeEnergy	$	4,273	$	798		$	5,093	$	10,473

Basic income per common share	$	1.56	$	0.28		$	1.85	$	3.54

Diluted income per common share	$	1.23	$	0.22		$	1.46	$	2.84

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

PrimeEnergy Corporation

Condensed Consolidated Statement of Stockholders’ Equity – Unaudited

Nine Months Ended September 30, 2011

(Thousands of dollars)


	Common Stock				Additional Paid in Capital		Retained Earnings		Treasury Stock			Total Stockholders’ Equity – PrimeEnergy			Non- Controlling Interest			Total Stockholders’ Equity
	Shares		Amount		Additional Paid in Capital		Retained Earnings		Treasury Stock			Total Stockholders’ Equity – PrimeEnergy			Non- Controlling Interest			Total Stockholders’ Equity
Balance at December 31, 2010,		3,836,397	$	383	$	5,955	$	46,478	$	(28,896	)	$	23,920		$	9,167		$	33,087
Purchase 70,724 shares of common stock		—		—		—		—		(1,633	)		(1,633	)		—			(1,633	)
Net income		—		—		—		5,093		—			5,093			1,412			6,505
Purchase of non-controlling interests		—		—		415		—		—			415			(607	)		(192	)
Distributions to non-controlling interests		—		—		—		—		—			—			(694	)		(694	)

Balance at September 30, 2011		3,836,397	$	383	$	6,370	$	51,571	$	(30,529	)	$	27,795		$	9,278		$	37,073

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

PrimeEnergy Corporation

Condensed Consolidated Statements of Comprehensive Income – Unaudited

(Thousands of dollars)


	Nine Months Ended September 30,
	2011		2010
Net income	$	6,505	$	11,510
Other comprehensive income, net of taxes:
Reclassification adjustment for settled contracts, net of taxes of $0 and $125,000, respectively		—		222
Changes in fair value of hedge positions, net of taxes of $0 and $5,000, respectively		—		(8	)

Total other comprehensive income		—		214

Comprehensive income		6,505		11,724
Less: Comprehensive income attributable to non-controlling interest		1,412		1,037

Comprehensive income attributable to PrimeEnergy	$	5,093	$	10,687

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

PrimeEnergy Corporation

Condensed Consolidated Statements of Cash Flows – Unaudited

(Thousands of dollars)


	Nine Months Ended September 30,
	2011			2010
OPERATING ACTIVITIES

Net Income	$	5,093		$	10,473

Adjustments to reconcile net income to net cash provided by operating activities:
Non-controlling interest in earnings of partnerships		1,412			1,037
Depreciation, depletion, amortization and accretion on discounted liabilities		40,930			24,238
Gain on sale of properties		(1,608	)		(1,684	)
Unrealized gain on derivative instruments, net		(9,015	)		(7,062	)
Provision for deferred income taxes		2,114			6,944

Changes in assets and liabilities:
(Increase) decrease in accounts receivable		42			(775	)
(Increase) decrease in other assets		(24	)		454
Increase (decrease) in accounts payable		(8,078	)		3,764
Increase in accrued liabilities		229			566
Increase (decrease) in due to related parties		41			(213	)

Net cash provided by operating activities		31,136			37,742

INVESTING ACTIVITIES

Capital expenditures, including exploration expense		(26,913	)		(9,621	)
Proceeds from sale of properties and equipment		1,855			1,686

Net cash used in investing activities		(25,058	)		(7,935	)

FINANCING ACTIVITIES

Purchase of stock for treasury		(1,633	)		(2,370	)
Purchase of non-controlling interests		(192	)		(6	)
Proceeds from long-term bank debt and other long-term obligations		64,831			48,270
Repayment of long-term bank debt and other long-term obligations		(68,134	)		(74,167	)
Repayment of indebtedness to related parties		(20,000	)		—
Distribution to non-controlling interest		(694	)		(818	)

Net cash used in financing activities		(25,822	)		(29,091	)

Net increase (decrease) in cash and cash equivalents		(19,744	)		716
Cash and cash equivalents at the beginning of the period		32,792			11,779

Cash and cash equivalents at the end of the period	$	13,048		$	12,495

SUPPLEMENTAL DISCLOSURES

Income taxes paid	$	1,211		$	2,167
Income tax refunds received during the year	$	41		$	—
Interest paid	$	3,400		$	5,266
Change in accrued expenses relating to property	$	579		$	1,315

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

PrimeEnergy Corporation

Notes to Condensed Consolidated Financial Statements

September 30, 2011

(Unaudited)

(1) Interim Financial Statements:

The accompanying condensed consolidated financial statements of PrimeEnergy Corporation (“PEC” or the “Company”) have not been audited by independent public accountants. During the interim periods, the Company follows the same accounting policies as used and described in its Annual Report on Form 10-K for the year ended December 31, 2010. In accordance with applicable Securities and Exchange Commission (“SEC”) rules and regulations, the accompanying interim financial statements do not include all disclosures presented in annual financial statements and the reader should refer to the Company’s Form 10-K for the year ended December 31, 2010 filed with the SEC on April 7, 2011. In the opinion of management, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the Company’s Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010, the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2010, the Condensed Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2011, and the Condensed Consolidated Statements of Comprehensive Income and Cash Flows for the nine months ended September 30, 2011 and 2010. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the condensed consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.

Recently Issued Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04 “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRSs”. This ASU amends previously issued authoritative guidance and requires new disclosures, clarifies existing disclosures and is effective for interim and annual periods beginning after December 15, 2011. Early application by public entities is not permitted. The amendments change requirements for measuring fair value and disclosing information about those measurements. Additionally, this ASU clarifies the FASB’s intent regarding the application of existing fair value measurement requirements and changes certain principles or requirements for measuring fair value or disclosing information about its measurements. For many of the requirements, the FASB does not intend the amendments to change the application of the existing Fair Value Measurements guidance. The Company does not expect this guidance to have a significant impact on its financial position, results of operations or cash flows.

In June 2011, the FASB issued ASU No. 2011-05, “Presentation of Comprehensive Income”, which amends current comprehensive income guidance. This accounting update eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. The new requirements are effective for public entities for interim and annual periods beginning after December 15, 2011 with early adoption permitted. The adoption of this ASU will not have an impact on the Company’s consolidated financial position, results of operations or cash flows as it only requires a change in the format of the current presentation.

In September 2011, the FASB issued ASU No. 2011-08, “Testing Goodwill for Impairment”, which amends the current goodwill impairment testing guidance. Under this accounting update, entities have the option of performing a qualitative assessment before calculating the fair value of the reporting unit when testing goodwill for impairment. If the fair value of the reporting unit is determined, based on qualitative factors, to be more likely than not less than the carrying amount of the reporting unit, then entities are required to perform the two-step goodwill impairment test. This ASU is effective for fiscal years beginning after December 15, 2011, with early adoption permitted. The adoption of this ASU will not have an impact on the Company’s consolidated financial position, results of operations or cash flows as it is a change in application of the goodwill impairment test only.

(2) Acquisitions and Dispositions:

Historically the Company has repurchased the interests of the partners and trust unit holders in the eighteen oil and gas limited partnerships (the “Partnerships”) and the two asset and business income trusts (the “Trusts”) managed by the Company as general partner and as managing trustee, respectively. The Company purchased such interests in an amount totaling $192,000 and $6,000 for the nine months ended September 30, 2011and 2010, respectively.

(3) Restricted Cash and Cash Equivalents:

Restricted cash and cash equivalents include $7,267,000 and $6,131,000 at September 30, 2011 and December 31, 2010, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at September 30, 2011 and December 31, 2010 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the Condensed Consolidated Balance Sheet.

(4) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:


(Thousands of dollars)	September 30, 2011		December 31, 2010
Accounts Receivable:
Joint interest billing	$	2,547	$	2,538
Trade receivables		2,075		1,688
Oil and gas sales		8,352		8,139
Other		131		724

		13,105		13,089
Less: Allowance for doubtful accounts		399		341

Total	$	12,706	$	12,748

Accounts Payable:
Trade	$	4,073	$	3,421
Royalty and other owners		12,194		10,395
Prepaid drilling deposits		4,134		12,871
Other		7,033		7,689

Total	$	27,434	$	34,376

Accrued Liabilities:
Compensation and related expenses	$	3,426	$	2,010
Property costs		2,758		3,282
Income tax		3		930
Other		1,139		1,454

Total	$	7,326	$	7,676

(5) Property and Equipment:

Property and equipment at September 30, 2011 and December 31, 2010 consisted of the following:


(Thousands of dollars)	September 30, 2011		December 31, 2010
Proved oil and gas properties, at cost	$	476,679	$	453,145
Unproved oil and gas properties, at cost		—		698
Less: Accumulated depletion and depreciation		347,964		310,809

	$	128,715	$	143,034

Field service equipment and other	$	21,306	$	19,499
Less: Accumulated depreciation		13,316		12,705

	$	7,990	$	6,794

Total net property and equipment	$	136,705	$	149,828

(6) Long-Term Bank Debt:

Bank Debt:

Effective June 22, 2011, the Company entered into a Second Amendment to the Second Amended and Restated Credit Agreement (“Second Amendment”). The Second Amendment to this $250 million credit facility increased the Company’s borrowing base to $125 million; removed the floor rate component of LIBO rate loans; modified financial reporting requirements to the agent; increased hedging allowances; and allowed for a one-time advance to be made to the Company’s offshore subsidiary. Subject to facility borrowing base availability amounts, the banks approved a one-time advance of up to $16 million to be made from PEC to its offshore subsidiary specifically to be used to pay in full the offshore subsidiary’s

indebtedness to a related party. The banks required this advance to be made within 30 days after the effective date of the Second Amendment and the Company completed the advance to its offshore subsidiary on June 24, 2011. Under the Second Amendment, the maximum percentage of production available to enter into commodity hedge agreements was revised to 90% from 85% of proved developed producing reserves for each of the next succeeding four calendar years for crude oil and natural gas computed separately. In addition, following the Second Amendment the Company’s restriction on payments for dividends, distributions or repurchase of PEC’s stock was increased from $1.0 million to $2.5 million in each calendar year. Borrowing base monthly reduction amounts remain at $2 million with the first reduction to now begin on December 15, 2011.

The Company’s borrowing rates in the credit facility provide for base rate loans at the prime rate (3.25% at September 30, 2011) plus applicable margin utilization rates that range from 1.75% to 2.0%, and LIBO rate loans at LIBO published rates plus applicable utilization rates (2.75% to 3.00% at September 30, 2011). As of September 30, 2011, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 5.00% and 2.97%, respectively.

At September 30, 2011, the Company had $69.5 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 4.05% and $55.5 million available for future borrowings. The combined weighted average interest rates paid on outstanding bank borrowings subject to base rate and LIBO interest were 5.04% during the first nine months of 2011 as compared to 6.11% during the same period in 2010.

Indebtedness to related parties:

Effective January 3, 2011, the Company’s loan with a private lender that is controlled by a Director of PEC was modified and provided for a payment from the Company’s offshore subsidiary to the private lender of $4.0 million. On January 18, 2011, the Company’s offshore subsidiary made a $4.0 million payment on this loan. Further, on June 27, 2011, this loan along with all accrued interest was paid in full from the Company’s offshore subsidiary and the note was cancelled.

(7) Other Long-Term Obligations and Commitments:

Operating Leases:

The Company has several non-cancelable operating leases, primarily for rental of office space, that have a term of more than one year. The future minimum lease payments for the rest of the fiscal 2011 and thereafter for the operating leases are as follows:


(Thousands of dollars)	Operating Leases
2011	$	202
2012		555
2013		434
2014		16

Total minimum payments	$	1,207

Rent expense for office space for the nine months ended September 30, 2011 and 2010 was $588,000 and $588,000, respectively.

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2011 is as follows:


(Thousands of dollars)
Asset retirement obligation – December 31, 2010	$	17,147
Liabilities incurred		315
Liabilities settled		(322	)
Accretion expense		1,727

Asset retirement obligation – September 30, 2011	$	18,867

The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates.

(8) Contingent Liabilities:

The Company, as managing general partner of the affiliated Partnerships, is responsible for all Partnership activities, including the drilling of development wells and the production and sale of oil and gas from productive wells. The Company also provides the administration, accounting and tax preparation work for the Partnerships, and is liable for all debts and liabilities of the affiliated Partnerships, to the extent that the assets of a given limited Partnership are not sufficient to satisfy its obligations. As of September 30, 2011, the affiliated Partnerships have established cash reserves in excess of their debts and liabilities and the Company believes these reserves will be sufficient to satisfy Partnership obligations.

The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.

From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.

(9) Stock Options and Other Compensation:

In May 1989, non-statutory stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At September 30, 2011 and 2010, options on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.

(10) Related Party Transactions:

The Company, as managing general partner or managing trustee, makes an annual offer to repurchase the interests of the partners and trust unit holders in certain of the Partnerships or Trusts. The Company purchased such interests in amounts totaling $192,000 and $6,000 for the nine months ended September 30, 2011 and 2010, respectively.

Receivables from related parties consist of reimbursable general and administrative costs, lease operating expenses and reimbursement for property development and related costs. These receivables are due from joint venture partners, which may include members of the Company’s Board of Directors.

Payables owed to related parties primarily represent receipts collected by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors, for oil and gas sales net of expenses. Also included in due to related parties at December 31, 2010 was the amount of accrued interest, $170,000, owed to a related party, a company controlled by a Director of the Company, with whom the Company’s offshore subsidiary entered into a credit agreement. This agreement was concluded as of June 2011 and all interest owed and the loan balance remaining was paid at that time.

(11) Financial Instruments

Fair Value measurements:

Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2011 and December 31, 2010:


September 30, 2011	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of September 30, 2011
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	6,422	$	6,422

Total assets	$	—	$	—	$	6,422	$	6,422

Liabilities
Commodity derivative contracts	$	—	$	—	$	—	$	—

Total liability	$	—	$	—	$	—	$	—


December 31, 2010	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance as of December 31, 2010
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	3,042		$	3,042

Total assets	$	—	$	—	$	3,042		$	3,042

Liabilities
Commodity derivative contracts	$	—	$	—	$	(5,635	)	$	(5,635	)

Total liability	$	—	$	—	$	(5,635	)	$	(5,635	)

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as level 3 in the fair value hierarchy for the nine months ended September 30, 2011.


(Thousands of dollars)
Net liabilities – December 31, 2010	$	(2,593	)
Total realized and unrealized gains or losses:
Included in earnings (a)		13,446
Purchases, sales, issuances and settlements		(4,431	)

Net assets – September 30, 2011	$	6,422

(a)	Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments.

Derivative Instrument:

The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity based derivatives. Both realized and unrealized gains and losses associated with derivative instruments are recognized in earnings.

The following table sets forth the effect of derivative instruments on the condensed consolidated balance sheets as of September 30, 2011 and December 31, 2010:


		Fair Value
(Thousands of dollars)	Balance Sheet Location	September 30, 2011		December 31, 2010
Asset Derivatives:
Derivatives not designated as hedging instruments:
Natural gas commodity contracts (a)	Other current assets	$	2,672	$	3,038
Crude oil commodity contracts	Other current assets		467		—
Natural gas commodity contracts (a)	Other assets		471		—
Crude oil commodity contracts	Other assets		2,812		4

Total		$	6,422	$	3,042

Liability Derivatives:
Derivatives not designated as hedging instruments:
Crude oil commodity contracts	Derivative liability short term	$	—	$	(3,048	)
Crude oil commodity contracts	Derivative liability long term		—		(2,587	)

Total		$	—	$	(5,635	)

Total derivative instruments		$	6,422	$	(2,593	)

(a)	Subsequent to September 30, 2011, the Company unwound and monetized natural gas swaps with original settlement dates from October 2011 through December 2012 for net proceeds of $2.9 million. These natural gas commodity contracts had an unrealized gain of $3.1 million at September 30, 2011.

The following table sets forth the effect of derivative instruments on the condensed consolidated statement of operations for the nine-month periods ended September 30, 2011 and 2010:


	Location of gain/loss reclassified from OCI into income	Amount of gain/loss reclassified from accumulated OCI into income
(Thousands of dollars)	Location of gain/loss reclassified from OCI into income	2011		2010
Derivatives designated as cash-flow hedges
Interest rate swap derivatives	Interest expense	$	—	$	(347	)

		$	—	$	(347	)


	Location of gain/loss recognized in income	Amount of gain/loss recognized in income
(Thousands of dollars)	Location of gain/loss recognized in income	2011		2010
Derivatives not designated as cash-flow hedge instruments
Natural gas commodity contracts	Unrealized gain on derivative instruments, net	$	106	$	4,026
Crude oil commodity contracts	Unrealized gain on derivative instruments, net		8,909		3,036
Natural gas commodity contracts	Realized gain on derivative instruments, net		2,969		2,659
Crude oil commodity contracts (a)	Realized gain (loss) on derivative instruments, net		1,462		(96	)

		$	13,446	$	9,625

(a)

In August 2011, the Company unwound and monetized crude oil swaps and collars with original settlement dates from September 2011 through December 2014 for net proceeds of $3.4 million. The $3.4 million gain associated with these early settlement transactions is included in realized gain on derivative instruments for the three and nine months ended September 30, 2011.

(12) Earnings Per Share:

Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the financial statements:


	Nine Months Ended September 30,
	2011						2010
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	5,093		2,758,388	$	1.85	$	10,473		2,954,433	$	3.54
Effect of dilutive securities:
Options		—		733,063				—		732,607

Diluted	$	5,093		3,491,451	$	1.46	$	10,473		3,687,040	$	2.84


	Three Months Ended September 30,
	2011						2010
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	4,273		2,744,177	$	1.56	$	798		2,870,453	$	0.28
Effect of dilutive securities:
Options		—		730,617				—		726,169

Diluted	$	4,273		3,474,794	$	1.23	$	798		3,596,622	$	0.22

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This report may contain statements relating to the future results of the Company that are considered “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 (the “PSLRA”). In addition, certain statements may be contained in the Company’s future filings with the SEC, in press releases, and in oral and written statements made by or with the approval of the Company that are not statements of historical fact and constitute forward-looking statements within the meaning of the PSLRA. Such forward-looking statements, in addition to historical information, which involve risk and uncertainties, are based on the beliefs, assumptions and expectations of management of the Company. Words such as “expects”, ‘believes”, “should”, “plans”, “anticipates”, “will”, “potential”, “could”, “intend”, “may”, “outlook”, “predict”, “project”, “would”, “estimates”, “assumes”, “likely”‘ “and variations of such similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and involve risks and uncertainties and are based on a number of assumptions that could ultimately prove inaccurate and, therefore, there can be no assurance that they will prove to be accurate. Actual results and outcomes may vary materially from what is expressed or forecast in such statements due to various risks and uncertainties. These risks and uncertainties include, among other things, the possibility of drilling cost overruns and technical difficulties, volatility of oil and gas prices, competition, risks inherent in the Company’s oil and gas operations, the inexact nature of interpretation of seismic and other geological and geophysical data, imprecision of reserve estimates, and the Company’s ability to replace and expand oil and gas reserves. Accordingly, stockholders and potential investors are cautioned that certain events or circumstances could cause actual results to differ materially from those projected. The forward looking statements are made as of the date of this report and other than as required by the federal securities laws, the Company assumes no obligation to update the forward-looking statement or to update the reasons why actual results could differ from those projected in the forward-looking statements.

This discussion should be read in conjunction with the condensed consolidated financial statements of the Company and notes thereto.

OVERVIEW

We are an independent oil and natural gas company engaged in acquiring, developing and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, Oklahoma, West Virginia, the Gulf of Mexico, New Mexico, Colorado and Louisiana. In addition, we own a substantial amount of well servicing equipment. All of our 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.

We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. In order to diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income producing assets so as to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient basis.

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 any 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.

RECENT ACTIVITIES

During the first nine months of 2011, we continued our drilling program in our West Texas district, drilling a total of 21 gross (13.8 net) wells, all of which were successful completions. We intend to drill approximately 30 wells this year, primarily in the West Texas area.

In June 2011, we successfully completed an amendment of our $250 million credit facility with an increase in the borrowing base from $100 million to $125 million and closed our previously existing subordinated credit facility with a related party private lender.

RESULTS OF OPERATIONS

Oil and gas sales increased $3.0 million, or 16% from $18.7 million for the third quarter 2010 to $21.7 million for the third quarter 2011 and $4.2 million, or 7% from $61.0 million for the nine months ended September 30, 2010 to $65.2 million for the nine months ended September 30, 2011. Crude oil and natural gas sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices at the well head increased an average of $8.01 per barrel, or 11% and $1.45 per mcf, or 27% on crude oil and natural gas, respectively, during the third quarter 2011 from the same period in 2010. Our realized prices at the well

head increased an average of $16.21 per barrel, or 22% and $0.72 per mcf, or 13% on crude oil and natural gas, respectively, during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010.

Our crude oil production increased by 12,000 barrels, or 8% from 143,000 barrels for the third quarter 2010 to 155,000 barrels for the third quarter 2011 and decreased 13,000 barrels, or 3% from 471,000 barrels for the nine months ended September 30, 2010 to 458,000 barrels for the nine months ended September 30, 2011. Our natural gas production decreased by 191,000 mcf, or 13% from 1,485,000 mcf for the third quarter 2010 to 1,294,000 mcf for the third quarter 2011 and 853,000 mcf, or 19% from 4,556,000 mcf for the nine months ended September 30, 2010 to 3,703,000 mcf for the nine months ended September 30, 2011. The crude oil production variances are a result of our recent drilling success in West Texas and the Gulf Coast regions as we place new wells into production, partially offset by the natural decline of existing properties. The natural gas volume decreases are primarily due to the natural decline of the primary natural gas producing offshore properties, partially offset by production from wells in the West Texas region recently placed into production.

The following table summarizes the primary components of production volumes and average sales prices realized for the three and nine months ended September 30, 2011 and 2010 (excluding realized gains and losses from derivatives).


	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Increase / (Decrease)			2011		2010		Increase / (Decrease)
Barrels of Oil Produced		155,000		143,000		12,000			458,000		471,000		(13,000	)
Average Price Received (rounded, excluding the impact of derivatives)	$	83.86	$	75.85	$	8.01		$	90.19	$	73.98	$	16.21

Oil Revenue (In 000’s)	$	13,001	$	10,842	$	2,159		$	41,283	$	34,847	$	6,436

Mcf of Gas Produced		1,294,000		1,485,000		(191,000	)		3,703,000		4,556,000		(853,000	)
Average Price Received (rounded, excluding the impact of derivatives)	$	6.77	$	5.32	$	1.45		$	6.47	$	5.75	$	0.72

Gas Revenue (In 000’s)	$	8,756	$	7,903	$	853		$	23,953	$	26,180	$	(2,227	)

Total Oil & Gas Revenue (In 000’s)	$	21,757	$	18,745	$	3,012		$	65,236	$	61,027	$	4,209

Realized net gains on derivative instruments include net gains of $3.3 million and $1.0 million on the settlements of crude oil and natural gas derivatives, respectively, for the third quarter 2011 and $0 and $1.0 million on the settlements of crude oil and natural gas derivatives, respectively, for the third quarter 2010. Realized net gains on derivative instruments include net gains of $1.4 million and $3.0 million on the settlements of crude oil and natural gas derivatives, respectively, for the nine months ended September 30, 2011 and a net loss of $0.1 million and net gain of $2.7 million on the settlements of crude oil and natural gas derivatives, respectively, for the nine months ended September 30, 2010. In August 2011, we unwound and monetized crude oil swaps and collars with original settlement dates from September 2011 through December 2014 for net proceeds of $3.4 million. The $3.4 million gain associated with these early settlement transactions is included in realized gain on derivative instruments for the three and nine months ended September 30, 2011.

Oil and gas prices received including the impact of derivatives but excluding the early settlement transactions were:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011		2010		Increase		2011		2010		Increase
Oil Price	$	83.22	$	75.85	$	7.37	$	85.96	$	73.78	$	12.18
Gas Price	$	7.54	$	6.00	$	1.54	$	7.27	$	6.33	$	0.94

We do not apply hedge accounting to any of our commodity based derivatives thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. During the three months ended September 30, 2011, we recognized $12.5 million in unrealized gains. This unrealized gain consists of $11.4 million associated with crude oil fixed swaps and collars due to a decrease in crude oil futures market prices between June 30, 2011 and September 30, 2011 and $1.1 million associated with natural gas fixed swap contracts due to decreased natural gas futures market prices between June 30, 2011 and September 30, 2011. For the nine months ended September 30, 2011, we recognized $9.0 million in unrealized gains primarily associated with crude oil fixed swaps and collars due to a decrease in crude oil futures market prices between December 31, 2010 and September 30, 2011.

Field service income increased $1.1 million, or 24% from $4.3 million for the third quarter 2010 to $5.4 million for the third quarter 2011 and $3.0 million, or 25% from $12.2 million for the nine months ended September 30, 2010 to $15.2 million for the nine months ended September 30, 2011. This increase is a direct result of upturns in utilization of equipment and the market allowing us to charge

higher rates to customers. Workover rig services represent the bulk of our field service operations, and those rates all increased in our most active districts. Utilization of our workover rigs increased in all districts. Water hauling and disposal services also increased in our South Texas district

Lease operating expense increased $2.0 million, or 26% from $7.7 million for the third quarter 2010 to $9.7 million for the third quarter 2011 and $1.2 million, or 5% from $25.3 million for the nine months ended September 30, 2010 to $26.5 million for the nine months ended September 30, 2011. These increases are primarily due to higher salt water disposal costs, production taxes and chemical expenses associated with new wells coming on line from the recent drilling success in West Texas, partially offset by decreased operating expenses on the offshore properties and decreased expensed workovers across all districts during the first nine months of 2011.

Field service expense increased $0.8 million, or 22% from $3.6 million for the third quarter 2010 to $4.4 million for the third quarter 2011 and $2.4 million, or 24% from $10.1 million for the nine months ended September 30, 2010 to $12.5 million for the nine months ended September 30, 2011. Field service expenses primarily consist of salaries and vehicle operating expenses which have increased $1.3 million and $1.1 million, respectively, during the nine months ended September 30, 2011 over the same period of 2010 as a direct result of increased services and utilization of the equipment.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $15.6 million from $7.3 million for the third quarter 2010 to $22.9 million for the third quarter 2011 and $16.7 million, or 69% from $24.2 million for the nine months ended September 30, 2010 to $40.9 million for the nine months ended September 30, 2011. Included in these increases is approximately $13.4 million and $14.4 million for the three and nine months ended September 30, 2011, respectively, related to an increased depletion rate recognized during the third quarter of 2011 associated with offshore properties driven by a decrease in estimated remaining economic reserves as several of our offshore properties enter into the last phase of their productive lives. The remaining increases of $2.2 million and $2.3 million for the three and nine months ended September 30, 2011, respectively, primarily relate to the increased production with new wells coming on line from the recent drilling success in West Texas.

Gain on sale and exchange of assets of $1.4 million for the third quarter 2011 consists of $0.5 million related to our Korean Joint Venture combined with $0.9 million related to sales of non-producing acreage and non-core producing properties.

Interest expense decreased $0.9 million, or 58% from $1.6 million for the third quarter 2010 to $0.7 million for the third quarter 2011 and $2.3 million, or 42% from $5.3 million for the nine months ended September 30, 2010 to $3.0 million for the nine months ended September 30, 2011. These decreases include the reduction of interest expense of $0.5 million and $0.7 million for the three and nine months ended September 30, 2011, respectively, associated with interest on the subordinated credit facility with a related party private lender which was paid off in June 2011. The remaining decreases of $0.4 million and $1.6 million for the three and nine months ended September 30, 2011, respectively, relate to reduced weighted average interest rates and less average debt outstanding during the 2011 periods.

LIQUIDITY AND CAPITAL RESOURCES

Our primary capital resources are cash provided by our operating activities and our credit facility.

Net cash provided by our operating activities for the nine month period ended September 30, 2011 was $31.1 million. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control. Hurricanes in the Gulf of Mexico may shut down our production for the duration of the storm’s presence in the Gulf or damage production facilities so that we cannot produce from a particular property for an extended amount of time. In addition, downstream activities on major pipelines in the Gulf of Mexico can also cause us to shut-in production for various lengths of time.

Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the vast majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility we sometimes lock in prices for some portion of our production through the use of financial instruments.

Our activities include development and exploratory drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential. During 2011, we plan on drilling in excess of 30 wells (20 net), mainly in the Permian Basin in West Texas.

We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2011. For the nine month period ended September 30, 2011, we have spent $1.8 million under these programs.

We currently maintain a credit facility totaling $250 million, with a current borrowing base of $125 million. The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a redetermined estimate of proved oil and gas reserves. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these

covenants. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable.

It is our goal to increase our oil and gas reserves and production through the acquisition and development of oil and gas properties. We also continue to explore and consider opportunities to further expand our oilfield servicing revenues through additional investment in field service equipment. However, the majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is a smaller reporting company and no response is required pursuant to this Item.

Item 4.

CONTROLS AND PROCEDURES

As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company’s internal control over financial reporting that occurred during the first nine months of 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS

None.

Item 1A.

RISK FACTORS

The Company is a smaller reporting company and no response is required pursuant to this Item.

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no sales of equity securities by the Company during the period covered by this report.

During the nine months ended September 30, 2011, the Company purchased the following shares of common stock as treasury shares.


2011 Month	Number of Shares		Average Price Paid per share		Maximum Number of Shares that May Yet Be Purchased Under The Program at Month - End (1)
January		17,225	$	19.44		238,372
February		12,110	$	24.08		226,262
March		12,492	$	26.61		213,770
April		5,227	$	27.63		208,543
May		1,788	$	27.17		206,755
June		1,152	$	23.55		205,603
July		8,702	$	24.26		196,901
August		6,544	$	20.93		190,357
September		5,484	$	19.25		184,873

Total/Average		70,724	$	23.08

(1)

In December 1993, we announced that our Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of our common stock from time-to-time, in open market transactions or negotiated sales. The Board of Directors of the Company approved an additional 300,000 shares of the Company’s stock to be included in the stock repurchase program effective May 20, 2010. A total of 3,000,000 shares have been authorized, to date, under this program. Through September 30, 2011 we repurchased a total of 2,815,127 shares under this program for $39,185,924 at an average price of $13.92 per share. Additional purchases may occur as market conditions warrant. We expect future purchases will be funded with internally generated cash flow or from working capital.

Item 3.

DEFAULTS UPON SENIOR SECURITIES

None

Item 4.

RESERVED

Item 5.

OTHER INFORMATION

None

Item 6.

EXHIBITS

The following exhibits are filed as a part of this report:


Exhibit No.

3.1		Restated Certificate of Incorporation of PrimeEnergy Corporation (effective July 1, 2009) (Incorporated by reference to Exhibit 3.1 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2009)

3.2		Bylaws of PrimeEnergy Corporation (Incorporated by reference to Exhibit 3.2 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2010)

10.3.1		Adoption Agreement #003 dated 4/23/2002, MassMutual Life Insurance Company Flexinvest Prototype Non-Standardized 401(k) Profit-Sharing Plan; EGTRRA Amendment to the PrimeEnergy employees 401(k) Savings Plan; MassMutual Retirement Services Flexinvest Defined Contribution Prototype Plan; Protected Benefit Addendum; Addendum to the Administrative Services Agreement Loan Agreement; Addendum to Administrative Services Agreement GUST Restatement Provisions; General Trust Agreement (Incorporated by reference to Exhibit 10.3.1 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2002)

10.3.2		First Amendment to the PrimeEnergy Corporation Employees 401(k) Savings Plan (Incorporated by reference to Exhibit 10.3.2 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2006)

10.4		Amended and Restated Agreement of Limited Partnership, FWOE Partners L.P., dated as of August 22, 2005 (Incorporated by reference to Exhibit 10.3 to PrimeEnergy Corporation Form 8-K for events of August 22, 2005)

10.4.1		Contribution Agreement between F-W Oil Exploration L.L.C. and FWOE Partners L.P. dated as of August 22, 2005 (Incorporated by reference to exhibit 10.4 to PrimeEnergy Corporation Form 8-K for events of August 22, 2005)

10.18		Composite copy of Non-Statutory Option Agreements (Incorporated by reference to Exhibit 10.18 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2004)

10.22.5.9		Second Amended and Restated Credit Agreement dated July 30, 2010, by and among PrimeEnergy Corporation, the Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, and EOWS Midland Company), Compass Bank (successor in interest to Guaranty Bank, FSB) As Administrative Agent and Letter of Credit Issuer, BBVA Compass, As Sole Lead Arranger and Sole Bookrunner and The Lenders Signatory Hereto (BNP Paribas, JPMorgan Chase Bank, N.A. and Amegy Bank National Association) (Incorporated by reference to Exhibit 10.22.5.9 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2010)

10.22.5.9.1		First Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, BNP Paribas, JPMorgan Chase Bank, N.A., Amegy Bank National Association) effective September 30, 2010 (Incorporated by reference to Exhibit 10.22.5.9.1 to PrimeEnergy Corporation Form 10Q for the quarter ended September 30, 2010).

10.22.5.9.2		Second Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, BNP Paribas, JPMorgan Chase Bank, N.A., Amegy Bank National Association) effective June 22, 2011 (Incorporated by reference to Exhibit 10.22.5.9.2 to PrimeEnergy Corporation Form 10Q for the quarter ended June 30, 2011).

10.22.5.10		Security Agreement (Pledge) effective July 30, 2010 by PrimeEnergy Corporation, in favor of Compass Bank) (Incorporated by reference to Exhibit 10.22.5.10 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2010)

10.22.5.11		Guaranty effective July 30, 2010, by PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, and EOWS Midland Company, in favor of Compass Bank (Incorporated by reference to Exhibit 10.22.5.11 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2010)


10.23.9		Ratification of and Amendment to Mortgage, Deed of Trust, Security Agreement, Financing Statement and Assignment of Production, dated effective February 24, 2010, by and between PrimeEnergy Corporation and PrimeEnergy Management Corporation and Compass Bank (successor in interest to Guaranty Bank, FSB) (Incorporated by reference to Exhibit 10.23.9 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2009)

10.25		Credit Agreement dated as of June 1, 2006 (but effective for all purposes as of August 22, 2005), between Prime Offshore L.L.C. as Borrower and PrimeEnergy Corporation as Lender (Incorporated by reference to Exhibit 10.25 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2006)

10.28		Completion and Liquidity Maintenance Agreement effective as of June 29, 2006, between PrimeEnergy Corporation, Guaranty Bank, FSB, and Prime Offshore, L.L.C. (Incorporated by reference to Exhibit 10.28 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2006)

10.29		Put Right Agreement effective as of June 29, 2006, by and among PrimeEnergy Corporation and Prime Offshore L.L.C. (Incorporated by reference to Exhibit 10.29 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2006)

31.1		Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).

31.2		Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

101.INS*		XBRL (eXtensible Business Reporting Language) Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

*	XBRL information (the Interactive Date File) is deemed not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934.

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.


						PrimeEnergy Corporation
						(Registrant)

November 9, 2011						/s/ Charles E. Drimal, Jr.
(Date)						Charles E. Drimal, Jr.
						President
						Principal Executive Officer

November 9, 2011						/s/ Beverly A. Cummings
(Date)						Beverly A. Cummings
						Executive Vice President
						Principal Financial Officer

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Smaller reporting company