Table of Contents

 

 

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 March 31, 2016

Or

 

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

For the Transition Period From                      to                     

Commission File Number 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.)

9821 Katy Freeway, Houston, Texas 77024

(Address of principal executive offices)

(713) 735-0000

(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.

 

Large accelerated filer		¨		Accelerated filer		¨
Non-accelerated filer		¨  (Do not check if smaller reporting company)		Smaller reporting company		x

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 May 11, 2016 was: Common Stock, $0.10 par value 2,293,964 shares.

 

 

 

---

Table of Contents

PrimeEnergy Corporation

Index to Form 10-Q

March 31, 2016

 

		Page
Part I - Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets – March  31, 2016 and December 31, 2015			3
Condensed Consolidated Statements of Operations – For the three months ended March 31, 2016 and 2015			4
Condensed Consolidated Statements of Comprehensive Income – For the three months ended March 31, 2016 and 2015			5
Condensed Consolidated Statement of Equity – For the three months ended March 31, 2016			6
Condensed Consolidated Statements of Cash Flows – For the three months ended March 31, 2016 and 2015			7
Notes to Condensed Consolidated Financial Statements – March  31, 2016			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			20-22
Signatures			23

 

2

---

Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – Unaudited

(Thousands of dollars, except per share amounts)

 

		March 31, 2016				December 31, 2015
ASSETS
Current Assets
Cash and cash equivalents		$	13,489			$	9,750
Restricted cash and cash equivalents			3,513				3,513
Accounts receivable, net			9,610				9,543
Other current assets			608				815
Total Current Assets			27,220				23,621
Property and Equipment, at cost
Oil and gas properties (successful efforts method), net			194,877				190,916
Field and office equipment, net			10,538				11,095
Total Property and Equipment, Net			205,415				202,011
Other Assets			124				629
Total Assets		$	232,759			$	226,261
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable		$	9,541			$	12,355
Accrued liabilities			10,390				6,122
Current portion of long-term debt			3,088				3,059
Current portion of asset retirement and other long-term obligations			2,128				1,435
Derivative liability short-term			—				7
Due to related parties			171				—
Total Current Liabilities			25,318				22,978
Long-Term Bank Debt			98,798				92,581
Asset Retirement Obligations			10,409				10,452
Deferred Income Taxes			37,059				37,349
Total Liabilities			171,584				163,360
Commitments and Contingencies
Equity
Common stock, $.10 par value; Authorized: 4,000,000 shares, issued: 3,836,397 shares			383				383
Paid-in capital			7,965				7,854
Retained earnings			91,018				92,878
Accumulated other comprehensive loss, net			—				(5	)
Treasury stock, at cost; 1,541,844 shares and 1,522,253 shares			(45,865	)			(45,380	)
Total Stockholders’ Equity – PrimeEnergy			53,501				55,730
Non-controlling interest			7,674				7,171
Total Equity			61,175				62,901
Total Liabilities and Equity		$	232,759			$	226,261

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

 

3

---

Table of Contents

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – Unaudited

Three Months Ended March 31, 2016 and 2015

(Thousands of dollars, except per share amounts)

 

		2016				2015
Revenues
Oil and gas sales		$	7,130			$	12,298
Realized gain on derivative instruments, net			—				5,143
Field service income			4,224				5,541
Administrative overhead fees			1,757				2,233
Unrealized loss on derivative instruments, net			—				(2,466	)
Other income			51				46
Total Revenues			13,162				22,795
Costs and Expenses
Lease operating expense			8,012				9,240
Field service expense			3,560				4,489
Depreciation, depletion, amortization and accretion on discounted liabilities			5,275				5,452
General and administrative expense			2,431				3,367
Total Costs and Expenses			19,278				22,548
Gain on Sale and Exchange of Assets			4,916				489
(Loss) Income from Operations			(1,200	)			736
Interest Expense			868				939
(Loss) Before Provision for Income Taxes			(2,068	)			(203	)
(Benefit) provision for Income Taxes			(890	)			15
Net (Loss)			(1,178	)			(218	)
Less: Net Income (Loss) Attributable to Non-Controlling Interests			682				(231	)
Net (Loss) Income Attributable to PrimeEnergy		$	(1,860	)		$	13
Basic (Loss) Income Per Common Share		$	(0.81	)		$	0.01
Diluted (Loss) Income Per Common Share		$	(0.81	)		$	0.00

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

 

4

---

Table of Contents

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – Unaudited

Three Months Ended March 31, 2016 and 2015

(Thousands of dollars)

 

		2016				2015
Net Income (Loss)		$	(1,178	)		$	(218	)
Other Comprehensive Loss, net of taxes:
Changes in fair value of hedge positions, net of taxes of $(2) and $4, respectively			5				(8	)
Total other comprehensive loss			5				(8	)
Comprehensive Income (Loss)			(1,173	)			(226	)
Less: Comprehensive Income (Loss) Attributable to Non-Controlling Interest			682				(231	)
Comprehensive Income Attributable to PrimeEnergy		$	(1,855	)		$	5

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

 

5

---

Table of Contents

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF EQUITY – Unaudited

Three Months Ended March 31, 2016

(Thousands of dollars)

 

		Common Stock								Additional Paid in Capital				Retained Earnings				Accumulated Other Comprehensive Loss				Treasury Stock				Total Stockholders’ Equity – PrimeEnergy				Non-Controlling Interest				Total Equity
		Shares				Amount
Balance at December 31, 2015			3,836,397			$	383			$	7,854			$	92,878			$	(5	)		$	(45,380	)		$	55,730			$	7,171			$	62,901
Repurchase 10,131 shares of common stock			—				—				—				—				—				(485	)			(485	)			—				(485	)
Net (loss) income			—				—				—				(1,860	)			—				—				(1,860	)			682				(1,178	)
Other comprehensive loss, net of taxes			—				—				—				—				5				—				5				—				5
Repurchase of non-controlling interests			—				—				111				—				—				—				111				(179	)			(68	)
Balance at March 31, 2016			3,836,397			$	383			$	7,965			$	91,018				—			$	(45,865	)		$	53,501			$	7,674			$	61,175

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

 

6

---

Table of Contents

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited

Three Months Ended March 31, 2016 and 2015

(Thousands of dollars)

 

		2016				2015
Cash Flows from Operating Activities:
Net (loss)		$	(1,178	)		$	(218	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities			5,275				5,452
Gain on sale of properties			(4,916	)			(489	)
Unrealized loss on derivative instruments, net			—				2,466
Provision (benefit) for deferred income taxes			(290	)			(63	)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable			(67	)			700
Decrease in due from related parties			171				255
Decrease in other assets			712				302
(Decrease) in accounts payable			(2,814	)			(1,162	)
Increase (decrease) in accrued liabilities			4,268				(5,914	)
Net Cash Provided by Operating Activities			1,161				1,329
Cash Flows from Investing Activities:
Capital expenditures, including exploration expense			(7,920	)			(4,533	)
Proceeds from sale of properties and equipment			4,916				525
Net Cash Used in Investing Activities			(3,004	)			(4,008	)
Cash Flows from Financing Activities:
Purchase of stock for treasury			(485	)			(1,280	)
Purchase of non-controlling interests			(179	)			(1	)
Proceeds from long-term bank debt and other long-term obligations			9,000				11,200
Repayment of long-term bank debt and other long-term obligations			(2,754	)			(10,755	)
Distribution to non-controlling interests			—				(16	)
Net Cash Provided by (Used) in Financing Activities			5,582				(852	)
Net Increase (Decrease) in Cash and Cash Equivalents			3,739				(3,531	)
Cash and Cash Equivalents at the Beginning of the Period			9,750				9,209
Cash and Cash Equivalents at the End of the Period		$	13,489			$	5,678
Supplemental Disclosures:
Income taxes paid		$	91			$	498
Interest paid		$	806			$	1,237

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

 

7

---

Table of Contents

PRIMEENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2016

(Unaudited)

(1) Basis of Presentation:

The accompanying condensed consolidated financial statements of PrimeEnergy Corporation (“PEC” or the “Company”) have not been audited by independent public accountants. Pursuant to 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, 2015. 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 March 31, 2016 and December 31, 2015, the condensed consolidated results of operations, cash flows and equity for the three months ended March 31, 2016 and 2015. 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

The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU supersedes the Revenue recognition requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic 932-605. Extractivies – Oil and Gas Revenue Recognition. This ASU provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers – Deferral or the Effective Date, to annual and interim periods beginning in 2018 and is required to be adopted using either the retrospective or cumulative effect (modified retrospective) transition method, with early adoption permitted in 2017. The Company is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures and does not plan on early adopting.

The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities such, as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The ASU is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. This ASU was adopted by the Company beginning January 1, 2016 did not have a material impact on the Company’s consolidated financial statements and related disclosures.

The FASB issued ASU 2015-03, Interest – Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest – Imputation of Interest (Topic 835): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASU’s require debt issuance costs related to a recognized debt liability, except for those related to revolving credit facilities, to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than an asset. These ASU’s was adopted by the Company beginning January 1, 2016 did not have a material impact on the Company’s consolidated financial statements and related disclosures.

The FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. This ASU is effective for annual and interim periods beginning in 2017 and can be applied prospectively or retrospectively, with early adoption permitted. This ASU was early-adopted by the Company effective January 1, 2016 and did not have a material impact on the Company’s financial statements and related disclosures.

The FASB issued ASU 2016-02, Leases (Topic 842). This ASU requires lessee recognition on the balance sheet of a right-of-use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Finally, it requires classification of all cash payments within operating activities in the statement of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. This ASU will not have a material impact on the Company’s financial statements and related disclosures.

(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 amounts totaling $68,000 and $1,000 for the three months ended March 31, 2016 and 2015, respectively.

 

8

---

Table of Contents

(3) Restricted Cash and Cash Equivalents:

Restricted cash and cash equivalents include $3.51 million at March 31, 2016 and December 31, 2015 of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at March 31, 2016 and December 31, 2015 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the accompanying condensed consolidated balance sheets.

(4) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

 

(Thousands of dollars)		March 31, 2016				December 31, 2015
Accounts Receivable:
Joint interest billing		$	2,741			$	2,667
Trade receivables			1,249				1,452
Oil and gas sales			3,682				3,576
Other			2,473				2,377
			10,145				10,072
Less: Allowance for doubtful accounts			(535	)			(529	)
Total		$	9,610			$	9,543
Accounts Payable:
Trade		$	1,658			$	3,289
Royalty and other owners			5,087				5,973
Partner advances			1,389				1,083
Prepaid drilling deposits			161				390
Other			1,246				1,620
Total		$	9,541			$	12,355
Accrued Liabilities:
Compensation and related expenses		$	2,549			$	2,294
Property costs			7,230				3,302
Other			611				526
Total		$	10,390			$	6,122

 

9

---

Table of Contents

(5) Property and Equipment:

Property and equipment at March 31, 2016 and December 31, 2015 consisted of the following:

 

(Thousands of dollars)		March 31, 2016				December 31, 2015
Proved oil and gas properties, at cost		$	403,525			$	395,129
Less: Accumulated depletion and depreciation			(208,648	)			(204,213	)
Oil and Gas Properties, Net		$	194,877			$	190,916
Field and office equipment		$	27,491			$	27,919
Less: Accumulated depreciation			(16,953	)			(16,824	)
Field and Office Equipment, Net		$	10,538			$	11,095
Total Property and Equipment, Net		$	205,415			$	202,011

(6) Long-Term Debt:

Bank Debt:

Effective July 30, 2010 the Company entered into a Second Amended and Restated Credit Agreement between Compass Bank as agent and a syndicated group of lenders (“Credit Agreement”). The Credit Agreement has a revolving line of credit and letter of credit facility of up to $250 million with a final maturity date of July 30, 2017. The credit facility is secured by substantially all of the Company’s oil and gas properties. The credit facility is subject to a borrowing base determined by the lenders taking into consideration the estimated value of PEC’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. This process involves reviewing PEC’s estimated proved reserves and their valuation. The borrowing base is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redetermination. In addition, PEC and the lenders each have at their discretion the right to request the borrowing base be redetermined with a maximum of one such request each year. A revision to PEC’s reserves may prompt such a request on the part of the lenders, which could possibly result in a reduction in the borrowing base and availability under the credit facility. At any time if the sum of the outstanding borrowings and letter of credit exposures exceed the applicable portion of the borrowing base, PEC would be required to repay the excess amount within a prescribed period.

At March 31, 2016, the credit facility borrowing base was $95.0 million with no required monthly reduction amount. The borrowings made within the credit facility may be placed in a base rate loan or LIBO rate loan. The Company’s borrowing rates in the credit facility provide for base rate loans at the prime rate (3.50% at March 31, 2016) plus applicable margin utilization rates that range from 1.75% to 2.50%, and LIBO rate loans at LIBO published rates plus applicable utilization rates (2.75% to 3.00% at March 31, 2016). At March 31, 2016, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 5.50% and 3.44%, respectively.

At March 31, 2016, the Company had $93.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.67% and $2 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 3.61% for the three months ended March 31, 2016 as compared to 3.41% for the three months ended March 31, 2015.

The Company entered into interest rate hedge agreements to help manage interest rate exposure. These contracts include interest rate swaps. Interest rate swap transactions generally involve the exchange of fixed and floating rate interest payment obligations without the exchange of the underlying principal amounts. In July 2012, the Company entered into interest swap agreements for a period of two years, which commenced in January 2014, related to $75 million of the Company’s bank debt resulting in a LIBO fixed rate of 0.563% and terminated in January 2016. The Company recorded interest expense and paid $7,070 and $74,000 related to the settlement of interest rate swaps for the three months ended March 31, 2016 and 2015, respectively.

Equipment Loans:

On July 31, 2013, the Company entered into a $10.0 million Loan and Security Agreement with JP Morgan Chase Bank (“Equipment Loan”). The Equipment Loan is secured by a portion of the Company’s field service equipment, carries an interest rate of 3.95% per annum, requires monthly payments (principal and interest) of $184,000, and has a final maturity date of July 31, 2018. As of March 31, 2016, the Company had a total of $5.08 million outstanding on this Equipment Loan.

 

10

---

Table of Contents

On July 29, 2014, the Company entered into additional equipment financing facilities (“Additional Equipment Loans”) totaling $6.0 million with JP Morgan Chase Bank. In August 2014, the Company drew down $4.8 million of this facility that is secured by field service equipment, carries an interest rate of 3.40% per annum, requires monthly payments (principal and interest) of $87,800, and has a final maturity date of July 31, 2019. The remaining $1.2 million under the Additional Equipment Loans was available for interim draws to finance the acquisition of any future field service equipment. In December 2014, the Company made an interim draw of an additional $0.5 million on this facility that is secured by recently purchased field service equipment. Interim draws on this facility carried a floating interest rate, payable monthly at the LIBO published rate plus 2.50% and on June 26, 2015 converted into a fixed term loan, with a rate of 3.50% and requiring monthly payments (principal and interest) of $8,700 with a final maturity date of June 26, 2020. As of March 31, 2016, the Company had a total of $3.81 million outstanding on the Additional Equipment Loans.

(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 fiscal 2016 and thereafter for the operating leases are as follows:

 

(Thousands of dollars)		Operating Leases
2016		$	597
2017			125
2018			16
Total minimum payments		$	738

Rent expense for office space for the three months ended March 31, 2016 and 2015 was $207,000 and $263,000, respectively.

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the three months ended March 31, 2016 is as follows:

 

(Thousands of dollars)
Asset retirement obligation – December 31, 2015		$	11,737
Liabilities incurred			32
Liabilities settled			(77	)
Accretion expense			124
Asset retirement obligation – March 31, 2016		$	11,816

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.

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.

 

11

---

Table of Contents

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 March 31, 2016 and 2015, remaining options held by two key executive officers 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 $68,000 and $1,000 for the three months ended March 31, 2016 and 2015, respectively.

Treasury stock purchases in any reported period may include shares from a related party, which may include members of the Company’s Board of Directors. The Company purchased 10,000 shares during the first quarter from a related party.

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.

(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 at March 31, 2016 and December 31, 2015:

 

March 31,2016 (Thousands of dollars)		Quoted Prices in Active Markets For Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Balance at March 31, 2016
Liabilities
Interest rate derivative contracts		$	—			$	—			$	—			$	—
Total liabilities		$	—			$	—			$	—			$	—
December 31, 2015 (Thousands of dollars)		Quoted Prices in Active Markets For Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Balance at December 31, 2015
Liabilities
Interest rate derivative contracts		$	—			$	—			$	(7	)		$	(7	)
Total liabilities		$	—			$	—			$	(7	)		$	(7	)

The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness.

 

12

---

Table of Contents

The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

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 three months ended March 31, 2016.

 

(Thousands of dollars)
Net Liabilities – December 31, 2015		$	(7	)
Total realized and unrealized (gains) losses:
Included in earnings (a)			7
Included in other comprehensive loss			—
Purchases, sales, issuances and settlements			—
Net assets(liabilities) – March 31, 2016		$	—

 

(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, and interest rate swap instruments are reported as an increase or reduction to interest expense.

Derivative Instruments:

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 commodity derivative instruments are recognized in earnings.

Interest rate swap derivatives continue to be treated as cash-flow hedges and are used to fix our float interest rates on existing debt. The value of these interest rate swaps at March 31, 2016 and December 31, 2015 are located, if applicable, in accumulated other comprehensive loss, net of tax. Settlement of the swaps, which began in January 2014 and concluded in January 2016, are recognized within interest expense.

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at March 31, 2016 and December 31, 2015:

 

						Fair Value at December 31,
(Thousands of dollars)		Balance Sheet Location				March 31, 2016				December 31, 2015
Liability Derivatives:
Derivatives designated as cash-flow hedging instruments:
Interest rate swap contracts			Derivative liability short-term			$	—			$	(7	)
Total						$	—			$	(7	)
Total derivative instruments						$	—			$	(7	)

 

13

---

Table of Contents

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the three month period ended March 31, 2016 and 2015:

 

		Location of gain/loss recognized in income		Amount of gain/loss recognized in income
(Thousands of dollars)				2016				2015
Derivative designated as cash-flow hedge instruments:
Interest rate swap contracts		Interest expense		$	(7	)		$	(74	)
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts		Unrealized (loss) gain on derivative instruments, net			—				(193	)
Crude oil commodity contracts		Unrealized (loss) gain on derivative instruments, net			—				(2,273	)
Natural gas commodity contracts		Realized gain (loss) on derivative instruments, net			—				592
Crude oil commodity contracts		Realized gain on derivative instruments, net			—				4,551
				$	(7	)		$	2,603

 

(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:

 

		Three Months Ended March 31,
		2016												2015
		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		$	(1,860	)			2,295,177			$	(0.81	)		$	13				2,318,348			$	0.01
Effect of dilutive securities:
Options			—				749,585								—				753,636
Diluted (a)		$	(1,860	)			3,044,762			$	(0.81	)		$	13				3,071,984			$	0.00

 

(a)	The effect of the 767,500 outstanding stock options is antidilutive for the three months ended March 31, 2016 due to a net loss reported for the period.

 

14

---

Table of Contents

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 statements or to update the reasons why actual results could differ from those projected in the forward-looking statements.

The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Condensed Consolidated Financial Statements and the accompanying Notes to the Condensed Consolidated Financial Statements included elsewhere in this Report contain additional information that should be referred to when reviewing this material.

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, 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 are the operator of substantially all of our undeveloped acreage and the majority of it is currently held by production. We maintain an acreage position of over 26,000 gross (16,500 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties. We believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for drilling opportunities. Our Oklahoma horizontal development is primarily in Grant and Canadian counties where we have approximately 6,450 net acres which we believe have significant resource potential based on our drilling results and those of offset operators.

We believe our balanced portfolio of assets positions 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, through our producing oil & gas properties, field services business and sales of non-core acreage.

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 may 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.

 

15

---

Table of Contents

RECENT ACTIVITIES

We began our West Texas, Upton County horizontal drilling program during 2015 and through the first quarter of 2016 we have drilled 4 wells in this phase. Discussions with our joint venture partner in that program, Apache Corporation, indicate that including additional phases of development in the program will result in approximately 60 horizontal wells being drilled at a cost of approximately $470 million. We own various interests, ranging from 16% up to 50% interest in the lands to be developed in the program, and expect our share of these capital expenditures to be approximately $120 million. The actual number of wells to be drilled and the timing of the drilling may vary based on commodity market conditions. Currently the Company and Apache have agreed until oil and gas prices recover to limit drilling to those wells required to maintain our acreage position. Apache drilling plans indicated two of these wells will be drilled later this year at a cost of $12 million, of which our share is $3.6 million.

During 2016 we commenced our Martin County, Texas horizontal drilling program, two wells have been drilled and cased, at a cost of $8.3 million of which our share is $8.1 million, and they are currently awaiting completion. During 2016 we have farmed out certain non-core acreage in exchange for cash and a royalty or working interest in both West Texas and Oklahoma. Proceeds under these agreements are $4.9 million.

RESULTS OF OPERATIONS

2016 and 2015 Compared

We reported a net loss for 2016 of $1.86 million, or $ (0.81) per share, compared to net income for 2015 of $13 thousand, or $0.01 per share. The decrease in commodity prices reduced oil and gas sales compared to 2015 and all derivative instruments expired during 2015 therefore we incurred no gains or losses related to derivative instruments during 2016. The significant components of income and expense are discussed below.

Oil and gas sales decreased $5.2 million, or 42% from $12.3 million for the three months ended March 31, 2015 to $7.1 million for the three months ended March 31, 2016. 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 decreased an average of $15.89 per barrel, or 35% on crude oil during the three months ended March 31, 2016 from the same period in 2015 and our average well head price for natural gas decreased $0.83 per mcf, or 27% during the three months ended March 31, 2016 from the same period in 2015.

Our crude oil production decreased by 32,000 barrels, or 16% from 194,000 barrels for the first quarter 2015 to 162,000 barrels for the first quarter 2016. Our natural gas production decreased by 80,000 mcf, or 7% from 1,185,000 mcf for the first quarter 2015 to 1,105,000 mcf for the first quarter 2016. The net decrease in crude oil and natural gas production volumes reflect the natural decline of properties drilled in early 2015 combined with the natural decline of the previously existing properties, slightly offset by production from new wells added in late March 2016.

The following table summarizes the primary components of production volumes and average sales prices realized for the three months ended March 31, 2016 and 2015 (excluding realized gains and losses from derivatives).

 

		Three Months Ended March 31,
		2016				2015				Increase / (Decrease)
Barrels of Oil Produced			162,000				194,000				(32,000	)
Average Price Received		$	28.91			$	44.80			$	(15.89	)
Oil Revenue (In 000’s)		$	4,684			$	8,700			$	(4,016	)
Mcf of Gas Produced			1,105,000				1,185,000				(80,000	)
Average Price Received		$	2.21			$	3.04			$	(.83	)
Gas Revenue (In 000’s)		$	2,446			$	3,598			$	(1,152	)
Total Oil & Gas Revenue (In 000’s)		$	7,130			$	12,298			$	(5,168	)

 

16

---

Table of Contents

Realized net gains on derivative instruments include net gains of $0.59 million and $4.55 million on the settlements of natural gas and crude oil derivatives, respectively for the first quarter 2015. No such gains were recognized in 2016.

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 condensed 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 March 31, 2015, we recognized net unrealized losses of $0.19 million associated with natural gas fixed swap contracts and $2.27 million in net unrealized losses associated with crude oil fixed swaps due to a decrease in natural gas and crude oil futures market prices between December 31, 2014 and March 31, 2015. No such losses were recognized in 2016.

Field service income decreased $1.32 million, or 24% from $5.54 million for the first quarter 2015 to $4.22 million for the first quarter 2016. This decrease is a combined result of reduced utilization and the market requiring us to charge lower rates to customers during the 2016 period. Workover rig services represent the bulk of our field service operations, and while we were able to keep our rigs utilized during 2016, working rates have all decreased between the periods in our most active districts.

Lease operating expense decreased $1.23 million, or 13% from $9.24 million for the first quarter 2015 to $8.01 million for the first quarter 2016. This decrease is primarily due to general rate reductions on vendor services combined with reduced production taxes related to reduced oil and natural gas prices during the first three months of 2016 as compared to the same period of 2015.

Field service expense decreased $0.93 million, or 21% from $4.49 million for the first quarter 2015 to $3.56 million for the first quarter 2016. Field service expenses primarily consist of salaries and vehicle operating expenses which have decreased during the three months ended March 31, 2016 over the same period of 2015 as a direct result of decreased services and utilization of the equipment.

Depreciation, depletion, amortization and accretion on discounted liabilities decreased $0.19 million, or 3% from $5.45 million for the first quarter 2015 to $5.26 million for the first quarter 2016 reflecting the decreased production during the first three months of 2016 as compared to the same period of 2015.

General and administrative expense decreased $0.94 million, or 28% from $3.37 million for the three months ended March 31, 2015 to $2.43 million for the three months ended March 31, 2016. This decrease in 2016 reflects the cost cutting measures including reductions in workforce put in place throughout 2015.

Gain on sale and exchange of assets of $0.49 million and $4.92 million for the three months ended March 31, 2015 and March 31, 2016, respectively consists of sales of non-essential oil and gas interests and field service equipment.

Interest expense decreased $0.07 million, or 7% from $0.94 million for the first quarter 2015 to $0.87 million for the first quarter 2016. This decrease relates to the expiration of interest rate swaps in 2016.

A tax benefit of $890 thousand, or an effective rate of 32% was recorded for the quarter ended March 31, 2016, versus a provision of $15 thousand for the quarter ended March 31, 2015.

LIQUIDITY AND CAPITAL RESOURCES

Our primary sources of liquidity are cash generated from our operations, through our producing oil & gas properties, field services business and sales of non-core acreage.

Net cash provided by our operating activities for the three months ended March 31, 2016 was $1.16 million compared to $1.33 million for the three months ended March 31, 2015. 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.

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 derivatives.

 

17

---

Table of Contents

If our exploratory drilling results in significant new discoveries, we will have to expend additional capital in order to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through bank financing.

We currently maintain a credit facility totaling $250 million, with a borrowing base of $95 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 and expect to be in compliance over the next twelve months. 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. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the redetermined borrowing base.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2016, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2016 capital budget is reflective of decreased commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures. We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit facility should our borrowing base become limited due to the deterioration of commodity prices.

Due to the uncertainty of financing availability we have removed all but one PUD location from our yearend reserve report in accordance with the SEC rules governing the scheduling of the drilling of PUD reserves within 5 years. We expect to continue development of those reserves when our borrowing base is redetermined and, if required, we have secured additional sources of financing. The one PUD included in our report was drilled in the first quarter of 2016 as part of our joint venture with Apache Corporation in Upton County, Texas.

We began our West Texas, Upton County horizontal drilling program during 2015 and through the first quarter of 2016 we have drilled 4 wells in this phase. Discussions with our joint venture partner in that program, Apache Corporation, indicate that including additional phases of development in the program will result in approximately 60 horizontal wells being drilled at a cost of approximately $470 million. We own various interests, ranging from 16% up to 50% interest in the lands to be developed in the program, and expect our share of these capital expenditures to be approximately $120 million. The actual number of wells to be drilled and the timing of the drilling may vary based on commodity market conditions. Currently the Company and Apache have agreed until oil and gas prices recover to limit drilling to those wells required to maintain our acreage position. Apache drilling plans indicated two of these wells will be drilled later this year at a cost of $12 million, of which our share is $3.6 million.

During 2016 we commenced our Martin County, Texas horizontal drilling program, two wells have been drilled and cased, at a cost of $8.3 million of which our share is $8.1 million, and they are currently awaiting completion. During 2016 we have farmed out certain non-core acreage in exchange for cash and a royalty or working interest in both West Texas and Oklahoma. Proceeds under these agreements are $4.9 million.

We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2016. For the three month period ended March 31, 2016, we have spent $553 thousand under these programs.

 

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

 

18

---

Table of Contents

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 three months of 2016 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 three months ended March 31, 2016, the Company purchased the following shares of common stock as treasury shares.

 

2016 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			10,070			$	47.96				248,158
February			—			$	—				248,158
March			61			$	34.76				248,097
Total/Average			10,131			$	47.88

 

(1)

In December 1993, we announced that the Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of the common stock from time-to-time, in open market transactions or negotiated sales. On October 31, 2012, the Board of Directors of the Company approved an additional 500,000 shares of the Company’s stock to be included in the stock repurchase program. A total of 3,500,000 shares have been authorized to date under this program. Through March 31, 2016, a total of 3,251,903 shares have been repurchased under this program for $54,521,686 at an average price of $16.77 per share. Additional purchases of shares 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

 

19

---

Table of Contents

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 as amended and restated as of May 20, 2015 (filed as Exhibit 3.2 of PrimeEnergy Corporation Form 8-K on May 21, 2015 and incorporated herein by reference).
10.18		Composite copy of Non-Statutory Option Agreements (Incorporated by reference to Exhibit 10.18 of 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 of 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 10-Q 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 10-Q for the quarter ended June 30, 2011).
10.22.5.9.3		Third 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 December 8, 2011 (Incorporated by reference to Exhibit 10.22.5.9.3 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2011).
10.22.5.9.4		Fourth 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 25, 2012 (Incorporated by reference to Exhibit 10.22.5.9.4 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2012).

 

20

---

Table of Contents

Exhibit No.
10.22.5.9.5		Fifth 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, Prime Offshore L.L.C.), 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, Wells Fargo Bank National Association, JPMorgan Chase Bank, N.A., Amegy Bank National Association, KeyBank National Association) effective November 26, 2012 (Incorporated by reference to Exhibit 10.22.5.9.5 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2012).
10.22.5.9.6		Sixth 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, Prime Offshore L.L.C.), 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, Wells Fargo Bank National Association, JPMorgan Chase Bank, N.A., Amegy Bank National Association, KeyBank National Association) effective June 28, 2013 (Incorporated by reference to Exhibit 10.22.5.9.6 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2013).
10.22.5.9.7		Assignment Agreement made by and among Amegy Bank National Association, as Assignor, and Compass Bank (successor in interest to Guaranty Bank, FSB), Wells Fargo Bank, National Association, JPMorgan Chase Bank and KeyBank National Association, as Assignees, effective December 23, 2013 (Incorporated by reference to Exhibit 10.22.5.9.7 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2013).
10.22.5.9.8		Seventh 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, Prime Offshore L.L.C.), 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, Wells Fargo Bank National Association, JPMorgan Chase Bank, N.A., KeyBank National Association) effective June 26, 2014 (Incorporated by reference to Exhibit 10.22.5.9.8 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2014).
10.22.5.9.9		Eighth 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, Prime Offshore L.L.C.), 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, Wells Fargo Bank National Association, JPMorgan Chase Bank, N.A., KeyBank National Association) effective June 29, 2015 (Incorporated by reference to Exhibit 10.22.5.9.9 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2015).
10.23.1		Loan and Security Agreement dated July 31, 2013, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.23.1 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2013).
10.23.2		Business Purpose Promissory Note dated July 31, 2013, made by Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company to JP Morgan Chase Bank N.A. (Incorporated by reference to Exhibit 10.23.2 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2013).
10.23.3		Guaranty dated July 31, 2013, made by PrimeEnergy Corporation in favor of JP Morgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.23.3 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2013).
10.23.4		Agreement of Equipment Substitution dated January 15, 2014, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.23.4 to PrimeEnergy Corporation Form 10-Q for the quarter ended March 31, 2014).

 

21

---

Table of Contents

Exhibit No.
10.24.1		Loan and Security Agreement dated July 29, 2014, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.24.1 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2014).
10.24.2		Business Purpose Promissory Note dated July 29, 2014, made by Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company to JP Morgan Chase Bank N.A. (Incorporated by reference to Exhibit 10.24.2 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2014).
10.24.3		Guaranty dated July 29, 2014, made by PrimeEnergy Corporation in favor of JP Morgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.24.3 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2014).
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 (filed herewith)
101.SCH		XBRL Taxonomy Extension Schema Document (filed herewith)
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith)
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document (filed herewith)
101.LAB		XBRL Taxonomy Extension Label Linkbase Document (filed herewith)
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith)

 

22

---

Table of Contents

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)
May 16, 2016				/s/ Charles E. Drimal, Jr.
(Date)				Charles E. Drimal, Jr.
				President
				Principal Executive Officer
May 16, 2016				/s/ Beverly A. Cummings
(Date)				Beverly A. Cummings
				Executive Vice President
				Principal Financial Officer

 

23