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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, 2015

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 November 6, 2015 was: Common Stock, $0.10 par value 2,307,216 shares.

 

 

 

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PrimeEnergy Corporation

Index to Form 10-Q

September 30, 2015

 

				Page
Part I - Financial Information
Item 1.		Financial Statements
		Condensed Consolidated Balance Sheets – September 30, 2015 and December 31, 2014			3
		Condensed Consolidated Statements of Operations – For the three and nine months ended September  30, 2015 and 2014			4
		Condensed Consolidated Statements of Comprehensive Income – For the nine months ended September  30, 2015 and 2014			5
		Condensed Consolidated Statement of Equity – For the nine months ended September 30, 2015			6
		Condensed Consolidated Statements of Cash Flows – For the nine months ended September 30, 2015 and 2014			7
		Notes to Condensed Consolidated Financial Statements – September 30, 2015			8-15
Item 2.		Management’s Discussion and Analysis of Financial Conditions and Results of Operations			16-20
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			20
Item 4.		Controls and Procedures			20
Part II - Other Information
Item 1.		Legal Proceedings			20
Item 1A.		Risk Factors			20
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			20
Item 3.		Defaults Upon Senior Securities			21
Item 4.		Reserved			21
Item 5.		Other Information			21
Item 6.		Exhibits			22-24
Signatures					25

 

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PART I—FINANCIAL INFORMATION

 

Item 1.

FINANCIAL STATEMENTS

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – Unaudited

(Thousands of dollars, except per share amounts)

 

		September 30, 2015				December 31, 2014
ASSETS
Current Assets
Cash and cash equivalents		$	5,454			$	9,209
Restricted cash and cash equivalents			3,628				3,877
Accounts receivable, net			11,639				12,315
Derivative contracts			5,649				16,914
Other current assets			1,057				1,490
Total Current Assets			27,427				43,805
Property and Equipment, at cost
Oil and gas properties (successful efforts method), net			201,866				207,600
Field and office equipment, net			11,710				12,701
Total Property and Equipment, Net			213,576				220,301
Other Assets			604				794
Total Assets		$	241,607			$	264,900
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable		$	11,077			$	16,258
Accrued liabilities			7,800				12,401
Current portion of long-term debt			3,030				2,903
Current portion of asset retirement and other long-term obligations			1,222				1,366
Current portion of deferred tax liability			1,517				5,547
Derivative liability short-term			76				170
Due to related parties			1				45
Total Current Liabilities			24,723				38,690
Long-Term Bank Debt			91,857				98,490
Asset Retirement Obligations			10,801				11,269
Deferred Income Taxes			40,613				38,191
Total Liabilities			167,994				186,640
Commitments and Contingencies
Equity
Common stock, $.10 par value; Authorized: 4,000,000 shares, issued: 3,836,397 shares			383				383
Paid-in capital			7,443				7,186
Retained earnings			103,087				105,662
Accumulated other comprehensive loss, net			(49	)			(92	)
Treasury stock, at cost; 1,528,323 shares and 1,502,993 shares			(45,186	)			(43,527	)
Total Stockholders’ Equity – PrimeEnergy			65,678				69,612
Non-controlling interest			7,935				8,648
Total Equity			73,613				78,260
Total Liabilities and Equity		$	241,607			$	264,900

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

 

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PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – Unaudited

(Thousands of dollars, except per share amounts)

 

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2015				2014				2015				2014
Revenues
Oil and gas sales		$	10,607			$	23,372			$	37,160			$	73,636
Realized gain (loss) on derivative instruments, net			5,494				151				14,939				(2,572	)
Field service income			5,507				6,472				16,497				19,830
Administrative overhead fees			2,036				2,383				6,399				7,057
Unrealized gain (loss) on derivative instruments, net			(2,147	)			8,360				(11,252	)			2,361
Other income			1				6				52				146
Total Revenues			21,498				40,744				63,795				100,458
Costs and Expenses
Lease operating expense			8,827				10,979				27,040				33,115
Field service expense			4,667				5,149				13,553				15,720
Depreciation, depletion, amortization and accretion on discounted liabilities			5,648				5,789				16,786				16,748
Gain on settlement of asset retirement obligations			—				(1,787	)			—				(1,787	)
General and administrative expense			2,783				4,289				9,271				11,819
Total Costs and Expenses			21,925				24,419				66,650				75,615
Gain on Sale and Exchange of Assets			156				1,608				1,373				5,623
Income (Loss) from Operations			(271	)			17,933				(1,482	)			30,466
Other Income and Expenses
Less: Interest expense			881				984				2,747				3,103
Add: Interest income			2				—				2				—
Income (Loss) Before Provision for Income Taxes			(1,150	)			16,949				(4,227	)			27,363
Provision (Benefit) for Income Taxes			(310	)			5,617				(1,331	)			8,531
Net Income (Loss)			(840	)			11,332				(2,896	)			18,832
Less: Net Income (Loss) Attributable to Non-Controlling Interests			(185	)			533				(321	)			1,991
Net Income (Loss) Attributable to PrimeEnergy		$	(655	)		$	10,799			$	(2,575	)		$	16,841
Basic Income (Loss) Per Common Share		$	(0.28	)		$	4.58			$	(1.11	)		$	7.11
Diluted Income (Loss) Per Common Share		$	(0.28	)		$	3.47			$	(1.11	)		$	5.40

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

 

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PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – Unaudited

Nine Months Ended September 30, 2015 and 2014

(Thousands of dollars)

 

		2015				2014
Net Income (Loss)		$	(2,896	)		$	18,832
Other Comprehensive Income, net of taxes:
Changes in fair value of hedge positions, net of taxes of $27 and $1, respectively			43				4
Total other comprehensive income			43				4
Comprehensive Income (Loss)			(2,853	)			18,836
Less: Comprehensive Income (Loss) Attributable to Non-Controlling Interest			(321	)			1,991
Comprehensive Income (Loss) Attributable to PrimeEnergy		$	(2,532	)		$	16,845

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

 

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PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF EQUITY – Unaudited

Nine Months Ended September 30, 2015

(Thousands of dollars)

 

		Common Stock								Additional Paid in Capital				Retained Earnings				Accumulated Other Comprehensive Income (Loss)				Treasury Stock				Total Stockholders’ Equity – PrimeEnergy				Non-Controlling Interest				Total Equity
		Shares				Amount
Balance at December 31, 2014			3,836,397			$	383			$	7,186			$	105,662			$	(92	)		$	(43,527	)		$	69,612			$	8,648			$	78,260
Repurchase 25,330 shares of common stock			—				—				—				—				—				(1,659	)			(1,659	)			—				(1,659	)
Net Loss			—				—				—				(2,575	)			—				—				(2,575	)			(321	)			(2,896	)
Other comprehensive income, net of taxes			—				—				—				—				43				—				43				—				43
Repurchase of non-controlling interests			—				—				257				—				—				—				257				(358	)			(101	)
Distributions to non-controlling interests			—				—				—				—				—				—				—				(34	)			(34	)
Balance at September 30, 2015			3,836,397			$	383			$	7,443			$	103,087			$	(49	)		$	(45,186	)		$	65,678			$	7,935			$	73,613

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

 

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PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited

Nine Months Ended September 30, 2015 and 2014

(Thousands of dollars)

 

		2015				2014
Cash Flows from Operating Activities:
Net income (loss)		$	(2,896	)		$	18,832
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities			16,786				16,748
Gain on sale of properties			(1,373	)			(5,623	)
Unrealized (gain) loss on derivative instruments, net			11,252				(2,361	)
Gain on settlement of asset retirement obligations			—				(1,787	)
Provision (benefit) for deferred income taxes			(1,660	)			8,153
Changes in assets and liabilities:
Decrease in accounts receivable			675				1,068
Decrease in other assets			276				216
Increase (decrease) in accounts payable			(4,932	)			203
Increase (decrease) in accrued liabilities			(4,601	)			8,546
Increase (decrease) in due to/from related parties			317				294
Net Cash Provided by Operating Activities			13,844				44,289
Cash Flows from Investing Activities:
Capital expenditures, including exploration expense			(11,209	)			(25,246	)
Proceeds from sale of property and equipment			1,910				6,305
Net Cash Used in Investing Activities			(9,299	)			(18,941	)
Cash Flows from Financing Activities:
Purchase of stock for treasury			(1,659	)			(2,553	)
Purchase of non-controlling interests			(101	)			(233	)
Proceeds from long-term bank debt and other long-term obligations			25,700				40,088
Repayment of long-term bank debt and other long-term obligations			(32,206	)			(62,719	)
Distribution to non-controlling interests			(34	)			(264	)
Net Cash Used in Financing Activities			(8,300	)			(25,681	)
Net Decrease in Cash and Cash Equivalents			(3,755	)			(333	)
Cash and Cash Equivalents at the Beginning of the Period			9,209				9,526
Cash and Cash Equivalents at the End of the Period		$	5,454			$	9,193
Supplemental Disclosures:
Income taxes paid		$	583			$	320
Interest paid		$	3,044			$	3,111

The accompanying notes are an integral part of these condensed consolidated financial statements

 

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PRIMEENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2015

(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, 2014. 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, 2015 and December 31, 2014, the condensed consolidated results of operations for the three and nine months ended September 30, 2015 and 2014, and the condensed consolidated results of cash flows and equity for the nine months ended September 30, 2015 and 2014. 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 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers.” ASU 2014-09 provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. ASU 2014-09 is effective for annual and interim reporting periods beginning after December 15, 2016, and can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption. Early application is not permitted. The Company is currently evaluating the effect that the adoption of ASU 2014-09 will have on the Company’s financial position, results of operations or cash flows. In August 2015, the FASB approved a delay of the effective date by one year as ASU 2015-14 finalized the delay.

(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 $101,000 and $233,000 for the nine months ended September 30, 2015 and 2014, respectively.

(3) Restricted Cash and Cash Equivalents:

Restricted cash and cash equivalents include $3.63 million and $3.88 million at September 30, 2015 and December 31, 2014, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at September 30, 2015 and December 31, 2014 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the accompanying condensed consolidated balance sheets.

 

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(4) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

 

(Thousands of dollars)		September 30, 2015				December 31, 2014
Accounts Receivable:
Joint interest billing		$	2,680			$	2,882
Trade receivables			1,878				1,980
Oil and gas sales			5,415				6,245
Other			2,135				1,751
			12,108				12,858
Less: Allowance for doubtful accounts			(469	)			(543	)
Total		$	11,639			$	12,315
Accounts Payable:
Trade		$	1,067			$	3,995
Royalty and other owners			6,820				8,444
Partner advances			1,774				1,344
Prepaid drilling deposits			—				786
Other			1,416				1,689
Total		$	11,077			$	16,258
Accrued Liabilities:
Compensation and related expenses		$	2,557			$	2,350
Property costs			4,319				9,204
Income tax			295				554
Other			629				293
Total		$	7,800			$	12,401

(5) Property and Equipment:

Property and equipment at September 30, 2015 and December 31, 2014 consisted of the following:

 

(Thousands of dollars)		September 30, 2015				December 31, 2014
Proved oil and gas properties, at cost		$	392,160			$	396,588
Less: Accumulated depletion and depreciation			190,294				188,988
Oil and Gas Properties, Net		$	201,866			$	207,600
Field and office equipment		$	28,313			$	27,403
Less: Accumulated depreciation			16,603				14,702
Field and Office Equipment, Net		$	11,710			$	12,701
Total Property and Equipment, Net		$	213,576			$	220,301

 

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(6) Long-Term Bank 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 September 30, 2015, the credit facility borrowing base was $112.5 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 (3.25% at September 30, 2015) plus applicable margin utilization rates that range from 1.50% to 2.00%, and LIBO rate loans at LIBO published rates plus applicable utilization rates (2.50% to 3.00% at September 30, 2015). At September 30, 2015, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 5.00% and 2.95%, respectively.

At September 30, 2015, the Company had a total of $84.5 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.44% and $28 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 3.39% for the nine months ended September 30, 2015 as compared to 3.48% for the nine months ended September 30, 2014.

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%. The Company recorded interest expense and paid $217,000 and $ 210,000 related to the settlement of interest rate swaps for the nine months ended September 30, 2015 and 2014, 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 September 30, 2015, the Company had a total of $6.0 million outstanding on this Equipment Loan.

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 requiring monthly payments (principal and interest) of $8,700 with a final maturity date of June 26, 2020. As of September 30, 2015, the Company had a total of $4.3 million outstanding on the Additional Equipment Loans.

 

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(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 2015 and thereafter for the operating leases are as follows:

 

(Thousands of dollars)		Operating Leases
2015		$	194
2016			793
2017			125
2018			16
Total minimum payments		$	1,128

Rent expense for office space for the nine months ended September 30, 2015 and 2014 was $571,000 and 579,000, respectively.

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2015 is as follows:

 

(Thousands of dollars)
Asset retirement obligation – December 31, 2014		$	12,501
Liabilities incurred			80
Liabilities settled			(1,108	)
Accretion expense			399
Asset retirement obligation – September 30, 2015		$	11,872

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, 2015, 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, 2015 and 2014, 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.

 

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(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 $101,000 and $233,000 for the nine months ended September 30, 2015 and 2014, 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.

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 as of September 30, 2015 and December 31, 2014:

 

September 30, 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 as of September 30, 2015
Assets
Commodity derivative contracts		$	—			$	—			$	5,649			$	5,649
Total assets		$	—			$	—			$	5,649			$	5,649
Liabilities
Interest rate derivative contracts			—				—				(76	)			(76	)
Total liabilities		$	—			$	—			$	(76	)		$	(76	)

 

December 31, 2014 (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 as of December 31, 2014
Assets
Commodity derivative contracts		$	—			$	—			$	16,901			$	16,901
Interest rate derivative contracts			—				—				26				26
Total assets		$	—			$	—			$	16,927			$	16,927
Liabilities
Interest rate derivative contracts			—				—				(170	)			(170	)
Total liabilities		$	—			$	—			$	(170	)		$	(170	)

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.

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.

 

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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, 2015.

 

(Thousands of dollars)
Net assets – December 31, 2014		$	16,757
Total realized and unrealized gains / losses:
Included in earnings (a)			3,470
Included in other comprehensive income			69
Purchases, sales, issuances and settlements			(14,723	)
Net assets – September 30, 2015		$	5,573

 

(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 derivative instruments are recognized in earnings.

Interest rate swap derivatives are treated as cash-flow hedges and are used to fix or float interest rates on existing debt. The value of these interest rate swaps at September 30, 2015 and December 31, 2014 is located in accumulated other comprehensive loss, net of tax. Settlement of the swaps is recorded within interest expense.

 

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The following table sets forth the effect of derivative instruments on the condensed consolidated balance sheets at September 30, 2015 and December 31, 2014:

 

				Fair Value
(Thousands of dollars)		Balance Sheet Location		September 30, 2015				December 31, 2014
Asset Derivatives:
Derivatives designated as cash-flow hedging instruments:
Interest rate swap contracts		Derivative assets		$	—			$	12
Interest rate swap contracts		Other assets		$	—			$	13
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts		Derivative Contracts			4,861				14,629
Natural gas commodity contracts		Derivative Contracts			788				2,273
Total				$	5,649			$	16,927
Liability Derivatives:
Derivatives designated as cash-flow hedging instruments:
Interest rate swap contracts		Derivative liability short-term		$	(76	)		$	(170	)
Total				$	(76	)		$	(170	)
Total derivative instruments				$	5,573			$	16,757

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, 2015 and 2014:

 

(Thousands of dollars)		Location of gain/loss recognized in income		Amount of gain/loss recognized in income
				2015				2014
Derivative designated as cash-flow hedge instruments:
Interest rate swap contracts		Interest expense		$	(217	)		$	(210	)
Derivatives not designated as cash-flow hedge instruments
Natural gas commodity contracts		Unrealized gain (loss) on derivative instruments, net			(1,484	)			565
Crude oil commodity contracts		Unrealized gain (loss) on derivative instruments, net			(9,768	)			1,796
Natural gas commodity contracts (a)		Realized gain (loss) on derivative instruments, net			2,061				(580	)
Crude oil commodity contracts		Realized gain (loss) on derivative instruments, net			12,878				(1,992	)
				$	3,470			$	(421	)

 

(a)

In January 2014, the Company unwound and monetized natural gas swaps with original settlement dates from January 2015 through December 2015 for net proceeds of $276,000. In September 2014, the Company unwound and monetized crude oil swaps with original settlement dates from January 2016 through December 2016 for net proceeds of $703,000. The $979,000 gains associated with these early settlement transactions are included in realized gain on derivative instruments for the nine months ended September 30, 2014.

 

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(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,
		2015												2014
		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		$	(2,575	)			2,314,704			$	(1.11	)		$	16,841				2,367,602			$	7.11
Effect of dilutive securities:
Options (a)			—				—				—				—				753,464
Diluted		$	(2,575	)			2,314,704			$	(1.11	)		$	16,841				3,121,066			$	5.40
		Three Months Ended September 30,
		2015												2014
		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		$	(655	)			2,311,873			$	(0.28	)		$	10,799				2,356,766			$	4.58
Effect of dilutive securities:
Options (a)			—								—				—				754,847
Diluted		$	(655	)			2,311,873			$	(0.28	)		$	10,799				3,111,613			$	3.47

 

(a)	The effect of the 767,500 outstanding stock options is antidilutive for the nine and three months ended September 30, 2015 due to net loss reported for the period.

 

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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 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 2015, we continued our drilling program in our West Texas and Mid-Continent regions. Through November 9, 2015, we participated in the drilling of 6 gross (2.6 net) new wells, all of these wells are producing. This includes our 12.5% participation in the drilling of the first two horizontal wells in our Apache joint venture. These wells were spudded on March 17, 2015 and July 25, 2015, respectively and both are currently producing.

It is our goal to increase our oil and gas reserves and production through the acquisition and development of oil and gas properties. Based upon the results of horizontal wells drilled by us and other offsetting operators and historical vertical well performance, we have decided to reduce the number of vertical wells in our drilling program and drill more horizontal wells. We believe horizontal development of our resource base will provide the opportunity to improve returns relative to vertical drilling by accessing a larger base of reserves in target zones with a lateral wellbore.

 

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RESULTS OF OPERATIONS

2015 and 2014 Compared

We reported net losses attributable to PrimeEnergy for the three and nine months ended September 30, 2015 of $0.66 million, or $0.28 per share and $2.58 million, or $1.11 per share, respectively as compared to net income of $10.80 million, or $4.58 per share and $16.84 million, or $7.11 per share for the three and nine months ended September 30, 2014, respectively. Net income decreased by $11.45 million or 106% and $19.42 million or 115% for the three and nine months ended September 30, 2015 as compared to the same periods during 2014 primarily due to decreases in oil and gas sales related to decreased commodity prices realized in 2015.

The significant components of net income are discussed below.

Oil and gas sales decreased $12.77 million, or 55% from $23.37 million for the three months ended September 30, 2014 to $10.61 million for the three months ended September 30, 2015 and decreased $36.48 million, or 49% from $73.64 million for the nine months ended September 30, 2014 to $37.16 million for the nine months ended September 30, 2015. 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 $45.95 per barrel, or 51% and $45.16 per barrel, or 49% on crude oil during the three and nine months ended September 30, 2015, respectively from the same periods in 2014 while our average well head price for natural gas decreased $2.28 per mcf, or 46% and $2.82 per mcf, or 50% during the three and nine months ended September 30, 2015, respectively from the same periods in 2014.

Our crude oil production decreased by 23,000 barrels, or 12% from 194,000 barrels for the third quarter 2014 to 171,000 barrels for the third quarter 2015 and decreased by 13,000 barrels, or 2% from 577,000 for the nine months ended September 30, 2014 to 564,000 barrels for the nine months ended September 30, 2015. Our natural gas production decreased by 55,000 mcf, or 5% from 1,206,000 mcf for the third quarter 2014 to 1,151,000 mcf for the third quarter 2015 and increased by 54,000 mcf, or 2% from 3,551,000 mcf for the nine months ended September 30, 2014 to 3,605,000 mcf for the nine months ended September 30, 2015. In general our production volumes remained flat as production from new wells offset the natural decline of existing properties. The third quarter decrease in oil production related to the temporary shut in of some of our West Texas wells for mechanical repairs.

The following table summarizes the primary components of production volumes and average sales prices realized for the three and nine months ended September 30, 2015 and 2014 (excluding realized gains and losses from derivatives).

 

		Three Months Ended September 30,												Nine Months Ended September 30,
		2015				2014				Increase / (Decrease)				2015				2014				Increase / (Decrease)
Barrels of Oil Produced			171,000				194,000				(23,000	)			564,000				577,000				(13,000	)
Average Price Received		$	43.84			$	89.79			$	(45.95	)		$	47.91			$	93.07			$	(45.16	)
Oil Revenue (In 000’s)		$	7,511			$	17,377			$	(9,866	)		$	27,044			$	53,656			$	(26,612	)
Mcf of Gas Produced			1,151,000				1,206,000				(55,000	)			3,605,000				3,551,000				54,000
Average Price Received		$	2.69			$	4.97			$	(2.28	)		$	2.81			$	5.63			$	(2.82	)
Gas Revenue (In 000’s)		$	3,096			$	5,995			$	(2,899	)		$	10,116			$	19,980			$	(9,864	)
Total Oil & Gas Revenue (In 000’s)		$	10,607			$	23,372			$	(12,765	)		$	37,160			$	73,636			$	(36,476	)

Realized gain (loss) on derivative instruments, net include net gains of $0.70 million and $4.79 million on the settlements of natural gas and crude oil derivatives, respectively for the third quarter 2015 and net gains of $0.02 million and $0.13 million on the settlements of natural gas and crude oil derivatives, respectively for the third quarter 2014. Realized gain (loss) on derivative instruments include net losses of $2.06 million and $12.88 million on the settlements of natural gas and crude oil derivatives, respectively for the nine months ended September 30, 2015 and net losses of $0.58 million and $1.99 million on the settlements of natural gas and crude oil derivatives, respectively for the nine months ended September 30, 2014. In the third quarter of 2014, we unwound and monetized crude oil swaps with original settlement dates from January 2016 through December 2016 for net proceeds of $0.70 million. The $0.70 million gain associated with this early settlement transaction is included in realized gain on derivative instruments for the three and nine months ended September 30, 2014. In addition, during the first quarter of 2014, we unwound and monetized natural gas swaps with original settlement dates from January 2015 through December 2015 for net proceeds of $0.28 million. The $0.28 million gain associated with this early settlement transaction is included in realized gain on derivative instruments for the nine months ended September 30, 2014.

 

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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,
		2015				2014				Decrease				2015				2014				Increase (Decrease)
Oil Price		$	71.81			$	90.48			$	(18.67	)		$	70.73			$	89.62			$	(18.89	)
Gas Price		$	3.30			$	4.98			$	(1.68	)		$	3.38			$	5.46			$	(2.08	)

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 and nine months ended September 30, 2015, we recognized net unrealized losses of $0.48 million and $1.48 million, respectively associated with natural gas fixed swap contracts and net unrealized losses of $1.67 million and $9.77 million, respectively associated with crude oil fixed swaps and collars due to market fluctuations in natural gas and crude oil futures market prices between December 31, 2014 and September 30, 2015. During the three and nine months ended September 30, 2014, we recognized net unrealized gains of $0.88 million and $0.56 million, respectively associated with natural gas fixed swap contracts and net unrealized gains of $7.48 million and $1.80 million, respectively associated with crude oil fixed swaps and collars due to market fluctuations in natural gas and crude oil futures market prices between December 31, 2013 and September 30, 2014.

Field service income decreased $0.97 million, or 15% from $6.47 million for the third quarter 2014 to $5.51 million for the third quarter 2015 and $3.33 million, or 17% from $19.83 million for the nine months ended September 30, 2014 to $16.50 million for the nine months ended September 30, 2015. This is a combined result of slightly reduced utilization and the market requiring us to charge lower rates to customers during the 2015 periods. Workover rig services represent the bulk of our field service operations, and while we were able to keep our rigs utilized during 2015, working rates have all decreased between the periods in our most active districts.

Lease operating expense decreased $2.15 million, or 20% from $10.98 million for the third quarter 2014 to $8.83 million for the third quarter 2015 and decreased $6.08 million, or 18% from $33.12 million for the nine months ended September 30, 2014 to $27.04 million for the nine months ended September 30, 2015. These decreases result from the industry wide costs saving measures implemented in response to the current commodity price environment. Where possible we have reduced company labor and support costs and have been successful in reducing costs with service vendors.

Field service expense decreased $0.48 million, or 9% from $5.15 million for the third quarter 2014 to $4.66 million for the third quarter 2015 and $2.17 million, or 14% from $15.72 million for the nine months ended September 30, 2014 to $13.55 million for the nine months ended September 30, 2015. Field service expenses primarily consist of salaries and vehicle operating expenses which have decreased during the nine months ended September 30, 2015 over the same period of 2014 as a direct result of decreased services and utilization of the equipment.

Depreciation, depletion, amortization and accretion on discounted liabilities decreased $0.14 million, or 1% from $5.79 million for the third quarter 2014 to $5.65 million for the third quarter 2015 and increased $0.38 million, or 0.2% from $16.75 million for the nine months ended September 30, 2014 to $16.79 million for the nine months ended September 30, 2015 These small fluctuations are related to the declining cost basis of the depletable properties combined with their production rate changes.

General and administrative expense decreased $1.51 million, or 35% from $4.29 million for the three months ended September 30, 2014 to $2.78 million for the three months ended September 30, 2015 and $2.55 million, or 22% from $11.82 million for the nine months ended September 30, 2014 to $9.27 million for the nine months ended September 30, 2015. The decrease in general and administrative expense in 2015 is largely due to decreased personnel costs including salaries, bonuses and employee related taxes and insurance.

Gain on sale and exchange of assets of $1.37 million and $5.62 million for the nine months ended September 30, 2015 and September 30, 2014, respectively consists of sales of non-essential oil and gas interests.

Interest expense decreased $0.10 million, or 10% from $0.98 million for the third quarter 2014 to $0.88 million for the third quarter 2015 and $0.35 million, or 12% from $3.10 million for the nine months ended September 30, 2014 to $2.75 million for the nine months ended September 30, 2015. This decrease results from the decrease in average debt outstanding during the 2015 periods.

 

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A benefit for income taxes of $0.31 million, or an effective tax rate of 32% was recorded for the third quarter 2015 versus a provision of $5.62 million, or an effective tax rate of 34% for the third quarter 2014 and a benefit of $1.33 million, or an effective tax rate of 34% was recorded for the nine months ended September 30, 2015 versus a provision of $8.53 million, or an effective tax rate of 31% for the nine months ended September 30, 2014. Our provision for income taxes can vary from the federal statutory tax rate of 34% primarily due to state taxes and percentage depletion deductions. We are entitled to percentage depletion on certain of our wells, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis, it creates a permanent difference, which would have the effect of lowering our effective rate.

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 months ended September 30, 2015 was $13.84 million compared $44.29 million for the nine months ended September 30, 2014. 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.

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 current borrowing base of $112.5 million and $28 million in availability at September 30, 2015. 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. 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. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months.

It is our goal to increase our oil and gas reserves and production through the acquisition and development of oil and gas properties. During 2015, we continued our drilling program in our West Texas and Mid-Continent regions. Based upon the results of horizontal wells drilled by us and other offsetting operators and historical vertical well performance, we have decided to reduce the number of vertical wells in our drilling program and drill more horizontal wells. We believe horizontal development of our resource base will provide the opportunity to improve returns relative to vertical drilling by accessing a larger base of reserves in target zones with a lateral wellbore.

During 2015 we intend to spend approximately $15 million in our drilling program primarily in the West Texas area. In our Mid-Continent region, the horizontal development is primarily in Kingfisher and Canadian counties where we have approximately 5,800 net acres which we believe have significant resource potential based on our drilling results and those of offset operators. We began our West Texas, Upton County horizontal drilling program in the first quarter of 2015, and will drill up to 4 wells in this phase at a net cost of approximately $10 million. The first well was spudded March 17, 2015 and the second well was spudded July 25, 2015 and 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 over the next 36 to 48 months at a cost of approximately $470 million. The actual number of wells to be drilled and timing of the drilling may vary based on commodity market conditions. We own various interests, ranging from 12.5% up to 50% interest in the lands to be developed in the program, and expect our share of these capital expenditures to be approximately $150 million. 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 have currently identified 104 proved undeveloped drilling locations there and believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional drilling opportunities.

We also continue to explore and consider opportunities to further expand our oilfield servicing revenues through additional investment in field service equipment. As of September 30, 2015, we have $10.3 million outstanding on our equipment financing facilities which are secured by substantially all of our field service equipment. However, the majority of our capital spending is

 

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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.

We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2015. For the nine month period ended September 30, 2015, we have spent $1.76 million 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 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 controls over financial reporting that occurred during the three months ended September 30, 2015 that materially affected, or are reasonably likely to materially affect, the Company’s internal controls 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, 2015, the Company purchased the following shares of common stock as treasury shares.

 

2015 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			15,980			$	68.73				270,968
February			774			$	59.34				270,194
March			2,506			$	54.00				267,688
April			50			$	59.40				267,638
May			226			$	57.52				267,412
June			379			$	56.02				267,033
July			695			$	56.56				266,338
August			316			$	55.91				266,022
September			4,404			$	64.74				261,618
Total/Average			25,330			$	65.49

 

(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 September 30, 2015, a total of 3,238,382 shares have been repurchased under this program for $53,843,126 at an average price of $16.63 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.

 

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Item 3.

DEFAULTS UPON SENIOR SECURITIES

None

 

Item 4.

RESERVED

 

Item 5.

OTHER INFORMATION

None

 

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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)
10.18		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 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).
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

 

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Exhibit No.
		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).
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).

 

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Exhibit No.
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)

 

 

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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 16, 2015				/s/ Charles E. Drimal, Jr.
(Date)				Charles E. Drimal, Jr.
				President
				Principal Executive Officer
November 16, 2015				/s/ Beverly A. Cummings
(Date)				Beverly A. Cummings
				Executive Vice President
				Principal Financial Officer

 

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