PrimeEnergy Resources (PNRG) 10-Q 2019 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM10-Q

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

For the Quarterly Period Ended September 30, 2019

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 Number0-7406

PrimeEnergy Resources 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)

Securities registered pursuant to Section 12(b) of the Act

Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, par value $0.10 (per share)	PNRG	NASDAQ

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  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of RegulationS-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule12b-2 of the Exchange Act.

Large Accelerated Filer	☐	Accelerated Filer	☐
Non-Accelerated Filer	☐	Smaller Reporting Company	☒
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule12b-2 of the Exchange Act).    Yes  ☐    No  ☒

The number of shares outstanding of each class of the Registrant’s Common Stock as of November 1, 2019, was: Common Stock, $0.10 par value 2,005,375 shares.

PrimeEnergy Resources Corporation

Index to Form10-Q

September 30, 2019

	Page
Part I — Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets – September  30, 2019 and December 31, 2018		3
Condensed Consolidated Statements of Operations – For the nine and three months ended September 30, 2019 and 2018		4
Condensed Consolidated Statement of Equity – For the nine months ended September 30, 2019 and 2018		5
Condensed Consolidated Statements of Cash Flows – For the nine months ended September 30, 2019 and 2018		7
Notes to Condensed Consolidated Financial Statements – September  30, 2019		8-16
Item  2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation		17-27
Item 3. Quantitative and Qualitative Disclosures About Market Risk		27
Item 4. Controls and Procedures		27
Part II — Other Information
Item 1. Legal Proceedings		28
Item 1A. Risk Factors		28
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		28
Item 3. Defaults Upon Senior Securities		28
Item 4. Reserved		28
Item 5. Other Information		28
Item 6. Exhibits		29
Signatures		31

2

PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS –Unaudited

(Thousands of dollars)

	September 30, 2019			December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents	$	4,357		$	6,315
Accounts receivable, net		17,696			14,961
Prepaid obligations		383			640
Derivative asset short-term		1,838			1,674
Other current assets		133			144
Total Current Assets		24,407			23,734
Property and Equipment, at cost
Oil and gas properties (successful efforts method), net		211,589			223,669
Field and office equipment, net		6,833			6,756
Total Property and Equipment, Net		218,422			230,425
Derivative asset long-term and other assets.		476			893
Total Assets	$	243,305		$	255,052
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	9,452		$	9,553
Accrued liabilities		9,062			18,431
Current portion of long-term debt		—			698
Current portion of asset retirement and other obligations		1,967			1,687
Derivative liability short-term		361			88
Due to Related Parties		—			5
Total Current Liabilities		20,842			30,462
Long-Term Bank Debt		61,500			65,547
Asset Retirement Obligations		19,372			19,647
Derivative Liability Long-Term		—			10
Deferred Income Taxes		34,094			32,828
Other Long-Term Obligations		590			555
Total Liabilities		136,398			149,049
Commitments and Contingencies
Equity
Common stock, $.10 par value; 2019 and 2018: Authorized and Issued: 2,810,000 shares; outstanding 2019: 2,008,693 shares; 2018: 2,039,919 shares		281			281
Paid-in capital		7,653			7,388
Retained earnings		130,893			125,644
Treasury stock, at cost; 2019: 801,307 shares; 2018: 770,081 shares		(35,412	)		(31,304	)
Total Stockholders’ Equity – PrimeEnergy		103,415			102,009
Non-controlling interest		3,492			3,994
Total Equity		106,907			106,003
Total Liabilities and Equity	$	243,305		$	255,052

3

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTSOF OPERATIONS– Unaudited

Three and nine months ended September 30, 2019 and 2018

(Thousands of dollars, except per share amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Revenues
Oil sales	$	16,928		$	20,960		$	55,370		$	57,863
Natural gas sales		1,467			2,174			5,057			6,526
Natural gas liquids sales		1,687			3,890			6,906			9,588
Realized loss on derivative instruments, net		(195	)		(1,349	)		(968	)		(2,925	)
Field service income		4,866			4,470			14,356			13,132
Administrative overhead fees		1,356			1,414			4,168			4,344
Unrealized gain (loss) on derivative instruments, net		2,071			(2,194	)		(819	)		(8,151	)
Other income		2			37			65			59
Total Revenues		28,182			29,402			84,135			80,256
Costs and Expenses
Lease operating expense		8,207			9,533			24,432			26,867
Field service expense		3,972			3,728			11,616			10,157
Depreciation, depletion, amortization and accretion on discounted liabilities		9,255			7,883			27,805			23,715
General and administrative expense		2,854			2,250			12,625			10,761
Total Costs and Expenses		24,288			23,394			76,478			71,500
Gain on Sale and Exchange of Assets		114			511			1,803			3,168
Income from Operations		4,008			6,519			9,460			11,924
Other Income (Expense)
Interest Income		7			12			17			34
Interest (Expense)		(919	)		(834	)		(2,907	)		(2,613	)
Income Before Income Taxes		3,096			5,697			6,570			9,345
Income Taxes Expense (Benefit)		569			1,424			1,252			2,332
Net Income		2,527			4,273			5,318			7,013
Less: Net Income (Loss) Attributable toNon-Controlling Interests		15			(80	)		69			(102	)
Net Income Attributable to PrimeEnergy	$	2,512		$	4,353		$	5,249		$	7,115
Basic Income Per Common Share	$	1.25		$	2.10		$	2.61		$	3.38
Diluted Income Per Common Share	$	0.91		$	1.54		$	1.90		$	2.49

4

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTOF EQUITY –Unaudited

Nine months ended September 30, 2019

(Thousands of dollars)

	Common Stock				Additional Paid in		Retained			Treasury			Total Stockholders’ Equity			Non- Controlling			Total
	Shares		Amount		Capital		Earnings			Stock			PrimeEnergy			Interest			Equity
Balance at December 31, 2018		2,810,000	$	281	$	7,388	$	125,644		$	(31,304	)	$	102,009		$	3,994		$	106,003
Repurchase 31,226 shares of common stock		—		—		—		—			(4,108	)		(4,108	)		—			(4,108	)
Net income		—		—		—		5,249			—			5,249			69			5,318
Purchase ofNon- controlling Interest		—		—		265		—			—			265			(571	)		(306	)
Balance at September 30, 2019		2,810,000	$	281	$	7,653	$	130,893		$	(35,412	)	$	103,415		$	3,492		$	106,907
Balance at December 31, 2018		2,810,000	$	281	$	7,388	$	125,644		$	(31,304	)	$	102,009		$	3,994		$	106,003
Repurchase 5,693 shares of common stock		—		—		—		—			(735	)		(735	)		—			(735	)
Net income (loss)		—		—		—		(3,038	)		—			(3,038	)		7			(3,031	)
Purchase ofNon- controlling Interest		—		—		224		—			—			224			(480	)		(256	)
Balance at March 31, 2019		2,810,000	$	281	$	7,612	$	122,606		$	(32,039	)	$	98,460		$	3,521		$	101,981
Repurchase 16,718 shares of common stock		—		—		—		—			(2,277	)		(2,277	)		—			(2,277	)
Net income		—		—		—		5,775			—			5,775			47			5,822
Purchase ofNon- controlling Interest		—		—		—		—			—			—			—			—
Balance at June 30, 2019		2,810,000	$	281	$	7,612	$	128,381		$	(34,316	)	$	101,958		$	3,568		$	105,526
Repurchase 8,815 shares of common stock		—		—		—		—			(1,096	)		(1,096	)		—			(1,096	)
Net income		—		—		—		2,512			—			2,512			15			2,527
Purchase ofNon- controlling Interest		—		—		41		—			—			41			(91	)		(50	)
Balance at September 30, 2019		2,810,000	$	281	$	7,653	$	130,893		$	(35,412	)	$	103,415		$	3,492		$	106,907

5

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTOF EQUITY –Unaudited

Nine months ended September 30, 2018

(Thousands of dollars)

	Common Stock				Additional Paid in		Retained			Treasury			Total Stockholders’ Equity –			Non-Controlling			Total
	Shares		Amount		Capital		Earnings			Stock			PrimeEnergy			Interest			Equity
Balance at December 31, 2017		3,836,397	$	383	$	8,729	$	138,320		$	(52,123	)	$	95,309		$	7,130		$	102,439
Repurchase 107,565 shares of common stock		—		—		—		—			(6,300	)		(6,300	)		—			(6,300	)
Net income (loss)		—		—		—		7,115			—			7,115			(102	)		7,013
Purchase ofNon- controlling Interest		—		—		43		—			—			43			(53	)		(10	)
Balance at September 30, 2018		3,836,397	$	383	$	8,772	$	145,435		$	(58,423	)	$	96,167		$	6,975		$	103,142
Balance at December 31, 2017		3,836,397	$	383	$	8,729	$	138,320		$	(52,123	)	$	95,309		$	7,130		$	102,439
Repurchase 67,218 shares of common stock		—		—		—		—			(3,379	)		(3,379	)		—			(3,379	)
Net income (loss)		—		—		—		3,286			—			3,286			15			3,301
Balance at March 31, 2018		3,836,397	$	383	$	8,729	$	141,606		$	(55,502	)	$	95,216		$	7,145		$	102,361
Repurchase 5,621 shares of common stock		—		—		—		—			(317	)		(317	)		—			(317	)
Purchase ofNon- controlling Interest		—		—		43		—			—			43			(53	)		(10	)
Net income (loss)		—		—		—		(524	)		—			(524	)		(37	)		(561	)
Balance at June 30, 2018		3,836,397	$	383	$	8,772	$	141,082		$	(55,819	)	$	94,418		$	7,055		$	101,473
Repurchase 34,726 shares of common stock		—		—		—		—			(2,604	)		(2,604	)		—			(2,604	)
Net income (loss)		—		—		—		4,353			—			4,353			(80	)		4,273
Balance at September 30, 2018		3,836,397	$	383	$	8,772	$	145,435		$	(58,423	)	$	96,167		$	6,975		$	103,142

6

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS –Unaudited

Nine months ended September 30, 2019 and 2018

(Thousands of dollars)

	2019			2018
Cash Flows from Operating Activities:
Net Income includingnon-controlling interest	$	5,318		$	7,013
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities		27,805			23,715
Gain on sale of properties		(1,803	)		(3,168	)
Unrealized loss on derivative instruments, net		819			8,151
Provision for deferred income taxes		1,266			2,363
Changes in operating assets and liabilities:
Accounts receivable		(2,735	)		2,162
Due to related parties		(5	)		(35	)
Other assets		268			376
Accounts payable		(101	)		(14,000	)
Accrued liabilities		(9,369	)		(1,030	)
Net Cash Provided by Operating Activities		21,463			25,547
Cash Flows from Investing Activities:
Capital expenditures		(16,070	)		(29,317	)
Proceeds from sale of properties and equipment		1,808			2,623
Net Cash Used in Investing Activities		(14,262	)		(26,694	)
Cash Flows from Financing Activities:
Purchase of stock for treasury		(4,108	)		(6,300	)
Purchase ofnon-controlling interests		(306	)		(10	)
Proceeds from long-term bank debt and other long-term obligations		25,000			42,800
Repayment of long-term bank debt and other long-term obligations		(29,745	)		(36,112	)
Net Cash (Used in) Provided by Financing Activities		(9,159	)		378
Cash and Cash Equivalents Period Decrease		(1,958	)		(769	)
Cash and Cash Equivalents at the Beginning of the Period		6,315			8,438
Cash and Cash Equivalents at the End of the Period	$	4,357		$	7,669
Supplemental Disclosures:
Income taxes paid	$	129		$	4,340
Interest paid	$	2,920		$	2,761

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

7

PRIMEENERGY RESOURCES CORPORATION

NOTESTo CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(Unaudited)

(1) Basis of Presentation:

The accompanying condensed consolidated financial statements of PrimeEnergy Resources Corporation (“PrimeEnergy” 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 Form10-K for the year ended December 31, 2018. 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, 2019 and December 31, 2018, the condensed consolidated results of operations, cash flows and equity for the nine months ended September 30, 2019 and 2018.

As of September 30, 2019, PrimeEnergy’s significant accounting policies are consistent with those discussed in Note 1—Description of Operations and Significant Accounting Policies of its consolidated financial statements contained in PrimeEnergy’s Annual Report on Form10-K for the fiscal year ended December 31, 2018, with the exception of Accounting Standards Update (ASU)2016-02, “Leases (Topic 842)” discussed below. 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 Adopted Accounting Pronouncements

Leases.In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”)2016-02, “Leases (Topic 842)” (“ASC 842”) which supersedes the lease recognition requirements in Accounting Standards Codification (“ASC”) 840, “Leases” (“ASC 840”), and requires lessees to recognize lease assets and lease liabilities for those leases previously classified as operating leases. The Company adopted ASC 842 as of January 1, 2019 using the modified retrospective transition method. The Company elected to apply the transition guidance under ASU2018-11, “Leases (Topic 842) Targeted Improvements,” in which ASC 842 is applied at the adoption date, while the comparative periods continue to be reported in accordance with historic accounting under ASC 840. This standard does not apply to leases to explore for or use minerals, oil or gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.

ASC 842 allowed for the election of certain practical expedients at adoption to ease the burden of implementation. At implementation, the Company elected to (i) maintain the historical lease classification for leases prior to January 1, 2019, (ii) maintain the historical accounting treatment for land easements that existed at adoption, (iii) use historical practices in assessing the lease term of existing contracts at adoption, (iv) combine lease andnon-lease components of a contract as a single lease and (v) not record short-term leases on the consolidated balance sheet, all in accordance with ASC 842.

The adoption of ASC 842 did not have a material impact on the consolidated statements of operations and had no impact on cash flows. The Company did not record a change to its opening retained earnings as of January 1, 2019, as there was no material change to the timing or pattern of recognition of lease costs due to the adoption of ASC 842. As of September 30, 2019, the Company has operating lease assets and liabilities of $305 thousand and a financing lease included in property and equipment and lease liabilities for $11 thousand.

New Pronouncements Issued But Not Yet Adopted

In August 2018, the FASB issued ASU2018-13, “Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement,” which changes the disclosure requirements for fair value measurements by removing, adding, and modifying certain disclosures. ASU2018-13 is effective for financial statements issued for annual periods beginning after December 15, 2019, and interim periods within those annual periods. Early adoption is permitted. The company is currently evaluating the impact of adoption of this ASU on its related disclosures and does not expect it to have a material impact on its financial statements.

8

In August 2018, the FASB issued ASU2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract.” This pronouncement clarifies the requirements for capitalizing implementation costs in cloud computing arrangements and aligns them with the requirements for capitalizing implementation costs incurred to develop or obtaininternal-use software. This pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued. The Company is currently evaluating the impact of adoption of this ASU on its consolidated financial statements and does not expect it to have a material impact.

(2) Acquisitions and Dispositions:

Historically the Company has repurchased the interests of the partners and trust unit holders in the oil and gas limited partnerships (the “Partnerships”) and the 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 $306,000 and $10,000 for the nine months ended September 30, 2019 and 2018, respectively.

During the first nine months of 2019 and 2018, the Company sold or farmed out interests in certainnon-core oil and natural gas properties and undeveloped acreage through a number of separate, individually negotiated transactions in exchange for cash or cash and a royalty or working interest in Texas, Oklahoma, Colorado, Kansas and Wyoming. Proceeds under these agreements were $1.6 million and $3 million, respectively.

During the first nine months of 2018, the Company acquired approximately 464 net mineral acres and working interest in 53 oil and gas wells for $6.08 million.

(3) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

(Thousands of dollars)	September 30, 2019			December 31, 2018
Accounts Receivable:
Joint interest billing	$	6,360		$	1,976
Trade receivables		2,177			1,979
Oil and gas sales		9,148			6,112
Tax refund receivable		—			4,760
Other		285			358
		17,970			15,185
Less: Allowance for doubtful accounts		(274	)		(224	)
Total	$	17,696		$	14,961
Accounts Payable:
Trade	$	1,628		$	1,174
Royalty and other owners		5,609			6,197
Due to partners		1,509			1,357
Other		706			825
Total	$	9,452		$	9,553
Accrued Liabilities:
Compensation and related expenses	$	3,528		$	2,907
Property costs		5,285			14,993
Other		249			531
Total	$	9,062		$	18,431

9

(4) Property and Equipment:

Property and equipment at September 30, 2019 and December 31, 2018 consisted of the following:

(Thousands of dollars)	September 30, 2019			December 31, 2018
Proved oil and gas properties, at cost	$	526,306		$	514,821
Less: Accumulated depletion and depreciation		(314,717	)		(291,152	)
Oil and Gas Properties, Net	$	211,589		$	223,669
Field and office equipment	$	27,533		$	27,252
Less: Accumulated depreciation		(20,700	)		(20,496	)
Field and Office Equipment, Net	$	6,833		$	6,756
Total Property and Equipment, Net	$	218,422		$	230,425

(5) Long-Term Debt:

Bank Debt:

On February 15, 2017, the Company and its lenders entered into a Third Amended and Restated Credit Agreement (the “2017 Credit Agreement”) with a maturity date of February 15, 2021. The Second Amended and Restated Credit Agreement and subsequent amendments were amended and restated by the 2017 Credit Agreement. Pursuant to the terms and conditions of the 2017 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $300 million subject to a borrowing base that is determined semi-annually by the lenders based upon the Company’s financial statements and the estimated value of the Company’s oil and gas properties, in accordance with the Lenders’ customary practices for oil and gas loans. The credit facility is secured by substantially all of the Company’s oil and gas properties. The 2017 Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio, total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio and interest coverage ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships.

On December 22, 2017, the Company and its lenders entered into a First Amendment to the Third Amended and Restated Credit Agreement. The credit agreement includes the addition of a new lender and retains all other aspects of the original credit agreement. As of the effective date of this amendment the Company’s borrowing base was increased to $85 million.

On July 17, 2018, the Company and its lenders entered into a Second Amendment to the Third Amended and Restated Credit Agreement. The credit agreement includes modifications for the borrowing base utilization margins and rates by type of borrowing, revises minimum quantifications for individual borrowings, reduces the overall percentage required for commodity hedge agreements, modifies the requirements placed on the companies’ ability to purchase equity interests and retains all other aspects of the original credit agreement. As of the effective date of this amendment the Company’s borrowing base was increased to $90 million.

On January 8, 2019, the Company and its lenders entered into a Third Amendment to the Third Amended and Restated Credit Agreement. The credit agreement includes additions for a Beneficial Ownership Certification on the effective date of the amendment. The agreement includes further clarifications for potential Libor loan market rate issues, swap agreement modifications and retains all other aspects of the original credit agreement. As of the effective date of this amendment the Company’s borrowing base was increased to $100 million. Effective on June 26, 2019 the Company’s lenders adjusted the borrowing base to $90 million.

At September 30, 2019, the Company had a total of $61.5 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 5.15% and $28.5 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 5.44% for the nine months ended September 30, 2019 as compared to 5.30% for nine months ended September 30, 2018. The Company’s borrowings under this credit facility approximates fair value because the interest rates are variable and reflective of market rates.

Equipment Loans:

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.

10

On January 12, 2018, the Company made a principal payment towards the third interim loan in the amount of $20,858. Effective with the payment due of January 26, 2018 the required monthly payments (principal and interest) on this loan changed to $7,986 with a continuing effective rate of 3.50% and a final maturity of June 26, 2020.

On May 23, 2019, the Company made its final payment towards both the second and third loans. At this time all equipment loans were paid in full and the field service equipment liens secured by these loans were cancelled and all titles returned to the Company.

(6) Other Long-Term Obligations and Commitments:

Operating Leases:

The Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Leases assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. A new finance lease for office equipment is included in property and equipment, other current liabilities and other long-term liabilities this quarter. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The weighted average discount rate used was 5.5%. Certain leases may contain variable costs above the minimum required payments and are not included in theright-of-use assets or liabilities. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded on the balance sheet.

Operating lease costs for the nine months ended September 30, 2019 were $291 thousand. Cash payments included in the operating lease cost for nine months ended September 30, 2019 were $296 thousand. The weighted-average remaining operating lease terms is 10 months. The amortization and interest expense for financing lease amounted to $3,100 and the cash payment for the lease was $3,200 and the lease term remaining was for 18 months.

The payment schedule for the Company’s operating and financing lease obligations as of September 30, 2019 is as follows:

(Thousands of dollars)	Operating Leases			Financing Leases
2019	$	149		$	2
2020		155			8
2021		17			2
Total undiscounted lease payments	$	321		$	12
Less: Amount associated with discounting		(16	)		(1	)
Net operating lease liabilities	$	305		$	11

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2019 is as follows:

(Thousands of dollars)	September 30, 2019
Asset retirement obligation at December 31, 2018	$	21,334
Liabilities incurred		4
Liabilities settled		(1,119	)
Accretion expense		840
Asset retirement obligation at September 30, 2019	$	21,059

11

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.

(7) 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.

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.

(8) 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, 2019 and December 31, 2018, 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.

(9) 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 interests totaling $306,000 and $10,000 for the nine months ended September 30, 2019 and 2018, respectively.

(10) 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 natural gas, crude oil price swaps and natural gas liquid 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 September 30, 2019 and December 31, 2018:

September 30, 2019	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at September 30, 2019
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	1,838		$	1,838
Total assets		—	$	—	$	1,838		$	1,838
Liabilities
Commodity derivative contracts	$	—	$	—	$	(361	)	$	(361	)
Total liabilities	$	—	$	—	$	(361	)	$	(361	)

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December 31, 2018	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, 2018
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	2,394		$	2,394
Total assets	$	—	$	—	$	2,394		$	2,394
Liabilities
Commodity derivative contract	$	—	$	—	$	(98	)	$	(98	)
Total liabilities	$	—	$	—	$	(98	)	$	(98	)

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 , crude oil, natural gas liquids, 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.

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, 2019.

(Thousands of dollars)
Net Asset– December 31, 2018	$	2,296
Total realized and unrealized (gains) losses:
Included in earnings (a)		(1,787	)
Purchases, sales, issuances and settlements		968
Net Assets September 30, 2019	$	1,477

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

Derivative 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 are treated as cash-flow hedges and are used to fix our floating interest rates on existing debt. The value of interest rate swaps if applicable, would be recorded in accumulated other comprehensive loss, net of tax. There are no current interest rate swaps for the periods ending September 30, 2019 and December 31, 2018.

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The following table sets forth the effect of derivative instruments on the consolidated balance sheets at September 30, 2019 and December 31, 2018:

			Fair Value
(Thousands of dollars)	Balance Sheet Location		September 30, 2019			December 31, 2018
Asset Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Natural gas commodity contracts		Derivative asset short-term	$	67		$	63
Natural gas liquid contracts		Derivative asset short-term		123			138
Crude oil commodity contracts		Derivative asset short-term		1,648			1,473
Natural gas commodity contracts		Derivative asset long-term and other assets		—			7
Crude oil commodity contracts		Derivative asset long-term and other assets		—			713
Total			$	1,838		$	2,394
Liability Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts		Derivative liability short-term	$	(361	)	$	—
Natural gas commodity contracts		Derivative liability short-term		—			(75	)
Natural gas liquid contracts		Derivative liability short-term		—			(13	)
Natural gas commodity contracts		Derivative liability long-term		—			(10	)
Total			$	(361	)	$	(98	)
Total derivative instruments			$	1,477		$	2,296

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the nine-month period ended September 30, 2019 and 2018:

	Location of gain (loss) recognized in income	Amount of gain/loss recognized in income
(Thousands of dollars)		2019			2018
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized gain (loss) on derivative instruments, net	$	82		$	(359	)
Crude oil commodity contracts	Unrealized loss on derivative instruments, net		(900	)		(7,148	)
Natural gas liquids contracts	Unrealized loss on derivative instruments, net		(1	)		(645	)
Natural gas commodity contracts	Realized gain on derivative instruments, net		90			124
Crude oil commodity contracts	Realized loss on derivative instruments, net		(1,302	)		(2,895	)
Natural gas liquids contracts	Realized gain (loss) on derivative instruments, net		244			(154	)
		$	(1,787	)	$	(11,077	)

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(11) 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,
	2019						2018
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	5,249		2,008,593	$	2.61	$	7,115		2,102,853	$	3.38
Effect of dilutive securities:
Options				760,972						754,558
Diluted	$	5,249		2,769,565	$	1.90	$	7,115		2,857,411	$	2.49
	Three Months ended September 30,
	2019						2018
	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	$	2,512		2,008,688	$	1.25	$	4,353		2,069,231	$	2.10
Effect of dilutive securities:
Options				760,552						756,366
Diluted	$	2,512		2,769,240	$	0.91	$	4,353		2,825,597	$	1.54

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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.

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 andnon-producing properties located primarily in Texas, Oklahoma and West Virginia. 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 the majority of our developed and undeveloped acreage which is nearly all held by production. In the Permian Basin of West Texas and eastern New Mexico the Company maintains an acreage position of approximately 19,900 gross (12,560 net) acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused. Recent results from our wells and the wells of other operators have proven the potential of the Lower Spraberry, Jo Mill, and Wolfcamp A intervals, in addition to the Middle Wolfcamp. We believe our Permian Basin acreage has the resource potential to support the future drilling of as many as 375 horizontal wells.

In Oklahoma we maintain an acreage position of approximately 55,880 gross (10,700 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Garfield, Major, Grady, and Garvin counties. We believe approximately 3,460 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 105 new horizontal wells based on two reservoir targets and four to eight wells per reservoir per section.

Future development plans are established based on various factors, including the expectation of available cash flows from operations and availability of funds under our revolving credit facility.

District Information

The following table represents certain reserve and well information as of December 31, 2018.

	Appalachian		Gulf Coast		Mid- Continent		West Texas		Other		Total
Proved Reserves as of December 31, 2018 (MBoe)
Developed		559		814		2,839		8,401		8		12,622
Undeveloped		—		—		43		—		—		43
Total		559		814		2,882		8,401		8		12,665
Average Daily Production (Boe per day)		244		572		977		4,248		7		6,048
Gross Productive Wells (Working Interest and ORRI Wells)		547		293		580		558		105		2,083
Gross Productive Wells (Working Interest Only)		500		263		430		519		45		1,757
Net Productive Wells (Working Interest Only)		469		164		227		256		4		1,120
Gross Operated Productive Wells		476		211		243		354		—		1,284
Gross Operated Water Disposal, Injection and Supply wells		1		9		67		7		—		84

In several of our regions we operate field service groups to service our operated wells and locations as well as third-party operators in the area. These services consist of well service support, site preparation and construction services for drilling and workover operations. Our operations are performed utilizing workover or swab rigs, water transport trucks, saltwater disposal facilities, various land excavating equipment and trucks we own and that are operated by our field employees.

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West Texas Region

Our West Texas activities are concentrated in the Permian Basin in Texas and New Mexico. The Spraberry field, discovered in 1949, encompasses eight counties in West Texas and the Company believes it is the second largest oil field in the United States. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casing-head gas with an average energy content of 1,400 Btu. The oil and gas are produced primarily from six formations; the Upper and Lower Spraberry, the Wolfcamp, the Strawn and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. This region is managed from our office in Midland, Texas.

As of December 31, 2018, we had 519 wells (256 net) in the West Texas area, of which 361 wells are operated by us. Principal producing intervals for the Company are in the Spraberry, Jo Mill, Wolfcamp and San Andres formations at depths ranging from 5,500 to 12,500 feet. Average net daily production in 2018 was 4,248 Boe. At December 31, 2018, we had 8,401 MBoe of proved reserves in the West Texas area, or 66% of our total proved reserves. We maintain an acreage position of approximately 19,900 gross (12,560 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing nine workover rigs, five hot oiler trucks, one kill truck, and one roustabout truck. Services including well service support, site preparation and construction services for drilling and workover operations are provided to third-party operators as well as utilized in our own operated wells and locations.

In the fourth quarter of 2018, in our West Texas horizontal drilling program, the Company participated for 49.3% interest in eightone-mile horizontal wells drilled in the Middle Wolfcamp. These wells were brought on production in February, 2019. The total cost of these eight wells and their facilities is approximately $48.3 million with the Company’s share being $23.7 million. Through September, these wells have produced approximately 670,000 barrels of oil, along with associated gas. PrimeEnergy’s net revenue interest is 36.82%, therefore, our share of the oil recovered in just the first eight months is approximately 247,000 barrels. We are pleased with the initial performance of these eight wells and expect 100% capital recover in approximately 28 months.

In the second quarter of 2019, in our West Texas horizontal drilling program, we completed three new horizontal wells on our Kashmir Tract: one in the Wolfcamp A, one in the Jo Mill, and one in the Lower Spraberry. These intervals were previously not proven as horizontal target reservoirs for our acreage in Upton County. In the first 120 days of production the three wells have produced 137,800 gross barrels of oil along with associated wellhead gas. PrimeEnergy has 47% to 49% working interest and 39% to 40.7% net revenue interest in the Lower Spraberry and Jo Mill wells, from which 76% of the production has been recoveredto-date. The Company has 5.3% working interest and 3.9% net revenue interest in the Wolfcamp A well. Our share of the gross $26 million cost to drill and complete these three wells is approximately $8.9 million. The three new Kashmir horizontal wells in Upton County have confirmed the economic viability of these three shallow target intervals, not only for the 1,300 acre block in which they were drilled, but also for the 3,260 acre block two miles to the west that we are also developing with Apache. In addition, two offset operators have recently completed wells in the Jo Mill and Lower Spraberry offset our 3,260 acre block, further proving the productive capabilities of these target benches.

Apache has indicated plans to drill 16 additional horizontal wells on the Kashmir Tract in early 2020. This 16 well program will not only focus on developing the Wolfcamp A, Jo Mill, and Lower Spraberry, but also investigate an additional target reservoir, the Middle Spraberry Shale. One of the 16 wells to be drilled in early 2020 will be landed in the Middle Spraberry Shale. Following the initial well there are five additional Middle Spraberry Shale wells that are likely to be drilled on the Kashmir Tract in the near future. The gross cost of the total additional 21 wells would be approximately $185 million, with the Company’s share being approximately $69 million. In the 3,260 acre block, Prime holds leases with interest varying from 14% to 56%.    Given the strong initial production performance of our recent shallow horizontals we anticipate an additional 80 wells to be drilled with Apache in this block over the next few years. The gross cost of 80 wells here would be approximately $648 million, with the Company’s share being approximately $281 million. The actual number of wells that will be drilled, the cost, and the timing of drilling will vary based upon many factors, including commodity market conditions.

In the Permian Basin of West Texas the Company maintains an acreage position of approximately 19,900 gross (12,560 net) acres primarily in Reagan, Upton, Martin and Midland counties. We believe this acreage has significant resource potential in approximately 10 reservoir benches, including benches of the Spraberry, Jo Mill, and Wolfcamp formations to support the potential for drilling as many as 375 additional horizontal wells. The Company’s share of the capital investment for a 375 well development program would be approximately $1.5 billion dollars assuming an average cost of $8.5 million per well and an average working interest of 50% in each well.

18

Mid-Continent Region

OurMid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2018, we had 580 wells (227 net) in theMid-Continent area, of which 310 wells are operated by us. Principal producing intervals are in the Roberson, Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet. Average net daily production in 2018 was 977 Boe. At December 31, 2018, we had 2,882 MBoe of proved reserves in theMid-Continent area, or 23% of our total proved reserves. We maintain an acreage position of approximately 55,880 gross (10,700 net) acres in this region, primarily in Canadian, Kingfisher, Grant and Garvin counties. We operate a field service group in this region from a field office in Elmore City, utilizing one workover rig and one saltwater hauling truck. OurMid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company owned interest in several counties in the STACK and SCOOP shale plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian, Woodford, and Hunton formations.

In theMid-Continent Region, in 2018, the Company participated in 11 wells in Oklahoma, with six of these on production byyear-end. Another five of the 11 wells were drilled by Marathon in the “Ruthie 1609” Tract in Kingfisher County and broughton-line in March of 2019. Prime participated with 11.87% interest in the five new Ruthie wells investing approximately $4.5 million. This group of wells is showing strong initial production performance. In 2019, Encana Corporation has continued development in the area with the drilling of six wells on the Slash Tract and six on the WM Wallace Tract in which PrimeEnergy has 1.54% and 7.64% working interest respectively. These wells are expected to beon-line in the fourth quarter of 2019. Our share of the drilling and completion costs of these 12 wells is expected to be $3.8 million. Also in Oklahoma, the Company recently participated with Roan Resources, Inc. in the drilling of seven wells in Grady County, Oklahoma. The Company has 10% interest in one of these wells and less than one percent interest in the remaining six. The estimated total expenditure net to the Company for these seven wells is approximately $1.3 Million. Three of the seven wells came on-line in July, 2019 and the remaining four wells were drilled, but due to a pending take-over of Roan Resources by Citizen Energy, are unlikely to be completed until 2020. In addition, there are eight new wells spud in the first and second quarter of 2019 from which the Company will receive a minor over-riding royalty interest.

The Company’s horizontal activity in Oklahoma is primarily focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 3,460 net leasehold acres within the SCOOP/STACK shale plays. We believe this acreage has significant additional resource potential that could support the drilling of as many as 105 new horizontal wells based on an estimate of eight wells per section: four in the Mississippian and four in the Woodford Shale.

Appalachian Region

Our Appalachian activities are concentrated primarily in West Virginia. This region is managed from our office in Charleston, West Virginia. Our assets in this region include a large acreage position and a high concentration of wells. At December 31, 2018, we had interest in 500 wells (469 net), of which 477 wells are operated. There are multiple producing intervals that include the Big Lime, Injun, Blue Monday, Weir, Berea, Gordon and Devonian Shale formations at depths primarily ranging from 1,600 to 5,600 feet. Average net daily production in 2018 was 244 Boe. While natural gas production volumes from Appalachian reservoirs are relatively low on aper-well basis compared to other areas of the United States, the productive life of Appalachian reserves is relatively long. At December 31, 2018, we had 559 MBoe of proved developed reserves (substantially all natural gas) in the Appalachian region, constituting 4% of our total proved reserves. We maintain an acreage position of over 40,200 gross (39,700 net) acres in this region, primarily in Calhoun, Clay, and Roane counties. We operate a small field service group in this region utilizing one swab rig, one paraffin truck, one saltwater hauling truck and limited excavating equipment to primarily service our own operated wells and locations. As of September 30, 2019, the Appalachian region has no wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

19

Gulf Coast Region

Our development, exploration, and production activities in the Gulf Coast region are primarily concentrated in southeast Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Wilcox, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to 12,500 feet. We had 263 producing wells (164 net) in the Gulf Coast region as of December 31, 2018, of which 220 wells are operated by us. Average daily production in 2018 was 572 Boe.

At December 31, 2018, we had 925 MBoe of proved reserves in the Gulf Coast region, which represented 7% of our total proved reserves. We maintain an acreage position of over 12,700 gross (5,120 net) acres in this region, primarily in Dimmit and Polk counties. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing: three workover rigs, 17 water transport trucks, two saltwater disposal wells, several trucks, and excavating equipment. Services, including well service support, site preparation and construction for drilling and workover operations, are provided to third-party operators as well as utilized for our own operated wells and locations.    As of September 30, 2019, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

Reserve Information:

Our interests in proved developed and undeveloped oil and gas properties, including the interests held by the Partnerships, have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2018. In matters related to the preparation of our reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of ouryear-end reserves by our independent third-party engineers, Ryder Scott Company, L.P. The members of our district and central groups consist of degreed engineers and geologists with between approximately twenty and thirty-five years of industry experience, and over ten years of experience managing our reserves. Our Engineering Data manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over twenty-five years of experience, holds a Bachelor’s degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist.

All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates:

	Reserve Category
	Proved Developed								Proved Undeveloped								Total
As of December 31,	Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)
2016		3,107		1,265		13,001		6,539		643		159		2,003		1,135		3,750		1,424		15,004		7,674
2017		5,333		1,703		17,143		9,893		505		156		710		779		5,838		1,859		17,853		10,672
2018		6,404		2,707		21,065		12,622		10		12		124		43		6,414		2,719		21,189		12,665

(a) In computing total reserves on a barrels of oil equivalent (Boe) basis, gas is converted to oil based on its relative energy content at the rate of six Mcf of gas to one barrel of oil and NGLs are converted based upon volume; one barrel of natural gas liquids equals one barrel of oil.

At December 31, 2016, we had undeveloped reserves of 1,135 MBoe, attributable to 20 wells that were all put on production in the first quarter of 2017. During 2017, 22 horizontal wells were drilled and completed in West Texas, two in Oklahoma, and one vertical well in the Gulf Coast of Texas. In addition, we had an increase in reserves from overriding royalty interest in nine horizontal wells drilled in Oklahoma by other operators.

At December 31, 2017 our reserve report included 779 MBoe of proved undeveloped reserves attributable to 22 horizontal wells that were all completed in 2018, and therefore, 100% of these reserves were converted to proved developed in the 2018year-end reserves report.

In 2018, the Company completed and put on production nine horizontal wells in West Texas and six horizontal wells in Oklahoma. Proved Developed reserves atyear-end included an additional eightShut-In horizontal wells in West Texas that have been brought on production in February, 2019 and fiveShut-In horizontal wells in Oklahoma brought on production in March, 2019. In addition, at December 31, 2018, our reserve report included 43 MBoe of proved undeveloped reserves attributable to eight horizontal wells drilled in Oklahoma. Three of the eight wells cameon-line in July, 2019 and the remaining five wells were drilled, but due to a pending take-over of Roan Resources by Citizen Energy, are unlikely to be completed until 2020. Additional 2019 activity is discussed in the Recent Activities section below.

We employ technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data, and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

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The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2018, are summarized as follows (in thousands of dollars):

	Proved Developed				Proved Undeveloped				Total
As of December 31,	Future Net Revenue		Present Value 10 Of Future Net Revenue		Future Net Revenue		Present Value 10 Of Future Net Revenue		Future Net Revenue		Present Value 10 Of Future Net Revenue		Present Value 10 Of Future Income Taxes		Standardized Measure of Discounted Cash flow
2016	$	56,467	$	46,827	$	18,114	$	10,403	$	74,581	$	57,230	$	4,993	$	52,237
2017	$	160,737	$	111,614	$	13,564	$	6,100	$	174,301	$	117,714	$	10,800	$	106,914
2018	$	239,337	$	161,376	$	767	$	525	$	240,104	$	161,901	$	23,992	$	137,909

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

“Proved developed” oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. “Proved undeveloped” oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a major expenditure is required before the well is put on production. Our reserves include amounts attributable tonon-controlling interests in the Partnerships. These interests represent less than 3% of our reserves.

In accordance with U.S. generally accepted accounting principles, product prices are determined using the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate. Also in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.

While it may reasonably be anticipated that the prices received for the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.

Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $3.10 per MMBtu in 2018 as compared to $2.98 per MMBtu in 2017 and $2.49 per MMBtu in 2016. Oil prices, based on the NYMEX first of the month average price, were $65.56 per barrel in 2018 as compared to $51.34 per barrel in 2017, and $42.75 per barrel in 2016. Since January 1, 2019, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.

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 flows generated from operations, through our producing oil and gas properties, our field services business, and from sales ofnon-core acreage.

The Company will continue to pursue the acquisition of leasehold acreage and producing properties in areas where we currently operate and believe there is additional exploration and development potential and will attempt to assume the position of operator in all such acquisitions. 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.

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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.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2019, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2019 capital budget is reflective of current 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, divestnon-strategic assets, or enter into strategic joint ventures.

RECENT ACTIVITIES

Since the start of our West Texas horizontal drilling program in 2015 the Company has participated in 67 horizontal wells and invested approximately $103 million dollars. The Company has an acreage position of approximately 12,560 net acres in West Texas with the potential to drill 375 or more new horizontal wells. In Oklahoma, since the start of our SCOOP/STACK horizontal drilling program in 2013, the Company has drilled or committed to drill 41 wells with a total investment of approximately $23.9 million dollars, plus has elected to receive an overriding royalty interest in 60 additional wells drilledto-date. The Company holds approximately 3,460 net acres within the SCOOP/STACK shale plays with the potential for 105 new horizontal wells.

In 2018, the Company participated in a total of 28 gross (6.1 net) horizontal wells with an investment to our share of approximately $41 million. We completed 17 wells in our West Texas horizontal development program and 11 wells in our SCOOP/STACK horizontal development program in Oklahoma. All 28 wells were successful and are producing.

In the fourth quarter of 2018, in our West Texas horizontal drilling program, the Company participated for 49.3% interest in eightone-mile horizontal wells drilled in the Middle Wolfcamp. These wells were brought on production in February, 2019. The total cost of these eight wells and their facilities is approximately $48.3 million with the Company’s share being $23.7 million. Since completion these wells will have produced approximately 670,000 barrels of oil, along with associated gas. PrimeEnergy’s net revenue interest is 36.82%, therefore, our share of the oil recovered in the first eight months of production is approximately 247,000 barrels. We are pleased with the initial performance of these eight wells and expect 100% capital recover in approximately 28 months.

In the second quarter of 2019, in our West Texas horizontal drilling program, we completed three new horizontal wells on our Kashmir Tract: one in the Wolfcamp A, one in the Jo Mill, and one in the Lower Spraberry. These intervals were previously not proven as horizontal target reservoirs for our acreage in Upton County. In the first 120 days of production the three wells have produced 137,800 gross barrels of oil along with associated wellhead gas. PrimeEnergy has 47% to 49% working interest and 39% to 40.7% net revenue interest in the Lower Spraberry and Jo Mill wells, from which 76% of the production has been recoveredto-date. The Company has 5.3% working interest and 3.9% net revenue interest in the Wolfcamp A well. Our share of the gross $26 million cost to drill and complete these three wells is approximately $8.9 million. The three new Kashmir Tract horizontal wells in Upton County have confirmed the economic viability of these three shallow target intervals, not only for the 1,300 acre block in which they were drilled, but also for the 3,260 acre block two miles to the west that we are also developing with Apache. In addition, two offset operators have recently completed wells in the Jo Mill and Lower Spraberry offset our 3,260 acre block, further proving the productive capabilities of these benches.

Apache has indicated that they are planning to drill 16 additional horizontal wells on the Kashmir Tract in early 2020. This 16 well program will not only focus on developing the shallower proven intervals, but also investigate a new reservoir bench, the Middle Spraberry Shale. Therefore, one of the 16 wells to be drilled in early 2020 will be landed in the Middle Spraberry Shale. Following the initial well, there are five additional Middle Spraberry Shale wells that are likely to be drilled on the Kashmir Tract in the near future. The gross cost of the total additional 21 wells would be approximately $185 million, with the Company’s share being approximately $69 million. In the 3,260 Tract, Prime holds leases with interest varying from 14% to 56%. Given the strong initial production performance of our recent shallow horizontals we anticipate an additional 80 wells to be drilled with Apache in the offset 3,260 acre block over the next few years. The gross cost of 80 wells here would be approximately $748 million with the Company’s share being approximately $284 million. The actual number of wells that will be drilled, the cost, and the timing of drilling will vary based upon many factors, including commodity market conditions.

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In the Permian Basin of West Texas the Company maintains an acreage position of approximately 19,900 gross (12,560 net) acres primarily in Reagan, Upton, Martin and Midland counties. We believe this acreage has significant resource potential in approximately 10 reservoir benches, including benches of the Spraberry, Jo Mill, and Wolfcamp formations to support the potential for drilling as many as 375 additional horizontal wells. The Company’s share of the capital investment for a 375 well development program would be approximately $1.5 billion dollars assuming an average cost of $8.5 million per well and an average working interest of 50% in each well.

In Oklahoma, since the start in 2013 of our SCOOP/STACK horizontal drilling program, the Company has drilled or committed to drill 41 wells with a total investment of approximately $23.9 million, plus elected to receive an overriding royalty in 60 additional wells. The Company holds approximately 3,460 net acres within the SCOOP/STACK shale plays with the potential for 105 new horizontal wells.

In Oklahoma, in 2018, the Company participated in 11 wells, with six of these on production byyear-end. Another five of the 11 wells were drilled by Marathon in the “Ruthie 1609” tract in Kingfisher County and were broughton-line in March of 2019. Prime participated with 11.87% interest in these five new wells, investing approximately $4.5 million. This group of wells had strong initial production performance and Encana has increased the level of activity in the area with the drilling of 12 new wells set to be producing in the fourth quarter of 2019. PrimeEnergy has an average of 4.59% working interest in these 12 wells. Drilling and completion costs net to our interest are expected to be $3.8 million.

Also in Oklahoma, the Company participated with Roan Resources, Inc. in the drilling of seven wells in Grady County, Oklahoma. The Company has 10% interest in one of these seven wells and less than one percent interest in the remaining six. The estimated total expenditure net to the Company is approximately $1.3 Million. Three of these seven wells cameon-line July, 2019 and the remaining four were drilled, but due to a pending take-over of Roan Resources by Citizen Energy, are unlikely to be completed until 2020. In addition, there are 15 new wells spud in the first nine months of 2019 from which the Company will receive a minor over-riding royalty interest.

The Company’s horizontal activity in Oklahoma is primarily focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 3,460 net leasehold acres within the SCOOP/STACK shale plays. We believe this acreage has significant additional resource potential that could support the drilling of as many as 105 new horizontal wells based on an estimate of twelve wells per section: six in the Mississippian and six in the Woodford Shale. Should we choose to participate in future development, our share of the capital expenditures would be approximately $80 million at an average 10% ownership level; the Company will otherwise sell its rights for cash, or cash plus a royalty or working interest.

RESULTS OF OPERATIONS

2019 and 2018 Compared

We reported net income of $5.2 million, or $2.61 per share and $2.5 million, or $1.25 per share for the nine and three months ended September 30, 2019, respectively, as compared to net income for the nine and three months ended September 30, 2018 of $7.15 million, or $3.38 per share and $4.4 million, or $2.10 per share, respectively. Current year net income reflects an increase in production combined with commodity price changes over the three and nine months ended September 30, 2019, decrease in gains related to the sale of acreage and changes related to the valuation of derivative instruments. The significant components of income and expense are discussed below.

Oil, gas and NGLs sales decreased $6.9 million, or 25.7% from $27 million for the three months ended September 30, 2018 to $20 million for the three months ended September 30, 2019 and decreased $6.5 million, or 8.8% from $73.8 million for the nine months ended September 30, 2018 to $67.3 million for the nine months ended September 30, 2019.

Our realized prices at the well head decreased an average of $10.72 per barrel, or 17.0% and $8.25 per barrel, or 13.1% on crude oil during the three and nine months ended September 30, 2019, respectively from the same periods in 2018. Our average price for natural gas decreased $1.28 per Mcf, or 53.2% and $0.92 per Mcf, or 39.4% during the three and nine months ended September 30, 2019, respectively from the same periods in 2018. Our average price for NGLs sold decreased an average of $21.4 per barrel, Or 66.6% and $13.19 per barrel, or 45.9% during the three and nine months ended September 30, 2019, respectively from the same periods in 2018. Production increases were negatively impacted by natural gas prices at the Waha hub where Permian Basin production exceeded West Texas takeaway capacity. Gas prices traded at historic lows, and at times were negative, for portions of the second and third quarters of 2019. This gas pricing is expected to improve as Waha prices improve, due to the third-party operated Gulf Coast Express (GCX) pipeline placed in service in late September.

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Our crude oil production decreased by 9,000 barrels or 2.7% from 332,000 barrels for the third quarter 2018 to 323,000 barrels for the third quarter 2019 and increased by 96,000 barrels, or 10.5% from 916,000 barrels for the nine months ended September 30, 2018 to 1,012,000 barrels for the nine months ended September 30, 2019. Our natural gas production increased by 399,632 Mcf, or 44.1% from 906,000 Mcf for the third quarter 2018 to 1,305,632 Mcf for the third quarter 2019 and increased by 772,000 Mcf, or 27.8% from 2,777,000 Mcf for the nine months ended September 30, 2018 to 3,549,000 Mcf for the nine months ended September 30, 2019. Our NGL production increased by 35,983 barrels or 29.7% from 121,000 barrels for the third quarter 2018 to 156,983 barrels for the third quarter 2019 and increased by 111,000 barrels, or 33.2% from 334,000 barrels for the nine months ended September 30, 2018 to 445,000 barrels for the nine months ended September 30, 2019. The net increase in production volumes reflect by production from new wells added in February through July 2019, offset with the natural decline of the previously existing properties.

The following table summarizes the primary components of production volumes and average sales prices realized for the nine months ended September 30, 2019 and 2018 (excluding realized gains and losses from derivatives).

			Nine months ended September 30,
	2019		2018		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Produced		1,012,000		916,000		96,000			10.5	%
Average Price Received	$	54.72	$	62.97	$	(8.25	)		(13.1	)%
Oil Revenue (In 000’s)	$	55,370	$	57,683	$	(2,313	)		(4.0	)%
Mcf of Gas Sold		3,549,000		2,777,000		772,000			27.8	%
Average Price Received	$	1.43	$	2.35	$	(0.92	)		(39.4	)%
Gas Revenue (In 000’s)	$	5,057	$	6,526	$	(1,469	)		(22.5	)%
Barrels of Natural Gas Liquids Sold		445,000		334,000		111,000			33.2	%
Average Price Received	$	15.52	$	28.71	$	(13.19	)		(45.9	)%
Natural Gas Liquids Revenue (In 000’s)	$	6,906	$	9,588	$	(2,682	)		(28.0	)%
Total Oil & Gas Revenue (In 000’s)	$	67,333	$	73,797	$	(6,464	)		(8.8	)%

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			Three months ended September 30,
	2019		2018		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Produced		323,000		332,000		(9,000	)		(2.7	)%
Average Price Received	$	52.41	$	63.13	$	(10.72	)		(17.0	)%
Oil Revenue (In 000’s)	$	16,928	$	20,960	$	(4,032	)		(19.2	)%
Mcf of Gas Sold		1,305,632		906,000		399,632			44.1	%
Average Price Received	$	1.12	$	2.40	$	(1.28	)		(53.2	)%
Gas Revenue (In 000’s)	$	1,467	$	2,174	$	(707	)		(32.5	)%
Barrels of Natural Gas Liquids Sold		156,983		121,000		35,893			29.7	%
Average Price Received	$	10.75	$	32.15	$	(21.40	)		(66.6	)%
Natural Gas Liquids Revenue (In 000’s)	$	1,687	$	3,890	$	(2,203	)		(56.6	)%
Total Oil & Gas Revenue (In 000’s)	$	20,082	$	27,024	$	(6,942	)		(25.7	)%

Oil, Natural Gas and NGL DerivativesWe 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 asmark-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. The following table summarizes the results of our derivative instruments for the three and nine months ended September 2019 and 2018:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
				($ in thousand)
Oil derivatives – realized losses	$	(426	)	$	(1,261	)	$	(1,302	)	$	(2,895	)
Oil derivatives – unrealized gains (losses)		2,202			(1,716	)		(900	)		(7,148	)
Total gains (losses) on oil derivatives	$	1,776		$	(2,977	)	$	(2,202	)	$	(10,043	)
Natural gas derivatives – realized gains	$	98		$	39		$	90		$	124
Natural gas derivatives – unrealized gains (losses)		(69	)		(31	)		82			(359	)
Total gains (losses) on natural gas derivatives	$	29		$	8		$	172		$	(235	)
NGL derivatives – realized gain (losses)	$	134		$	(127	)	$	244		$	(154	)
NGL derivatives – unrealized gains (losses)		(62	)		(448	)		(1	)		(645	)
Total gains (losses) on NGL derivatives		72			(575	)		243			(799	)
Total gains (losses) on oil, natural gas and NGL derivatives	$	1,876		$	(3,544	)	$	(1,787	)	$	(11,077	)

Prices received for the nine months ended September 30, 2019 and 2018, respectively, including the impact of derivatives were:

	2019		2018
Oil Price	$	53.43	$	59.81
Gas Price	$	1.45	$	2.39
NGLS Price	$	16.08	$	28.24

Field service income increased $0.4 million or 8.9% from $4.5 million for the third quarter 2018 to $4.9 million for the third quarter 2019 and $1.2 million, or 9.3% from $13.1 million for the nine months ended September 30, 2018 to $14.3 million for the nine months ended September 30, 2019. This increase is a combined result of increased utilization and rates charged to customers during the 2019 period. Workover rig services, hot oil treatments, salt water hauling and disposal represent the bulk of our field service operations.

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Lease operating expense decreased $1.3 million or 13.9% from $9.5 million for the third quarter 2018 to $8.2 million for the third quarter 2019, and decreased $2.4 million or 9.1% from $26.8 million for the nine months ended September 30, 2018 to $24.4 million for the nine months ended September 30, 2019. This decrease is primarily due to the sales of high lifting cost properties during 2019 combined with lower production taxes related to lower commodity prices, offset by costs related to new wells broughton-line and general rate increases on vendor services during the first nine months of 2019 as compared to the same period of 2018.

Field service expense increased $0.2 million or 6.5% from $3.7 million for the third quarter 2018 to $3.9 million for the third quarter 2019 and increased $1.4 million, or 14.4% from $10.2 million for the nine months ended September 30, 2018 to $11.6 million for the nine months ended September 30, 2019. Field service expenses primarily consist of salaries and vehicle operating expenses which have increased during the nine months ended September 30, 2019 over the same period of 2018 as a direct result of increased services and utilization of the equipment.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $1.4 million, or 17.4% from $7.9 million for the third quarter 2018 to $9.3 million for the third quarter 2019 and $4.1 million, or 17.2% from $23.7 million for the nine months ended September 30, 2018 to $27.8 million for the nine months ended September 30, 2019, reflecting the increased production related to new wells placed on production late in 2018 and the first three quarters of 2019.

General and administrative expense increased $0.6 million, or 26.8% from $2.2 million for the three months ended September 30, 2018 to $2.8 million for the three months ended September 30, 2019, and increased $1.9 million, or 17.3% from $10.7 million for the nine months ended September 30, 2018 to $12.6 million for the nine months ended September 30, 2019. This increase in 2019 reflects the combination of a reduction in G&A reimbursements related to the sale of property and increases in personnel costs.

Gain on sale and exchange of assets of $3.2 million and $1.8 million for the nine months ended September 30, 2018 and September 30, 2019, respectively consists of sales ofnon-essential oil and gas interests and field service equipment.

Interest expense increased from $0.8 million for the third quarter 2018 to $0.9 million for the third quarter 2019 and from $2.6 million for the nine months ended September 30, 2018 to $2.9 million for the nine months ended September 30, 2019. This increase reflects the increase in current borrowings under our revolving credit agreement.

Income tax expense for the September 30, 2018 and 2019 periods varied due to the change in net income for those periods.

LIQUIDITY AND CAPITAL RESOURCES

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

Net cash provided by our operating activities for the nine months ended September 30, 2019 was $21.5 million compared to $25.5 million for the nine months ended September 30, 2018. 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 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, we will be able to access sufficient additional capital through bank financing.

We currently maintain a credit facility totaling $300 million, with a borrowing base of $90 million. As of November 1, 2019 the Company has $59 million in outstanding borrowings and $31 million in availability under this facility. 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. The next borrowing base review is scheduled for December 2019. 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.

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Our credit agreement required us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. Accordingly the Company has in place the following swap and put agreements for oil and natural gas.

	2019		2020		2019		2020
Swap Agreements
Natural Gas (MMBTU)		—		180,000	$	—	$	2.95
Natural Gas Liquids (barrels)		15,000		—	$	21.66		—
Oil (barrels)		134,600		225,500	$	53.05	$	58.43
	2019		2020		2019		2020
Put Agreements
Natural Gas (MMBTU)		—		1,849,000	$	—	$	2.25
Oil (barrels)		—		65,000	$	—	$	49.00

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2019, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2019 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, divestnon-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.

We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2019. As of November 1, 2019, we have spent $4.846 million under these programs during 2019.

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 Rules13a-15 and15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company’s internal control over financial reporting that occurred during the first nine months of 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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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, 2019, the Company purchased the following shares of common stock as treasury shares.

2019 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		1,386	$	80.50		192,077
February		2,716	$	122.36		189,361
March		1,861	$	156.23		187,500
April		2,601	$	142.71		184,899
May		10,637	$	138.44		174,262
June		3,210	$	135.04		171,052
July		6,253	$	127.74		164,799
August		1,155	$	118.73		163,644
September		1,407	$	114.11		162,237
Total/Average		31,226	$	131.57

(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 fromtime-to-time, in open market transactions or negotiated sales. On October 31, 2012 and June 13, 2018, the Board of Directors of the Company approved an additional 500,000 and 200,000 respectively, shares of the Company’s stock to be included in the stock repurchase program. A total of 3,700,000 shares have been authorized, to date, under this program. Through September 30, 2019, a total of 3,537,763 shares have been repurchased under this program for $72,844,792 at an average price of $20.59 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

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Item 6. EXHIBITS

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

Exhibit No.
3.1	Certificate of Incorporation of PrimeEnergy Resources Corporation, as amended and restated of December  21, 2018, (filed as Exhibit 3.1 of PrimeEnergy Resources Corporation Form8-K on December 27, 2018, and incorporated herein by reference).
3.2	Bylaws of PrimeEnergy Resources Corporation as amended and restated as of May  20, 2015 (filed as Exhibit 3.2 of PrimeEnergy Resources Corporation Form8-K on May 21, 2015 and incorporated herein by reference).
10.18	Composite copy ofNon-Statutory Option Agreements (Incorporated by reference to Exhibit  10.18 of PrimeEnergy Resources Corporation Form10-K for the year ended December 31, 2004).
10.22.5.10	Third Amended and Restated Credit Agreement dated as of February  15, 2017 among PrimeEnergy Resources Corporation, as Borrower, Compass Bank, as Administrative Agent and Lender, Wells Fargo, National Association, as Document Agent, the Lenders Party Hereto (Compass Bank, Wells Fargo, National Association, Citibank, N.A.) and BBVA Compass Bank, as Letter of Credit Issuer and Sole Lead Arranger and Sole Bookrunner (Incorporated by reference to Exhibit 10.22.5.10 to PrimeEnergy Resources Corporation Form10-K for the year ended December 31, 2016).
10.22.5.10.1	FIRST AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of December  22, 2017 among PRIMEENERGY RESOURCES CORPORATION, as Borrower, THE LENDERS PARTY HERETO, COMPASS BANK, as Administrative Agent, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Documentation Agent, and BBVA COMPASS, as Sole Lead Arranger and Sole Book Runner, (Incorporated by reference to Exhibit 10.22.5.10.1 to PrimeEnergy Resources Corporation Form10-K for the year ended December 31, 2017).
10.22.5.10.2	SECOND AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of July  17, 2018 among PRIMEENERGY CORPORATION, as Borrower, THE LENDERS PARTY HERETO, COMPASS BANK, as Administrative Agent, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Documentation Agent, and BBVA COMPASS, as Sole Lead Arranger and Sole Book Runner, (Incorporated by reference to Exhibit 10.22.5.10.2 to PrimeEnergy Corporation Form10-Q for the quarter ended June 30, 2018).
10.22.5.10.3	THIRD AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of January  8, 2019, among PRIMEENERGY RESOURCES CORPORATION, as Borrower, THE LENDERS PARTY HERETO, COMPASS BANK, as Administrative Agent, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Documentation Agent, and BBVA COMPASS, as Sole Lead Arranger and Sole Book Runner (Incorporated by reference to Exhibit 10.22.5.10.3 to PrimeEnergy Resources Corporation Form10-K for the year ended December 31, 2018).
10.22.5.11	Amended, Restated and Consolidated Guaranty dated as of February  15, 2017, among PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, EOWS Midland Company and Prime Offshore L.L.C. in favor of Compass Bank, as Administrative Agent for the Lenders (Incorporated by reference to Exhibit 10.22.5.11 to PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2016).
10.22.5.12	Amended, Restated and Consolidated Pledge and Security Agreement dated as of February  15, 2017, among PrimeEnergy Resources Corporation, PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, EOWS Midland Company and Prime Offshore L.L.C. and Compass Bank, as Administrative Agent for the Secured Parties (Incorporated by reference to Exhibit 10.22.5.12 to PrimeEnergy Resources Corporation Form10-K for the year ended December 31, 2016).
10.22.5.13	Amended, Restated and Consolidated Deed of Trust, Mortgage, Security Agreement, Assignment of Production and Financing Statement Dated as of May 5, 2017 (Incorporated by reference to Exhibit 10.22.5.13 to PrimeEnergy Resources Corporation Form10-Q for the quarter ended March 31, 2017).
10.22.5.14	Deed of Trust, Mortgage, Security Agreement, Assignment of Production and Financing Statement Dated as of May  5, 2017 (Incorporated by reference to Exhibit 10.22.5.14 to PrimeEnergy Resources Corporation Form10-Q for the quarter ended March 31, 2017).

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Exhibit No.
10.22.5.15	Amended, Restated and Consolidated Mortgage of Oil and Gas Property, Security Agreement, Assignment of Production and Financing Statement Dated as of May 5, 2017 (Incorporated by reference to Exhibit 10.22.5.15 to PrimeEnergy Resources Corporation Form10-Q for the quarter ended March 31, 2017).
31.1	Certification of Chief Executive Officer pursuant to Rule13(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 Rule13(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 Resources Corporation
	(Registrant)
November 7, 2019	/s/ Charles E. Drimal, Jr.
(Date)	Charles E. Drimal, Jr.
	President
	Principal Executive Officer
November 7, 2019	/s/ Beverly A. Cummings
(Date)	Beverly A. Cummings
	Executive Vice President
	Principal Financial Officer

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