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~~June 30, ~~2018~~2019

☐	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 and posted 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 and post 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.

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 ~~November 13, 2018~~August 9, 2019 was: Common Stock, $0.10 par value ~~2,049,478~~2,010,613 shares.

PrimeEnergy Resources Corporation

Index to Form10-Q

~~September~~June 30, ~~2018~~2019


	Page
Part I—Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets – ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017~~2018		3
Condensed Consolidated Statements of Operations – For the ~~nine~~six and three months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018		4
Condensed Consolidated Statement of Equity – For the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018		5
Condensed Consolidated Statements of Cash Flows – For the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018		6
Notes to Condensed Consolidated Financial Statements – ~~September~~June 30, ~~2018~~2019		~~7-15~~7-14
Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation		~~15-21~~14-24
Item 3. Quantitative and Qualitative Disclosures About Market Risk		2124
Item 4. Controls and Procedures		2124
Part II - Other Information
Item 1. Legal Proceedings		2124
Item 1A. Risk Factors		2124
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		2225
Item 3. Defaults Upon Senior Securities		2226
Item 4. Reserved		2226
Item 5. Other Information		2226
Item 6. Exhibits		~~23-24~~27
Signatures		2529

PART I—FINANCIAL INFORMATION

Item 1.

FINANCIAL STATEMENTS

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS –Unaudited

(Thousands of dollars)


	September 30, 2018			December 31, 2017			June 30, 2019			December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents	$	7,669		$	8,438		$	2,821		$	6,315
Accounts receivable, net		14,799			16,961			16,848			14,961
Prepaid obligations								485			640
Derivative asset short-term								1,081			1,674
Other current assets		856			1,232			139			144

Total Current Assets		23,324			26,631			21,374			23,734
Property and Equipment, at cost
Oil and gas properties (successful efforts method), net		218,134			213,001			216,123			223,669
Field and office equipment, net		6,596			6,974			6,905			6,756

Total Property and Equipment, Net		224,730			219,975			223,028			230,425

Other Assets		149			159
Derivative asset long-term and other assets.								623			893

Total Assets	$	248,203		$	246,765		$	245,025		$	255,052

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	10,615		$	24,615		$	13,440		$	9,553
Accrued liabilities		15,264			16,294			6,767			18,431
Current portion of long-term debt		948			2,378			—			698
Current portion of asset retirement		2,665			2,309
Current portion of asset retirement and other obligations								2,098			1,687
Derivative liability short-term		8,028			1,509			1,675			88
Due to Related Parties		30			65			—			5

Total Current Liabilities		37,550			47,170			23,980			30,462
Long-Term Bank Debt		56,577			48,459			62,000			65,547
Asset Retirement Obligations		19,828			21,269			19,377			19,647
Derivative Liability Long-Term		3,226			1,913			—			10
Deferred Income Taxes		27,325			24,962			33,534			32,828
Other Long-Term Obligations		555			553			608			555

Total Liabilities		145,061			144,326			139,499			149,049
Commitments and Contingencies
Equity
Common stock, $.10 par value; 2018 and 2017: Authorized: 4,000,000 shares, issued: 3,836,397 shares; outstanding 2018: 2,061,805 shares; 2017: 2,169,370 shares		383			383
Common stock, $.10 par value; 2019 and 2018: Authorized and Issued: 2,810,000 shares; outstanding 2019: 2,017,508 shares; 2018: 2,039,919 shares								281			281
Paid-in capital		8,772			8,729			7,612			7,388
Retained earnings		145,435			138,320			128,381			125,644
Treasury stock, at cost; 2018: 1,774,592 shares; 2017: 1,667,027 shares		(58,423	)		(52,123	)
Treasury stock, at cost; 2019: 792,492 shares; 2018: 770,081 shares								(34,316	)		(31,304	)

Total Stockholders’ Equity – PrimeEnergy		96,167			95,309			101,958			102,009
Non-controlling interest		6,975			7,130			3,568			3,994

Total Equity		103,142			102,439			105,526			106,003

Total Liabilities and Equity	$	248,203		$	246,765		$	245,025		$	255,052

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTSOF OPERATIONS– Unaudited

Three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018

(Thousands of dollars, except per share amounts)


	Three Months Ended September 30,						Nine months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017			2019			2018			2019			2018
Revenues
Oil sales	$	20,960		$	8,568		$	57,683		$	27,479		$	19,644		$	16,622		$	38,442		$	36,723
Natural gas sales		2,174			2,502			6,526			7,665			1,355			1,989			3,590			4,352
Natural gas liquids sales		3,890			1,534			9,588			3,901			2,375			3,098			5,219			5,698
Realized (loss) gain on derivative instruments, net		(1,349	)		156			(2,925	)		(49	)
Realized loss on derivative instruments, net														(851	)		(1,081	)		(773	)		(1,576	)
Field service income		4,470			4,109			13,132			12,176			4,757			4,447			9,490			8,662
Administrative overhead fees		1,414			1,530			4,344			4,758			1,388			1,426			2,812			2,930
Unrealized (loss) gain on derivative instruments, net		(2,194	)		(1,262	)		(8,151	)		3,092
Unrealized gain (loss) on derivative instruments, net														2,862			(4,136	)		(2,890	)		(5,957	)
Other income		37			47			59			169			4			22			63			22

Total Revenues		29,402			17,184			80,256			59,191			31,534			22,387			55,953			50,854
Costs and Expenses
Lease operating expense		9,533			6,762			26,867			21,058			8,149			8,757			16,225			17,336
Field service expense		3,728			3,126			10,157			9,152			3,979			3,219			7,644			6,429
Depreciation, depletion, amortization and accretion on discounted liabilities		7,883			7,812			23,715			23,821			9,292			7,909			18,550			15,832
General and administrative expense		2,250			2,523			10,761			6,878			2,895			2,571			9,771			8,547

Total Costs and Expenses		23,394			20,223			71,500			60,909			24,315			22,456			52,190			48,144
Gain on Sale and Exchange of Assets		511			359			3,168			42,078			1,023			185			1,689			2,657

Income (Loss) from Operations		6,519			(2,680	)		11,924			40,360
Income from Operations														8,242			116			5,452			5,367
Other Income (Expense)
Interest Income		12			—			34			—			3			12			10			23
Interest (Expense)		(834	)		(594	)		(2,613	)		(1,659	)		(1,013	)		(917	)		(1,988	)		(1,779	)

Income (Loss) Before Income Taxes		5,697			(3,274	)		9,345			3,870			7,232			(789	)		3,474			3,611
Income Taxes (Benefit) Expense		1,424			(1,384	)		2,332			12,407
Income Taxes Expense (Benefit)														1,410			(192	)		683			907

Net (Loss) Income		4,273			(1,890	)		7,013			26,294
Net Income (Loss)														5,822			(597	)		2,791			2,704
Less: Net Income (Loss) Attributable toNon-Controlling Interests		(80	)		122			(102	)		5,646			47			(37	)		54			(22	)

Net (Loss) Income Attributable to PrimeEnergy	$	4,353		$	(2,012)		$	7,115		$	20,648
Net Income (Loss) Attributable to PrimeEnergy													$	5,775		$	(560	)		2,737			2,726

Basic (Loss) Income Per Common Share	$	2.10		$	(0.92)		$	3.38		$	9.29
Basic Income (Loss) Per Common Share													$	2.85		$	(0.27	)	$	1.35		$	1.29

Diluted (Loss) Income Per Common Share	$	1.54		$	(0.92)		$	2.49		$	6.94
Diluted Income (Loss) Per Common Share													$	2.07		$	(0.27	)	$	0.98		$	0.95

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTOF EQUITY –Unaudited

~~Nine~~Six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~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, 2016
3,836,397 $ 383 $ 8,313 $ 96,322 $ (46,473) $ 58,545 $ 7,335 $ 65,880
Repurchase 101,207 shares of common stock
—   —   —   —   (5,000) (5,000 ) —   (5,000 )
Net income
—   —   —   20,648 —   20,648 5,646 26,294
Repurchase ofNon-controlling interests
—   —   127 —   —   127 (187 ) (60 )
Distribution of Non-controlling interests
—   —   —   —   —   —   (4,410 ) (4,410 )

Balance at September 30, 2017
3,836,397 $ 383 $ 8,840 $ 116,970 $ (51,473) $ 74,320 $ 8,344 $ 82,704

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


	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 72,839 shares of common stock		—		—		—		—		(3,696	)		(3,696	)		—			(3,696	)
Net income (loss)		—		—		—		2,726		—			2,726			(22	)		2,704
Purchase ofNon- controlling Interest		—		—		43		—		—			43			(53	)		(10	)

Balance at June 30, 2018		3,836,397	$	383	$	8,772	$	141,046	$	(55,819	)	$	94,382		$	7,055		$	101,437

Balance at December 31, 2018		2,810,000	$	281	$	7,388	$	125,644	$	(31,304	)	$	102,009		$	3,994		$	106,003
Repurchase 22,411 shares of common stock		—		—		—		—		(3,012	)		(3,012	)		—			(3,012	)
Net income		—		—		—		2,737		—			2,737			54			2,791
Purchase ofNon- controlling Interest		—		—		224		—		—			224			(480	)		(256	)

Balance at June 30, 2019		2,810,000	$	281	$	7,612	$	128,381	$	(34,316	)	$	101,958		$	3,568		$	105,526

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OOFF CASH FLOWS –Unaudited

~~Nine~~Six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018

(Thousands of dollars)


	2018			2017			2019			2018
Cash Flows from Operating Activities:
Net Income includingnon-controlling interest	$	7,013		$	26,294		$	2,791		$	2,704
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities		23,715			23,821			18,550			15,832
Gain on sale of properties		(3,168	)		(42,078	)		(1,689	)		(2,657	)
Unrealized loss (gain) on derivative instruments, net		8,151			(3,092	)
Unrealized loss on derivative instruments, net								2,890			5,957
Provision for deferred income taxes		2.363			10,425			706			961
Changes in operating assets and liabilities:
Accounts receivable		2,162			(2,922	)		(1,887	)		3,174
Due to related parties		(35	)		31			(5	)		6
Other assets		376			(1,164	)		160			620
Accounts payable		(14,000	)		1,337			3,887			(12,042	)
Accrued liabilities		(1,030	)		8,771			(11,664	)		(7,121	)

Net Cash Provided by Operating Activities		25,547			21,423			13,739			7,434

Cash Flows from Investing Activities:
Capital expenditures		(29,317	)		(40,057	)		(11,412	)		(18,709	)
Proceeds from sale of properties and equipment		2,623			46,977			1,693			2,112

Net Cash (Used in) Provided by Investing Activities		(26,694	)		6,920
Net Cash Used in Investing Activities								(9,719	)		(16,597	)

Cash Flows from Financing Activities:
Purchase of stock for treasury		(6,300	)		(5,000	)		(3,012	)		(3,696	)
Purchase ofnon-controlling interests		(10	)		(60	)		(256	)		(10	)
Proceeds from long-term bank debt and other long-term obligations		42,800			52,000			13,000			35,300
Repayment of long-term bank debt and other long-term obligations		(36,112	)		(67,521	)		(17,246	)		(25,428	)
Distributions tonon-controlling interests		—			(4,410	)

Net Cash Provided by (Used in) Financing Activities		378			(24,991	)
Net Cash (Used in) Provided by Financing Activities								(7,514	)		6,166

Net (Decrease) Increase in Cash and Cash Equivalents		(769	)		3,352			(3,494	)		(2,997	)
Cash and Cash Equivalents at the Beginning of the Period		8,438			6,568			6,315			8,438

Cash and Cash Equivalents at the End of the Period	$	7,669		$	9,920		$	2,821		$	5,441

Supplemental Disclosures:
Income taxes paid	$	4,340		$	2,588		$	130		$	4,341
Interest paid	$	2,761		$	1,762		$	2,015		$	1,950

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

PRIMEENERGY RESOURCES CORPORATION

NOTESTO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~September~~June 30, ~~2018~~2019

(Unaudited)

(1) Basis of Presentation:

The accompanying condensed consolidated financial statements of PrimeEnergy Resources Corporation (“PrimeEnergy” or the ~~��Company”~~“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, ~~2017.~~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~~June 30, ~~2018~~2019 and December 31, ~~2017,~~2018, the condensed consolidated results of operations, cash flows and equity for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017.~~2018.

As of ~~September~~June 30, ~~2018,~~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, ~~2017,~~2018, with the exception of Accounting Standards Update (ASU)~~2014-09,~~2016-02, ~~“Revenue from Contracts with Customers~~“Leases (Topic ~~606)~~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

~~On January 1, 2018, PrimeEnergy adopted ASU2014-09,~~ “Revenue from Contracts with Customers (ASC 606),” using the modified retrospective method. The Company elected to evaluate all contracts at the date of initial application. While there was no impact to the opening balance of retained earnings as a result of the adoption, certain items previously netted in revenue are now recognized as lease operating expense in the Company’s statement of consolidated operations. The amounts are immaterial to the financial statements, and prior comparative periods have not been restated and continue to be reported under the accounting standards in effect for those periods. Adoption of the new standard is not anticipated to have a material impact on the Company’s net earnings on an ongoing basis.

The Company applies the provisions of ASC 606 for revenue recognition to contracts with customers. Sales of crude oil, natural gas, and natural gas liquids (NGLs) are included in revenue when production is sold to a customer in fulfillment of performance obligations under the terms of agreed contracts. Performance obligations primarily comprise delivery of oil, gas, or NGLs at a delivery point, as negotiated within each contract. Each barrel of oil, million Btu (MMBtu) of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, the Company’s right to payment, and transfer of legal title. In each case, the term between delivery and when payments are due is not significant.

PrimeEnergy records trade accounts receivable for its unconditional rights to consideration arising under sales contracts with customers. The carrying value of such receivables, net of the allowance for doubtful accounts, represents estimated net realizable value. The Company routinely assesses the collectability of all material trade and other receivables. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. PrimeEnergy has concluded that the disaggregation of revenue by product appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors.

~~Practical Expedients and Exemptions~~

PrimeEnergy does not disclose the value of unsatisfied performance obligations for contracts with an original expected length of one year or less or contracts for which variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

PrimeEnergy will utilize the practical expedient to expense incremental costs of obtaining a contract if the expected amortization period is one year or less. Costs to obtain a contract with expected amortization periods of greater than one year will be recorded as an asset and will be recognized in accordance with ASC 340, “Other Assets and Deferred Costs.” Currently, the Company does not have contract assets related to incremental costs to obtain a contract.

~~New Pronouncements Issued But Not Yet Adopted~~

Leases.In February 2016, the Financial Accounting Standards Board ~~(FASB)~~(“FASB”) issued ~~ASU~~Accounting Standards Update (“ASU”)2016-02, “Leases (Topic 842),” ~~requiring~~(“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 ~~most~~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 ~~under previous GAAP. The guidance is effective~~to explore for ~~fiscal years beginning after December 15, 2018. Early~~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 ~~is permitted; however,~~to ease the burden of implementation. At implementation, the Company ~~does not intend~~elected to ~~early adopt. In~~(i) maintain the historical lease classification for leases prior to January ~~2018,~~1, 2019, (ii) maintain the ~~FASB issued ASU2018-01,~~ ~~which permits an entity an optional election to not evaluate under ASU2016-02~~ ~~those existing or expired~~historical accounting treatment for land easements that ~~were~~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 ~~previously accounted for as~~record short-term leases ~~prior to~~on the consolidated balance sheet, all in accordance with ASC 842.

The adoption of ~~ASU2016-02.~~ ~~In July 2018, the FASB issued ASU2018-11,~~ which adds a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting wouldASC 842 did not ~~be required, and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. The Company intends to elect both transitional practical expedients.~~

In the normal course of business, the Company enters into various lease agreements for office space and equipment related to its exploration and development activities that are currently accounted for as operating leases. At this time, the Company cannot reasonably estimate the financial impact this will have on its consolidated financial statements; however, the Company believes adoption and implementation of this ASU will not significantly impact its balance sheet.

~~In June 2018, the FASB issued ASU2018-07,~~ “Improvements to Nonemployee Share-Based Payment Accounting,” to simplify the accounting for share-based transactions by expanding the scope of Topic 718 from only being applicable to share-based payments to employees to also include share-based payment transactions for acquiring goods and services from nonemployees. As a result, the same guidance that provides for employee share-based payments, including most of the requirements related to classification and measurement, applies to nonemployee share-based payment arrangements. ASU~~2018-07~~ is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted. The Company anticipates adopting this guidance for the first quarter of 2019 and does not expect it to 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 ~~consolidated financial statements.~~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 June 30, 2019, the Company has operating lease assets and liabilities of $452 thousand and a financing lease included in property and equipment and lease liabilities for $13 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.

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)~~(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 ~~$10,000~~$256,000 and ~~$60,000~~$10,000 for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017,~~2018, respectively.

During the ~~nine~~first six months ~~ended September 30,~~of 2019 and 2018, ~~The~~the Company sold or farmed out interests in certainnon-core ~~undeveloped and developed~~ 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, ~~Kansas,~~ Colorado ~~Texas~~ and ~~Wyoming.~~West Virginia. Proceeds under these agreements were ~~$3.0 million.~~ $1.6 million and $2.8 million, respectively.

During ~~this same time period~~the first six months of 2018, the Company acquired approximately 464 net mineral acres and working interest in 53 oil and gas wells ~~ranging from 16.6% to 33.4%, plus one commercial salt water disposal well,~~ for ~~a total of $6,080,000. This acreage~~$6.08 million and ~~group of wells are all operated by the Company~~sold or farmed out interests in certainnon-core undeveloped oil and natural gas properties located in ~~Reagan County,~~Oklahoma, Kansas, Colorado and Texas, ~~where future horizontal drilling will likely occur.~~

in exchange for cash and a royalty or working interest, with proceeds of $2.19 million.
3)(3) Additional Balance Sheet Information:
Certain balance sheet amounts are comprised of the following:

(Thousands of dollars)    September 30,
2018    December 31,
2017    June 30,
2019    December 31,
2018
Accounts Receivable:

Joint interest billing
   $ 1,873    $ 3,173    $ 2,303    $ 1,976
Trade receivables
   2,207    941    2,725    1,979
Oil and gas sales
   10,456    12,941    11,131    6,112
Tax refund receivable
   —      4,760
Other
   361    4    913    358








   14,897    17,059    17,072    15,185
Less: Allowance for doubtful accounts
   (98 )    (98 )    (224 )    (224 )








Total
   $ 14,799    $ 16,961    $ 16,848    $ 14,961








Accounts Payable:

Accounts Payable:

Trade
   $ 1,153    $ 14,317    $ 5,399    $ 1,174
Royalty and other owners
   7,944    8,341    5,742    6,197
Prepaid drilling deposits
   114    67
Partner advances
   1,335    1,357
Other
   1,404    1,890    964    825








Total
   $ 10,615    $ 24,615    $ 13,440    $ 9,553








Accrued Liabilities:

Accrued Liabilities:

Compensation and related expenses
   $ 2,387    $ 2,449    $ 3,161    $ 2,907
Property costs
   12,092    9,141    3,606    14,993
Income Tax
   —      4,180
Other
   785    524    —      531








Total
   $ 15,264    $ 16,294    $ 6,767    $ 18,431








(4) Property and Equipment:
Property and equipment at ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017~~2018 consisted of the following:

(Thousands of dollars)    September 30,
2018    December 31,
2017    June 30,
2019    December 31,
2018
Proved oil and gas properties, at cost
   $ 499,958    $ 476,570    $ 522,239    $ 514,821
Less: Accumulated depletion and depreciation
   (281,824 )    (263,569 )    (306,116 )    (291,152 )








Oil and Gas Properties, Net
   $ 218,134    $ 213,001    $ 216,123    $ 223,669








Field and office equipment
   $ 26,788    $ 26,241    $ 28,188    $ 27,252
Less: Accumulated depreciation
   (20,192 )    (19,267 )    (21,283 )    (20,496 )








Field and Office Equipment, Net
   $ 6,596    $ 6,974    $ 6,905    $ 6,756








Total Property and Equipment, Net
   $ 224,730    $ 219,975    $ 223,028    $ 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~~June 30 ~~2018,~~2019, the Company had a total of ~~$56.5~~$62 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of ~~5.22%~~5.52% and ~~$33.5~~$28 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was ~~5.30%~~5.53% for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 as compared to ~~4.98%~~5.38% for ~~nine~~six months ended ~~September~~June 30, ~~2017.~~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. ~~As of September 30, 2018, the Company had a total of $1.025 million outstanding on the Additional Equipment Loans.~~
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.
~~The~~On May 23, 2019, the Company ~~determined~~made its final payment towards both the second and third loans. At this time all equipment loans have been paid in full and the field service equipment liens secured by these loans ~~are Level 3 liabilities in~~have been cancelled and all titles returned to the ~~fair-value hierarchy and estimated their fair value as $922 thousand and $3.941 million at September 30, 2018 and 2017, respectively, using a discounted cash flow model.~~Company.
(6) Other Long-Term Obligations and Commitments:
Operating Leases:
The Company ~~has severalnon-cancelable~~leases office facilities under operating leases ~~primarily~~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 ~~rental~~office equipment is included in property and equipment, other current liabilities and other long-term liabilities this quarter. As most of ~~office space,~~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 ~~have a~~can extend or shorten the term of ~~more than one year.~~the lease. The ~~future minimum~~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 ~~payments~~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 ~~rest of fiscal 2018 and thereafter~~six months ended June 30, 2019 were $293 thousand. Cash payments included in the operating lease cost for the six months ended June 30, 2019 were $284 thousand. The weighted-average remaining operating ~~leases are~~lease terms is 12 months. The amortization and interest expense for financing lease amounted to $1,275 and the cash payment for the lease was $1,200 and the lease term remaining was for 22 months.
The payment schedule for the Company’s operating and financing lease obligations as of June 30, 2019 is as follows:

(Thousands of dollars)    Operating
Leases
2018
   $ 133
2019
   222
2020
   69
2021
   17


Total minimum payments
   $ 441


~~Rent expense for office space for the nine months ended September 30, 2018 and 2017 was $396,000 and $509,000, respectively.~~
(Thousands of dollars)
   Operating
Leases    Financing
Leases
2019
   $ 299    $ 5
2020
   155    7
2021
   17    2




Total undiscounted lease payments
   $ 471    $ 14
Less: Amount associated with discounting
   (19 )    (1 )




Net operating lease liabilities
   $ 452    $ 13




Asset Retirement Obligation:
A reconciliation of the liability for plugging and abandonment costs for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 is as follows:

(Thousands of dollars)       June 30,
2019
Asset retirement obligation – December 31, 2017
   $ 23,578
Asset retirement obligation at December 31, 2018
   $ 21,334
Liabilities incurred
   42    —
Liabilities settled
   (1,967 )    (829 )
Accretion expense
   840    560
Revisions in estimated liabilities
   —




Asset retirement obligation – September 30, 2018
   $ 22,493
Asset retirement obligation at June 30, 2019
   $ 21,065




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~~June 30, ~~2018~~2019 and ~~2017,~~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 ~~and~~or Trusts. The Company purchased interests totaling ~~$10,000~~$256,000 and ~~$60,000~~$10,000 for the ~~nine~~six months ended ~~September~~June 30, 2019 and 2018, ~~and 2017,~~ respectively.
Payables owed to related parties primarily represent receipts collected by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors, for oil and gas sales net of expenses.
(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~~June 30, ~~2018~~2019 and December 31, ~~2017:~~2018:

September 30, 2018
   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,
2018
June 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
June 30,
2019
(Thousands of dollars)
Assets

Commodity derivative contracts
   $ —      $ —      $ 68    $ 68    $ —      $ —      $ 1,081 $ 1,081














Total assets
   —      $ —      $ 68    $ 68    —      $ —      $ 1,081 $ 1,081














Liabilities

Commodity derivative contracts
   $ —      $ —      $ (11,254 )    $ (11,254 )    $ —      $ —      $ (1,675 ) $ (1,675 )














Total liabilities
   $ —      $ —      $ (11,254 )    $ (11.254 )    $ —      $ —      $ (1,675 ) $ (1,675 )














December 31, 2017
   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,
2017
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
   $ —      $ —      $ 388    $ 388    $ —      $ —      $ 2,394 $ 2,394














Total assets
   $ —      $ —      $ 388    $ 388    $ —      $ —      $ 2,394 $ 2,394














Liabilities

Commodity derivative contract
   $ —
$
—

   $ (3,422 )    $ (3,422 )    $ —      $ —      $ (98 ) $ (98 )














Total liabilities
   $ —      $ —      $ (3,422 )    $ (3,422 )    $ —      $ —      $ (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~~six months ended ~~September~~June 30, ~~2018.~~2019.

(Thousands of dollars)
Net Liabilities – December 31, 2017
   $ (3,034 )
Total realized and unrealized gains (losses):

Net Asset– December 31, 2018
   $ 2,296
Total realized and unrealized (gains) losses:

Included in earnings (a)
   (11,077 )    (3,663 )
Purchases, sales, issuances and settlements
   2,925    773




Net Liabilities – September 30, 2018
   $ (11,186 )
Net Liabilities June 30, 2019
   $ (594 )




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 June 30, 2019 and December 31, 2018.
The following table sets forth the effect of derivative instruments on the consolidated balance sheets at ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017:~~2018:

Fair Value
(Thousands of dollars) Balance Sheet Location September 30,
2018 December 31,
2017
Asset Derivatives:

Derivatives not designated as cash-flow hedging instruments:

Natural gas commodity contracts
Other Current Assets $ 55 $ —
Natural gas liquid contracts
Other Current Assets —   —
Crude oil commodity contracts
Other Current Assets —   344
Natural gas commodity contracts
Other Assets 13 44
Natural gas liquid contracts
Other Assets —   —

Total
$ 68 $ 388

Liability Derivatives:

Derivatives not designated as cash-flow hedging instruments:

Crude oil commodity contracts
Derivative liability short-term (7,420) (1,504)
Natural gas commodity contracts
Derivative liability short-term (47) (4)
Natural gas liquid contracts
Derivative liability short-term (561) —
Crude oil commodity contracts
Derivative liability long-term (3,143) (1,910)
Natural gas commodity contracts
Derivative liability long-term —   (4)
Natural gas liquid contracts
Derivative liability long-term (83) —

Total
$ (11,254) $ (3,422)

Total derivative instruments
$ (11,186) $ (3,034)

      Fair Value
(Thousands of dollars)
   Balance Sheet Location    June 30,
2019    December 31,
2018
Asset Derivatives:

Derivatives not designated as cash-flow hedging instruments:

Natural gas commodity contracts
   Derivative asset short-term    $ 136    $ 63
Natural gas liquid contracts
   Derivative asset short-term    $ 185    $ 138
Crude oil commodity contracts
   Derivative asset short-term    $ 760    $ 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
      $ 1,081    $ 2,394




Liability Derivatives:

Derivatives not designated as cash-flow hedging instruments:

Crude oil commodity contracts
   Derivative liability short-term    $ (1,675 )    $ —
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
      $ (1,675 )    $ (98 )




Total derivative instruments
      $ (594 )    $ 2,296




The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the ~~nine month~~six-month period ended ~~September~~June 30, ~~2018~~2019 and ~~2017:~~2018:


Location of gain (loss) recognized in income
   Amount of gain/loss
recognized in income
Location of gain (loss) recognized in income
   Amount of gain/loss
recognized in income
(Thousands of dollars)
   2018    2017    2019    2018
Derivatives not designated as cash-flow hedge instruments:

Natural gas commodity contracts
   Unrealized (loss) gain on derivative instruments, net    $ (359 )    $ 1,709    Unrealized gain (loss) on derivative instruments, net    $ 151    $ (328 )
Crude oil commodity contracts
   Unrealized (loss) gain on derivative instruments, net    $ (7,148 )    1,383    Unrealized loss on derivative instruments, net    (3,101 )    (5,432 )
Natural gas liquids contracts
   Unrealized gain on derivative instruments, net    (645 )    —      Unrealized gain (loss) on derivative instruments, net    60    (197 )
Natural gas commodity contracts
   Realized (loss) on derivative instruments, net    124    (130 )    Realized (loss) gain on derivative instruments, net    (8 )    85
Crude oil commodity contracts
   Realized (loss) on derivative instruments, net    (2,895 )    81    Realized loss on derivative instruments, net    (876 )    (1,634 )
Natural gas liquids contracts
   Realized gain on derivative instruments, net    (154 )    —      Realized gain (loss) on derivative instruments, net    111    (27 )








      $ (11,077 )    $ 3,043       $ (3,663 )    $ (7,533 )




(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,    Six Months Ended June 30,
   2018    2017    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    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
   $ 7,115    2,102,853    $ 3.38    $ 20,648 2,223,399    $ 9.29    $ 2,737    2,031,569    $ 1.35    $ 2,726 2,119,343    $ 1.29
Effect of dilutive securities: Options
      754,558       750,731
Effect of dilutive securities:

Options
      761,169       753,404













Diluted
   $ 7,115    2,857,411    $ 2.49    $ 20,648 2,974,130    $ 6.94    $ 2,737    2,792,738    $ 0.98    $ 2,726 2,872,747    $ 0.95













   Three Months Ended September,    Three Months Ended June 30,
   2018    2017    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    Net Income
(In 000’s)    Weighted
Average
Number of
Shares
Outstanding    Per Share
Amount    Net Income
(In 000’s) Weighted
Average
Number of
Shares
Outstanding    Per Share
Amount
Basic
   $ 4,353    2,069,231    $ 2.10    $ (2,012 ) 2,187,894    $ (0.92 )    $ 5,775    2,026,119    $ 2.85    $ (560 ) 2,097,737    $ (0.27 )
Effect of dilutive securities: Options (a)
      756,366       —   —
Effect of dilutive securities:

Options (a)
      761,584













Diluted
   $ 4,353    2,825,597    $ 1.54    $ (2,012 ) 2,187,894    $ (0.92 )    $ 5,775    2,787,702    $ 2.07    $ (560 ) 2,097,737    $ (0.27 )














(a)
The effect of the 767,500 outstanding stock option is anti-dilutive for the three months ended ~~September~~June 30, ~~2017~~2018 due to net loss for the period.
This Report may contain statements relating to the future results of the Company that are considered “forward-looking ~~statements” as~~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.

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 ~~over 20,440~~approximately 19,830 gross ~~(13,100~~(12,580 net) acres, ~~approximately 95%~~97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused. ~~Our West Texas~~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 ~~significant~~the resource potential into support the ~~Spraberry and Wolfcamp reservoirs that we believe could support the~~future drilling of as many as ~~400 additional~~375 horizontal wells.
In Oklahoma we maintain an acreage position of approximately ~~81,860~~81,800 gross (10,900 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately ~~2,215~~2,210 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 63105 new horizontal wells based on an estimate of ~~only two~~four to eight wells per section ~~with our share of such prospective future~~depending on the reservoir target area.
Future development ~~being approximately $33.3 million~~plans are established based on ~~an average 10.5% ownership level.~~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, ~~2017.~~2018.

   Appalachian    Gulf
Coast    Mid-
Continent    West
Texas    Other    Total    Appalachian    Gulf
Coast    Mid-
Continent    West
Texas    Other    Total
Proved Reserves as of December 31, 2017 (MBoe)

Proved Reserves as of December 31, 2018 (MBoe)

Developed
   537    803    1,774    6,742    37    9,893    559    814    2,839    8,401    8    12,622
Undeveloped
   —      —      132    647    —      779    —      —      43    —      —      43
Total
   537    803    1,906    7,389    37    10,672    559    814    2,882    8,401    8    12,665
Gross Productive Wells (Working Interest and ORRI wells)
   557    322    619    566    156    2,220
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)
   489    281    471    523    94    1,858    500    263    430    519    45    1,757
Net Productive Wells
   456    174    257    516    23    1,426
Net Productive Wells (Working Interest Only)
   469    164    227    256    4    1,120
Gross Operated Productive Wells
   467    244    348    370    57    1,486    476    211    243    354    —      1,284
Gross Operated Water Disposal, Injection and Supply wells
   1    8    64    7    1    81    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.
West Texas Region
Our West Texas activities are concentrated in the Permian Basin in Texas and New Mexico. The Spraberry field was 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 19,830 gross (12,580 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 first quarter of 2019, 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 $50.6 million, with the Company’s share being $24.9 million. Since completion these wells will have produced approximately 600,000 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 six months is approximately 212,500 barrels. We are pleased with the economic performance of these eight wells and expect 100% capital recover in less than two years.
In the second quarter of 2019, in our West Texas horizontal drilling program, we completed three new horizontal wells in intervals above the Middle Wolfcamp that previously were not proven as horizontal target reservoirs for our acreage. In the first 60 days of production the three wells have produced 125,000 gross barrels of oil along with associated wellhead gas: 50,000 barrels from the Lower Spraberry, 46,000 barrels from the Jo Mill, and 31,000 barrels from the Upper Wolfcamp. PrimeEnergy has 49% working interest and 40.7% net revenue interest in the Lower Spraberry well, 47% working interest and 39% net revenue interest in the Jo Mill well and 5.3% working interest and 3.9% net revenue interest in the Upper Wolfcamp well. Our share of the gross $26 million cost of these three wells is approximately $8.9 million.
These three new horizontal wells in Upton County are important tests of the economic viability of the shallower target zones, both for the 1,300 acre block in which they were drilled, as well as for our nearby 2,600 leasehold AMI (Area of Mutual Interest) acreage with Apache that holds similar potential. The successful outcome hasproven-up 21 additional locations in the 1,300 acre block, making these locations more likely to be drilled in the near future. The gross cost of an additional 21 wells would be approximately $182 million, with the Company’s share being $60 million. In the nearby Apache AMI, Prime holds several leases with interest varying from 14% to 56%. The strong performance of these new horizontals is likely to spur the drilling of as many as 96 additional horizontal wells in the Apache AMI over the coming years. The gross cost of 96 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.
In the Permian Basin of West Texas the Company maintains an acreage position of approximately 19,830 gross (12,580 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.
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 81,800 gross (10,900 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 Kingsfisher County and broughton-line in March of 2019. Prime participated with 11.87% interest in these five new wells, investing approximately $4.9 million. This group of wells is showing strong initial production performance. This activity has now been closely followed by the
proposed drilling of 19 new wells by Encana Corporation in nearby leases in which PrimeEnergy has an average of 7.05% interest. Twelve of these wells were spud in June 2019 and the Company has agreed to participate for its average interest in these wells of 4.9% interest. Drilling and completion costs of these 19 wells net to our interest are expected to be $9.3 million. Also in Oklahoma, the Company recently participated with Roane 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. These wells were included as Proved Undeveloped in the 2018year-end reserve report. The estimated total expenditure net to the Company is approximately $1.46 Million. Three of these seven wells came on line July, 2019 and we anticipate the other four wells will also be completed and put into production in the third quarter of 2019. 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, and Garvin counties where we have approximately 2,210 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 June 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.
Gulf Coast Region
Our development, exploitation, 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 6% 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 four workover rigs, nineteen water transport trucks, two saltwater disposal wells and several trucks and excavating equipment. 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.
As of June 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          Reserve Category
   Proved Developed    Proved Undeveloped    Total    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)    Oil
(MBbls)    NGLs
(MBbls)    Gas
(MMcf)    Total
(MBoe)    Oil
(MBbls)    NGLs
(MBbls)    Gas
(MMcf)    Total
(MBoe)    Oil
(MBbls)    NGLs
(MBbls)    Gas
(MMcf)    Total
(MBoe)
            (a)             (a)             (a)
2015
   4,579    1,673    23,275    10,131    52    12    55    73    4,631    1,685    23,330    10,204
2016
   3,107    1,265    13,001    6,539    643    159    2,003    1,135    3,750    1,424    15,004    7,674    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    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. These eight wells are expected to be completed and put on production in the second and third quarters of 2019. 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.
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, ~~2017,~~2018, are summarized as follows (in thousands of dollars):

   Proved Developed    Proved Undeveloped    Total    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    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
2015
   $ 70,834    $ 60,962    $ 1,098    $ 233    $ 71,932    $ 61,195    $ 2,393    $ 58,802
2016
   $ 56,467    $ 46,827    $ 18,114    $ 10,403    $ 74,581    $ 57,230    $ 4,993    $ 52,237    $ 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    $ 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 ~~SEC rules governing~~U.S. generally accepted accounting principles, product prices are determined using the ~~scheduling~~twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the ~~drilling~~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 ~~PUD reserves~~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 ~~only~~not filed any estimates of our oil and gas reserves with, nor were any such estimates included in ~~ouryear-end~~ ~~reserve report~~any reports to, any federal authority or agency, other than the ~~22 PUD locations for which we have definitive plans to drill. The Company has a working interest in eight of these PUD locations~~Securities and ~~an overriding royalty interest in the remaining fourteen locations. Currently all 22 of these PUD locations have been drilled, and 20 are producing.~~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.
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 ~~2018,~~2019, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our ~~2018~~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 ~~and through the 3rd quarter of 2018,~~ the Company has participated in 67 horizontal wells and invested approximately $103 million dollars. The Company has an acreage position approximately 12,580 net acres in West Texas with the potential to drill 375 or more new horizontal wells. In Oklahoma, since the start in 2012 of our horizontal drilling program in the SCOOP/STACK shale plays, the Company has drilled or committed to drill 64 wells with a total investment of approximately $46 million dollars, plus has elected to receive an overriding royalty interest in 63 additional wells drilledto-date. The Company holds approximately 2,210 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 horizontal wells in our West ~~Texas; 46~~Texas horizontal development program and 11 horizontal wells in our Scoop-Stack horizontal development program in Oklahoma. All 28 wells were successful and are producing.
In the first quarter of ~~these were completed and producing by~~2019, in our West Texas horizontal drilling program, the Company participated for 49.3% interest in eight~~year-end~~one-mile ~~2017, and 10 more have been broughton-line~~horizontal wells drilled in the ~~first nine months 2018. Of the total 64~~Middle Wolfcamp. These wells ~~drilled and producing, the Company has an average of 28% interest in 49 wells, and less than one percent interest in 15 wells. Of the 10 wells~~were brought on production in February, 2019. The total cost of these eight wells and their facilities is approximately $50.6 million, with the Company’s share being $24.9 million.    Since completion these wells will have produced approximately 600,000 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 ~~nine~~six months is approximately 212,500 barrels. We are pleased with the economic performance of ~~2018,~~these eight wells and expect 100% capital recover in less than two years.
In the second quarter of 2019, in our West Texas horizontal drilling program, we completed three ~~aretwo-mile~~ ~~long~~new horizontal ~~laterals. The Company~~wells in intervals above the Middle Wolfcamp that previously were not proven as horizontal target reservoirs for our acreage. In the first 60 days of production the three wells have produced 125,000 gross barrels of oil along with associated wellhead gas: 50,000 barrels from the Lower Spraberry, 46,000 barrels from the Jo Mill, and 31,000 barrels from the Upper Wolfcamp. PrimeEnergy has ~~38.25%~~49% working interest and 40.7% net revenue interest in the Lower Spraberry well, 47% working interest and 39% net revenue interest in the Jo Mill well and 5.3% working interest and 3.9% net revenue interest in the Upper Wolfcamp well. Our share of the gross $26 million cost of these three wells ~~and invested~~is approximately ~~$10.1~~$8.9 million. ~~As to~~
These three new horizontal wells in Upton County are important tests of the ~~remaining seven wells brought on production~~economic viability of the shallower target zones, both for the 1,300 acre block in which they were drilled, as well as for our nearby 2,600 leasehold AMI acreage with Apache that holds similar potential. The successful outcome hasproven-up 21 additional locations in the ~~first nine months~~1,300 acre block, making these locations more likely to be drilled in the near future. The gross cost of ~~2018,~~an additional 21 wells would be approximately $182 million, with the ~~Company has less than 1% interest.~~Company’s share being $60 million. In the 3^rd ~~quarter~~nearby Apache AMI, Prime holds several leases with interest varying from 14% to 56%. The strong performance of ~~2018, PrimeEnergy is participating in eight~~these new horizontals wells, each having a one mile long lateral. The Company has 49% interest in these wells and will invest approximately $22.7 million including for production facilities. We anticipate these eight wellsis likely to ~~be on line in the 1st quarter of 2019.~~
In Upton County, West Texas, we are developing a contiguous 3,900 acre block with our joint venture partner, Apache Corporation. In this block the Company has 2,543 leasehold acres with interest between 14% and 56%, depending on the formation or depth being developed. Through the 3rd quarter of 2018, 25 wells have been drilled and completed in this joint venture, including three~~two-mile~~ long horizontals completed and put on production as of July 1, 2018. In addition, the Company is participating for 49% interest in eight wells that are in the process of being drilled and completed. Apache Corporation has indicated plans to continue PAD drilling of the acreage with future phases of development expected to result inspur the drilling of ~~approximately~~as many as 96 additional horizontal wells ~~at a~~in the Apache AMI over the coming years. The gross cost of 96 wells here would be approximately $748 million inwith the ~~contiguous 3900 acre block. The~~ Company’s share ~~of these future capital expenditures would be~~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.
~~Also in Upton County,~~In the Permian Basin of West Texas the Company maintains an acreage position of approximately 19,830 gross (12,580 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.
In Oklahoma, in 2018, the Company participated in 11 wells, with six of these on production byyear-end. Five of these wells, drilled by Marathon in the “Ruthie 1609” tract in Kingsfisher County, were broughton-line in March of 2019. Prime participated with 11.87% interest in these five new wells, investing approximately $4.9 million. This group of wells is ~~developing a separate 1,310 acre block, with Apache Corporation as operator. Plans for~~showing strong initial production performance. This activity has now been closely followed by the ~~4th quarter of 2018 include the~~proposed drilling of ~~three~~19 new ~~horizontal~~ wells ~~that will develop target pay intervals other than~~by
Encana Corporation in nearby leases in which PrimeEnergy has an average of 7.05% interest. Twelve of these wells were spud in June 2019 and the ~~middle Wolfcamp. The gross drilling~~Company has agreed to participate for its average interest in these wells of 4.9% interest. Drilling and completion costs ~~for these three wells will be approximately $26 million. Prime holds between 5% and 48% working interest in various depths of this acreage and our share~~ of these ~~three~~19 wells will be approximately $8.5 million. With favorable results from these three wells an additional 21 wells would likely be drilled in the near future at a gross cost of approximately $182 million with the Company’s share being approximately $60 million.
In Martin County, Texas we are developing a 960 acre block with Concho Resources. In 2016, two wells were drilled and completed and two additional wells were drilled and brought on line in 2017. The Company owns 35% to 38% interest in this joint venture acreage where Concho Resources is the operator. No near-term additional drilling plans have been received from Concho Resources, however, offset operators have been actively drilling and their results appear encouraging for the future development of multiple landing zones within this acreage block.
~~With regard~~net to our ~~Oklahoma horizontal development program, which began~~interest are expected to be $9.3 million.
Also in ~~2012,~~Oklahoma, the Company ~~has~~recently participated in 41 horizontal wells for approximately $35 million through September, 2018. Over this same time period the Company chose to retain an overriding royalty interest in 29 other horizontal wells that were being drilled. In the first nine months of 2018, the Company has participated in eleven wells to be completed this year at a net cost of $8.5 million. Also in the first nine months of 2018, the Company elected to retain an ORRI in 22 wells that are in the process of being drilled or completed located in various counties of central Oklahoma. In the 4th quarter of 2018 the Company anticipates participatingwith Roane Resources, Inc. in the drilling of ~~six additional horizontal~~seven wells in ~~central Oklahoma with~~Grady County, Oklahoma. The Company has 10% interest in one of these seven wells and less than one ~~percent.~~percent interest in the remaining six. The estimated total expenditure net to the Company is approximately $1.46 Million. Three of these seven wells came on line July, 2019 and we anticipate the other four wells will also be completed and put into production in the third quarter of 2019. 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 ~~on Company acreage~~ in Oklahoma is primarily focused in Canadian, Grady, Kingfisher, and Garvin counties where we have approximately ~~2,215~~2,210 net ~~acres.~~leasehold acres within the SCOOP/STACK shale plays. We believe this acreage has significant additional resource potential that could support the drilling of 63as many as 105 new horizontal wells based on an estimate of ~~only two~~eight wells per ~~section with our share of the capital expenditure being approximately $33.3 million at an average 10.5% ownership level.~~
~~In the first nine months of 2018,~~section: four in the ~~Gulf Coast region of Texas, Unit Petroleum drilled~~Mississippian and ~~completed two successful wells and recompleted a third well~~four in the Wilcox Formation of the Jazz field in Polk County. The Company has a 3.87% overriding royalty interest in both of the newly drilled wells and a 1.575% overriding royalty interest in the recompleted well. In addition, the Company successfully recompleted a shallow well in the Segno field of Polk County, Texas in which the company has a 72.5% working interest.Woodford Shale.
RESULTS OF OPERATIONS
~~2018~~2019 and ~~2017~~2018 Compared
We reported anet income of $2.7 million, or $1.35 per share and $5.8 million, or $2.85 per share for the six and three months ended June 30, 2019, respectively, as compared to net income for the ~~nine~~six months ended ~~September~~June 30, 2018 of ~~$7.1~~$2.7 million, or ~~$3.38~~$1.29 per share and a net ~~income~~loss for the three months ended ~~September~~June 30, 2018 of ~~$4.4~~$0.6 million, or ~~$2.10~~$0.27 per ~~share, as compared to net income of $20.6 million, or $9.29 per share and a loss of $2 million, or $(0.92) per share for the nine and three months ended September 30, 2017, respectively.~~share. Current year net income reflects an increase in production combined with commodity price changes over the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~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 increased ~~$14.4~~$1.7 million, or ~~114.4%~~8% from ~~$12.6~~$21.7 million for the three months ended ~~September~~June 30, ~~2017~~2018 to ~~$27~~$23.4 million for the three months ended ~~September~~June 30, ~~2018~~2019 and increased ~~$34.8~~$0.5 million, or ~~89%~~1% from ~~$39~~$46.8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 to ~~$74~~$47.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019.
Our realized prices at the well head ~~increased~~decreased an average of ~~$18.04~~$4.52 per barrel, or ~~40%~~7% and ~~$16.48~~$7.04 per barrel, or ~~35%~~11% on crude oil during the three and ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, respectively from the same periods in ~~2017.~~2018. Our average price for natural gas decreased ~~$0.24~~$1.01 per Mcf, or 9%49% and ~~$0.55~~$0.73 per Mcf, or ~~19%~~31% during the three and ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, respectively from the same periods in ~~2017.~~2018. Our average price for NGLs sold ~~increased~~decreased an average of ~~$10.84~~$11.15 per barrel, or ~~51%~~41% and ~~$7.27~~$8.61 per barrel, or ~~34%~~32% during the three and ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, respectively from the same periods in ~~2017.~~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 quarter of 2019. This gas pricing is expected to continue until Waha prices improve, which is anticipated when the third-party operated Gulf Coast Express (GCX) pipeline enters service in late September.
Our crude oil production increased by ~~142,000~~71,000 barrels or ~~75%~~27% from ~~190,000~~261,000 barrels for the ~~third~~second quarter ~~2017~~2018 to 332,000 barrels for the ~~third~~second quarter ~~2018~~2019 and increased by ~~325,000~~104,000 barrels, or ~~55%~~18% from ~~591,000~~584,000 barrels for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 to ~~916,000~~688,000 barrels for the ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019. Our natural gas production ~~decreased~~increased by ~~41,000~~331,000 Mcf, or 4%34% from ~~947,000~~964,000 Mcf for the ~~third~~second quarter ~~2017~~2018 to ~~906,000~~1,295,000 Mcf for the ~~third~~second quarter ~~2018~~2019 and increased by ~~136,000~~372,000 Mcf, or 5%20% from ~~2,641,000~~1,871,000 Mcf for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 to ~~2,777,000~~2,243,000 Mcf for the ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019. Our NGL production increased by ~~49,000~~33,000 barrels or ~~68%~~29% from ~~72,000~~113,000 barrels for the ~~third~~second quarter ~~2017~~2018 to ~~121,000~~146,000 barrels for the ~~third~~second quarter ~~2018~~2019 and increased by ~~152,000~~75,000 barrels, or ~~83.5%~~35% from ~~182,000~~213,000 barrels for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 to ~~334,000~~288,000 barrels for the ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019. The net increase in production volumes reflect by production from ~~our Upton county horizontal~~new wells added in ~~late 2017 and mid 2018,~~February through May 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 three months ended June 30, 2019 and 2018 (excluding realized gains and losses from derivatives).

      Nine months September 30,
   2018    2017    Increase /
(Decrease)    Increase /
(Decrease)
Barrels of Oil Produced
   916,000    591,000    325,000    55.0 %
Average Price Received
   $ 62.97    $ 46.50    $ 16.48    35.4 %







Oil Revenue (In 000’s)
   $ 57,683    $ 27,479    $ 30,204    109.9 %







Mcf of Gas Sold
   2,777,000    2,641,000    136,000    5.1 %
Average Price Received
   $ 2.35    $ 2.90    $ (0.55)    (19.0 )%







Gas Revenue (In 000’s)
   $ 6,526    $ 7,665    $ (1,139)    (14.9 )%







Barrels of Natural Gas Liquids Sold
   334,000    182,000    152,000    83.5 %
Average Price Received
   $ 28.71    $ 21.43    $ 7.27    33.9 %







Natural Gas Liquids Revenue (In 000’s)
   $ 9,588    $ 3,901    $ 5,687    145.8 %







Total Oil & Gas Revenue (In 000’s)
   $ 73,797    $ 39,045    $ 34,752    89.0 %







      Six months ended June 30,
   2019    2018    Increase /
(Decrease) Increase /
(Decrease)
Barrels of Oil Produced
   688,000    584,000    104,000 18 %
Average Price Received
   $ 55.84    $ 62.88    $ (7.04 ) (11 )%






Oil Revenue (In 000’s)
   $ 38,442    $ 36,723    $ 1,719 5 %






Mcf of Gas Sold
   2,243,000    1,871,000    372,000 20 %
      Three months ended September 30,       Six months ended June 30,
   2018    2017    Increase /
(Decrease)    Increase /
(Decrease)    2019    2018    Increase /
(Decrease) Increase /
(Decrease)
Barrels of Oil Produced
   332,000    190,000    142,000    74.7 %
Average Price Received
   $ 63.13    $ 45.09    $ 18.04    40.0 %







Oil Revenue (In 000’s)
   $ 20,960    $ 8,568    $ 12,392    144.6 %







Mcf of Gas Sold
   906,000    947,000    (41,000 )    (4.3 )%
Average Price Received
   $ 2.40    $ 2.64    $ (0.24)    (9.2 )%    $ 1.60    $ 2.33    $ (0.73 ) (31 )%












Gas Revenue (In 000’s)
   $ 2,174    $ 2,502    $ (328)    (13.1 )%    $ 3,590    $ 4,352    $ (762 ) (18 )%












Barrels of Natural Gas Liquids Sold
   121,000    72,000    49,000    68.1 %    288,000    213,000    75,000 35 %
Average Price Received
   $ 32.15    $ 21.31    $ 10.84    50.9 %    $ 18.14    $ 26.75    $ (8.61 ) (32 )%












Natural Gas Liquids Revenue (In 000’s)
   $ 3,890    $ 1,534    $ 2,356    153.6 %    $ 5,219    $ 5,698    $ (479 ) (8 )%












Total Oil & Gas Revenue (In 000’s)
   $ 27,024    $ 12,604    $ 14,420    114.4 %    $ 47,251    $ 46,773    $ 478 1 %












      Three months ended June 30,
   2019    2018    Increase /
(Decrease) Increase /
(Decrease)
Barrels of Oil Produced
   332,000    261,000    71,000 27 %
Average Price Received
   $ 59.17    $ 63.69    $ (4.52 ) (7 )%






Oil Revenue (In 000’s)
   $ 19,644    $ 16,622    $ 3,022 18 %






Mcf of Gas Sold
   1,295,000    964,000    331,000 34 %
Average Price Received
   $ 1.05    $ 2.06    $ (1.01 ) (49 )%






Gas Revenue (In 000’s)
   $ 1,355    $ 1,989    $ (634 ) (32 )%






Barrels of Natural Gas Liquids Sold
   146,000    113,000    33,000 29 %
Average Price Received
   $ 16.27    $ 27.42    $ (11.15 ) (41 )%






Natural Gas Liquids Revenue (In 000’s)
   $ 2,375    $ 3,098    $ (723 ) (23 )%






Total Oil & Gas Revenue (In 000’s)
   $ 23,374    $ 21,709    $ 1,665 8 %






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~~six months ended ~~September 2018~~June 2019 and ~~2017:~~2018:

   Three Months Ended
September 30,    Nine months Ended
September 30,    Three Months Ended
June 30,    Six Months Ended
June 30,
   2018    2017    2018    2017    2019    2018    2019 2018
      ($ in thousand)          ($ in thousand)
Oil derivatives – realized gains (losses)
   $ (1,261)    $ 159    $ (2,895)    $ 81    $ (964 )    $ (1,156 )    $ (876 ) $ (1,634 )
Oil derivatives – unrealized gains (losses)
   (1,716 )    (108 )    (7,148 )    1,383    2,637    (3,564 )    (3,101 ) (5,432 )














Total gains (losses) on oil derivatives
   $ (2,977)    $ 51    $ (10,043)    $ 1,464    $ 1,673    $ (4,720 )    $ (3,977 ) $ (7,066 )
Natural gas derivatives – realized gains (losses)
   $ 39    $ 19    $ 124    $ (130)    $ 4    $ 105    $ (8 ) $ 85
Natural gas derivatives – unrealized gains (losses)
   (31 )    396    (359 )    1,709    156    (249 )    151 (328 )














Total gains (losses) on natural gas derivatives
   $ 8    $ 415    $ (235)    $ 1,579    $ 160    $ (144 )    $ 143 $ (243 )
NGL derivatives – realized (losses)
   $ (127)    $ —      $ (154)    $ —
NGL derivatives – realized gain (losses)
   $ 109    $ (30 )    $ 111 $ (27 )
NGL derivatives – unrealized gains (losses)
   (448 )    —      (645 )    —      69    (323 )    60 (197 )














Total gains (losses) on NGL derivatives
   (575 )    —      (799 )    —      178    (353 )    171 (225 )














Total gains (losses) on oil, natural gas and NGL derivatives
   $ (3,544)    $ 466    $ (11,077)    $ 3,043    $ 2,011    $ (5,217 )    $ (3,663 ) $ (7,533 )














Prices received for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017,~~2018, respectively, including the impact of derivatives were:

   2018    2017    2019    2018
Oil Price
   $ 59.81    $ 46.63    $ 54.56    $ 59.26
Gas Price
   $ 2.39    $ 2.85    $ 1.00    $ 2.17
NGLS Price
   $ 28.24    $ 21.43    $ 18.52    $ 27.15
Field service income increased $0.4 million or ~~8.8%~~0.01% from ~~$4.1~~$4.4 million for the ~~third~~second quarter ~~2017~~2018 to ~~$4.5~~$4.8 million for the ~~third~~second quarter ~~2018~~2019 and ~~$1.0~~$0.8 million, or ~~7.9%~~0.01% from ~~$12.2~~$8.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 to ~~$13.1~~$9.5 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019. This increase is a combined result of increased utilization and rates charged to customers during the ~~2018~~2019 period. Workover rig services, hot oil treatments, salt water hauling and disposal represent the bulk of our field service operations.
Lease operating expense ~~increased $2.8~~decreased $0.7 million or ~~41%~~0.01% from ~~$6.8~~$8.8 million for the ~~third~~second quarter ~~2017~~2018 to ~~$9.5~~$8.1 million for the ~~third~~second quarter ~~2018~~2019, and ~~increased $5.8~~decreased $1.1 million or ~~27.6%~~0.01% from ~~$21~~$17.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 to ~~$26.9~~$16.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019. This ~~increase~~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 ~~and increased production taxes related to increased prices and production~~ during the first ~~nine~~three months of ~~2018~~2019 as compared to the same period of ~~2017.~~2018.
Field service expense increased ~~$0.6~~$0.8 million or ~~19.3%~~0.02% from ~~$3.1~~$3.2 million for the ~~third~~second quarter ~~2017~~2018 to ~~$3.7~~$4.0 million for the ~~third~~second quarter ~~2018~~2019 and increased ~~$1.0~~$1.2 million, or ~~19.3%~~0.02% from ~~$9.2~~$6.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 to ~~$10.2~~$7.6 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019. Field service expenses primarily consist of salaries and vehicle operating expenses which have increased during the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 over the same period of ~~2017~~2018 as a direct result of increased services and utilization of the equipment.
Depreciation, depletion, amortization and accretion on discounted liabilities ~~remained flat~~increased $1.4 million, or 0.02% from ~~$7.8 million for the third quarter 2017 to~~ $7.9 million for the ~~third~~second quarter 2018 ~~and $23.8~~to $9.3 million for the ~~nine months ended September 30, 2017 to $23.7~~second quarter 2019 and $2.8 million, or 0.02% from $15.8 million for the ~~nine~~six months ended ~~September~~June 30, 2018 to $18.6 million for the six months ended June 30, 2019, reflecting the increased ~~reserve base and~~ production related to new wells placed on production late in ~~2017~~2018 and ~~mid 2018.~~the first two quarters of 2019.
General and administrative expense increased ~~$3.9~~$1.3 million, or ~~56.5%~~0.01% from ~~$6.9~~$8.5 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 to ~~$10.8~~$9.8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, and ~~decreased~~increased $0.3 million, or ~~10.8%~~0.01% from ~~$2.5~~$2.6 million for the three months ended ~~September~~June 30, ~~2017~~2018 to ~~$2.25~~$2.9 million for the three months ended ~~September~~June 30, ~~2018.~~2019. This increase in ~~2018~~2019 reflects the combination of a reduction in G&A reimbursements related to the ~~decrease in gains on sales~~sale of ~~properties from 2017 to 2018~~property and increases in personnel costs.
Gain on sale and exchange of assets of ~~$3.2~~$2.7 million and ~~$42.1~~$1.7 million for the ~~nine~~six months ended ~~September~~June 30, 2018 and ~~September~~June 30, ~~2017,~~2019, respectively consists of sales ofnon-essential oil and gas interests and field service equipment.
Interest expense increased from ~~$0.6~~$0.9 million for the ~~third~~second quarter ~~2017~~2018 to ~~$0.8~~$1.0 million for the ~~third~~second quarter ~~2018~~2019 and from ~~$1.7~~$1.8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 to ~~$2.6~~$2.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019. This increase reflects the increase in current ~~rates and~~ borrowings under our revolving credit agreement.
Income tax expense ~~decreased $10.1 million due to a lower effective tax rate and lowerpre-tax~~ ~~income. The effective tax rates~~ for the ~~nine months of~~June 30, 2018 and ~~2017 were 25% and 32.1%, respectively. The decrease in the effective tax rate is primarily~~2019 periods varied due to the ~~impact of the Tax Cuts and Jobs Act changes that are effective January 1, 2018.~~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 ~~and~~& gas properties and field services business, and from sales ofnon-core acreage.
Net cash provided by our operating activities for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 was ~~$25.5~~$13.7 million compared to ~~$21.4~~$7.4 million ~~provided by operating activities~~ for the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~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 ~~vast~~ majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility we sometimes lock in prices for some portion of our production through the use of derivatives.
If our exploratory drilling results in significant new discoveries, we will have to expend additional capital in order to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells, 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. ~~The~~As of August 1, 2019 the Company ~~currently~~ has ~~$55~~$64.5 million in outstanding borrowings and ~~$35million~~$25.5 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 ~~2018.~~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~~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.
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 agreements for oil ~~natural gas~~ and natural ~~gas liquids.~~gas.

   Volumes    Prices
   2018    2019    2020    2018    2019    2020    2019    2020    2019    2020
Natural Gas (MMBTU)
   600,000    749,000    180,000    $ 2.97    $ 2.93    $ 2.95    180,000    180,000    $ 2.77    $ 2.95
Natural Gas Liquids (barrels)
   18,000    60,000    —      $ 22.73    $ 21.66       30,000    —      $ 21.66    —
Oil (barrels)
   71,700    540,500    100,500    $ 51.95    $ 53.53    $ 56.11    264,000    225,500    $ 53.00    $ 58.43
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For ~~2018,~~2019, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our ~~2018~~2019 capital budget is reflective of ~~current~~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 ~~2018. For the nine month period ended September 30, 2018,~~2019. As of August 1, 2019, we have spent ~~$6.3~~$4.109 million under these ~~programs.~~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~~six months of ~~2018~~2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II—OTHER INFORMATION

Item 1.
LEGAL PROCEEDINGS
None.

Item 1A.
RISK FACTORS
The Company is a smaller reporting company and no response is required pursuant to this Item.
Item 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
There were no sales of equity securities by the Company during the period covered by this report.
During the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, the Company purchased the following shares of common stock as treasury shares.

2018 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
   178    $ 55.55    122,736
February
   64,841    $ 50.18    57,895
March
   2,199    $ 52.50    55,696
April
   4,787    $ 54.08    50,909
May
   417    $ 69.81    50,492
June
   417    $ 69.35    250,075
July
   34,522    $ 74.99    215,553
August
   93    $ 75.49    215,460
September
   111    $ 75.43    214,349





Total/Average
   107,565    $ 58.57





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





Total/Average
   22,411    $ 134.40






(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 ~~the Board of Directors of the Company approved an additional 500,000 shares of the Company’s stock to be included in the stock repurchase program. On~~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~~June 30, ~~2018,~~2019, a total of ~~3,484,651~~3,528,948 shares have been repurchased under this program for ~~$67,079,992~~$71,748,358 at an average price of ~~$19.25~~$20.33 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
Item 6.
EXHIBITS
The following exhibits are filed as a part of this report:

Exhibit
No.

  3.1    ~~Restated~~ Certificate of Incorporation of PrimeEnergy Resources Corporation, ~~(effective July~~as amended and restated of December ~~1, 2009) (Incorporated by reference to~~21, 2018, (filed as Exhibit 3.1 toof PrimeEnergy Resources Corporation Form~~10-Q~~8-K ~~for the quarter ended June~~on December ~~30, 2009)~~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 Form10-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).
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).
~~10.23.1~~ ~~Loan and Security Agreement dated July~~ 31, 2013, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.23.1 to PrimeEnergy Corporation Form~~10-Q~~ ~~for the quarter ended September~~ ~~30, 2013).~~
~~10.23.2~~ ~~Business Purpose Promissory Note dated July~~ 31, 2013, made by Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company to JP Morgan Chase Bank N.A. (Incorporated by reference to Exhibit 10.23.2 to PrimeEnergy Corporation Form~~10-Q~~ ~~for the quarter ended September~~ ~~30, 2013).~~
~~10.23.3~~ ~~Guaranty dated July~~ ~~31, 2013, made by PrimeEnergy Corporation in favor of JP Morgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.23.3 to PrimeEnergy Corporation Form~~ ~~10-Q~~ ~~for the quarter ended September~~ ~~30, 2013).~~
~~Exhibit No.~~
~~10.23.4~~ ~~Agreement of Equipment Substitution dated January~~ 15, 2014, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.23.4 to PrimeEnergy Corporation Form~~10-Q~~ ~~for the quarter ended March~~ ~~31, 2014).~~
~~10.24.1~~ ~~Loan and Security Agreement dated July~~ 29, 2014, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.24.1 to PrimeEnergy Corporation Form~~10-Q~~ ~~for the quarter ended September~~ ~~30, 2014).~~
~~10.24.2~~ ~~Business Purpose Promissory Note dated July~~ 29, 2014, made by Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company to JP Morgan Chase Bank N.A. (Incorporated by reference to Exhibit 10.24.2 to PrimeEnergy Corporation Form~~10-Q~~ ~~for the quarter ended September~~ ~~30, 2014).~~
~~10.24.3~~ ~~Guaranty dated July~~ ~~29, 2014, made by PrimeEnergy Corporation in favor of JP Morgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.24.3 to PrimeEnergy Corporation Form10-Q~~ ~~for the quarter ended~~
~~September~~ ~~30, 2014).~~
~~10.25~~ ~~Purchase and Sale Agreement dated as of January~~ ~~25, 2017, among PrimeEnergy Corporation, PrimeEnergy Management Corporation, PrimeEnergy Operating Company, PrimeEnergy Asset and Income Fund, L.P.A-2,~~ ~~PrimeEnergy Asset and Income Fund, L.P.A-3,~~ ~~PrimeEnergy Asset and Income Fund, L.P.AA-2,~~ ~~and PrimeEnergy Asset and Income Fund, L.P.AA-4,~~ ~~as Sellers and Guidon Operating LLC, as Purchaser (Incorporated by reference to Exhibit 10.25 to PrimeEnergy Corporation Form10-K~~ ~~for the year ended December~~ ~~31, 2016)~~.
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)
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 16, 2018~~August 14, 2019
/s/ Charles E. Drimal, Jr.
(Date) Charles E. Drimal, Jr.
President
Principal Executive Officer
~~November 16, 2018~~August 14, 2019
/s/ Beverly A. Cummings
(Date) Beverly A. Cummings
Executive Vice President

Principal Financial Officer

2529


(Thousands of dollars)	September 30, 2018			December 31, 2017			June 30, 2019			December 31, 2018
Accounts Receivable:
Joint interest billing	$	1,873		$	3,173		$	2,303		$	1,976
Trade receivables		2,207			941			2,725			1,979
Oil and gas sales		10,456			12,941			11,131			6,112
Tax refund receivable								—			4,760
Other		361			4			913			358

		14,897			17,059			17,072			15,185
Less: Allowance for doubtful accounts		(98	)		(98	)		(224	)		(224	)

Total	$	14,799		$	16,961		$	16,848		$	14,961

Accounts Payable:
Accounts Payable:
Trade	$	1,153		$	14,317		$	5,399		$	1,174
Royalty and other owners		7,944			8,341			5,742			6,197
Prepaid drilling deposits		114			67
Partner advances								1,335			1,357
Other		1,404			1,890			964			825

Total	$	10,615		$	24,615		$	13,440		$	9,553

Accrued Liabilities:
Accrued Liabilities:
Compensation and related expenses	$	2,387		$	2,449		$	3,161		$	2,907
Property costs		12,092			9,141			3,606			14,993
Income Tax		—			4,180
Other		785			524			—			531

Total	$	15,264		$	16,294		$	6,767		$	18,431


(Thousands of dollars)	Operating Leases
2018	$	133
2019		222
2020		69
2021		17

Total minimum payments	$	441


(Thousands of dollars)	Operating Leases			Financing Leases
2019	$	299		$	5
2020		155			7
2021		17			2

Total undiscounted lease payments	$	471		$	14
Less: Amount associated with discounting		(19	)		(1	)

Net operating lease liabilities	$	452		$	13


(Thousands of dollars)				June 30, 2019
Asset retirement obligation – December 31, 2017	$	23,578
Asset retirement obligation at December 31, 2018				$	21,334
Liabilities incurred		42			—
Liabilities settled		(1,967	)		(829	)
Accretion expense		840			560
Revisions in estimated liabilities					—

Asset retirement obligation – September 30, 2018	$	22,493
Asset retirement obligation at June 30, 2019				$	21,065


September 30, 2018	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, 2018
June 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 June 30, 2019
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	68		$	68		$	—	$	—	$	1,081		$	1,081

Total assets		—	$	—	$	68		$	68			—	$	—	$	1,081		$	1,081

Liabilities
Commodity derivative contracts	$	—	$	—	$	(11,254	)	$	(11,254	)	$	—	$	—	$	(1,675	)	$	(1,675	)

Total liabilities	$	—	$	—	$	(11,254	)	$	(11.254	)	$	—	$	—	$	(1,675	)	$	(1,675	)


December 31, 2017	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, 2017
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	$	—	$	—	$	388		$	388		$	—	$	—	$	2,394		$	2,394

Total assets	$	—	$	—	$	388		$	388		$	—	$	—	$	2,394		$	2,394

Liabilities
Commodity derivative contract	$	—	$	—	$	(3,422	)	$	(3,422	)	$	—	$	—	$	(98	)	$	(98	)

Total liabilities	$	—	$	—	$	(3,422	)	$	(3,422	)	$	—	$	—	$	(98	)	$	(98	)


(Thousands of dollars)
Net Liabilities – December 31, 2017	$	(3,034	)
Total realized and unrealized gains (losses):
Net Asset– December 31, 2018				$	2,296
Total realized and unrealized (gains) losses:
Included in earnings (a)		(11,077	)		(3,663	)
Purchases, sales, issuances and settlements		2,925			773

Net Liabilities – September 30, 2018	$	(11,186	)
Net Liabilities June 30, 2019				$	(594	)


			Fair Value
(Thousands of dollars)	Balance Sheet Location		September 30, 2018		December 31, 2017
Asset Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Natural gas commodity contracts		Other Current Assets	$	55	$	—
Natural gas liquid contracts		Other Current Assets		—		—
Crude oil commodity contracts		Other Current Assets		—		344
Natural gas commodity contracts		Other Assets		13		44
Natural gas liquid contracts		Other Assets		—		—

Total			$	68	$	388

Liability Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts		Derivative liability short-term		(7,420)		(1,504)
Natural gas commodity contracts		Derivative liability short-term		(47)		(4)
Natural gas liquid contracts		Derivative liability short-term		(561)		—
Crude oil commodity contracts		Derivative liability long-term		(3,143)		(1,910)
Natural gas commodity contracts		Derivative liability long-term		—		(4)
Natural gas liquid contracts		Derivative liability long-term		(83)		—

Total			$	(11,254)	$	(3,422)

Total derivative instruments			$	(11,186)	$	(3,034)


	Location of gain (loss) recognized in income	Amount of gain/loss recognized in income						Location of gain (loss) recognized in income	Amount of gain/loss recognized in income
(Thousands of dollars)	Location of gain (loss) recognized in income	2018			2017			Location of gain (loss) recognized in income	2019			2018
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized (loss) gain on derivative instruments, net	$	(359	)	$	1,709		Unrealized gain (loss) on derivative instruments, net	$	151		$	(328	)
Crude oil commodity contracts	Unrealized (loss) gain on derivative instruments, net	$	(7,148	)		1,383		Unrealized loss on derivative instruments, net		(3,101	)		(5,432	)
Natural gas liquids contracts	Unrealized gain on derivative instruments, net		(645	)		—		Unrealized gain (loss) on derivative instruments, net		60			(197	)
Natural gas commodity contracts	Realized (loss) on derivative instruments, net		124			(130	)	Realized (loss) gain on derivative instruments, net		(8	)		85
Crude oil commodity contracts	Realized (loss) on derivative instruments, net		(2,895	)		81		Realized loss on derivative instruments, net		(876	)		(1,634	)
Natural gas liquids contracts	Realized gain on derivative instruments, net		(154	)		—		Realized gain (loss) on derivative instruments, net		111			(27	)

		$	(11,077	)	$	3,043			$	(3,663	)	$	(7,533	)


	Nine months Ended September 30,														Six Months Ended June 30,
	2018						2017								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			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	$	7,115		2,102,853	$	3.38	$	20,648			2,223,399	$	9.29		$	2,737		2,031,569	$	1.35	$	2,726			2,119,343	$	1.29
Effect of dilutive securities: Options				754,558							750,731
Effect of dilutive securities:
Options																		761,169							753,404

Diluted	$	7,115		2,857,411	$	2.49	$	20,648			2,974,130	$	6.94		$	2,737		2,792,738	$	0.98	$	2,726			2,872,747	$	0.95


	Three Months Ended September,														Three Months Ended June 30,
	2018						2017								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			Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Income (In 000’s)			Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	4,353		2,069,231	$	2.10	$	(2,012	)		2,187,894	$	(0.92	)	$	5,775		2,026,119	$	2.85	$	(560	)		2,097,737	$	(0.27	)
Effect of dilutive securities: Options (a)				756,366				—			—
Effect of dilutive securities:
Options (a)																		761,584

Diluted	$	4,353		2,825,597	$	1.54	$	(2,012	)		2,187,894	$	(0.92	)	$	5,775		2,787,702	$	2.07	$	(560	)		2,097,737	$	(0.27	)


	Appalachian		Gulf Coast		Mid- Continent		West Texas		Other		Total		Appalachian		Gulf Coast		Mid- Continent		West Texas		Other		Total
Proved Reserves as of December 31, 2017 (MBoe)
Proved Reserves as of December 31, 2018 (MBoe)
Developed		537		803		1,774		6,742		37		9,893		559		814		2,839		8,401		8		12,622
Undeveloped		—		—		132		647		—		779		—		—		43		—		—		43
Total		537		803		1,906		7,389		37		10,672		559		814		2,882		8,401		8		12,665
Gross Productive Wells (Working Interest and ORRI wells)		557		322		619		566		156		2,220
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)		489		281		471		523		94		1,858		500		263		430		519		45		1,757
Net Productive Wells		456		174		257		516		23		1,426
Net Productive Wells (Working Interest Only)														469		164		227		256		4		1,120
Gross Operated Productive Wells		467		244		348		370		57		1,486		476		211		243		354		—		1,284
Gross Operated Water Disposal, Injection and Supply wells		1		8		64		7		1		81		1		9		67		7		—		84


	Reserve Category																								Reserve Category
	Proved Developed								Proved Undeveloped								Total								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)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)
							(a)								(a)								(a)
2015		4,579		1,673		23,275		10,131		52		12		55		73		4,631		1,685		23,330		10,204
2016		3,107		1,265		13,001		6,539		643		159		2,003		1,135		3,750		1,424		15,004		7,674		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		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


			Nine months September 30,
	2018		2017		Increase / (Decrease)		Increase / (Decrease)
Barrels of Oil Produced		916,000		591,000		325,000		55.0	%
Average Price Received	$	62.97	$	46.50	$	16.48		35.4	%

Oil Revenue (In 000’s)	$	57,683	$	27,479	$	30,204		109.9	%

Mcf of Gas Sold		2,777,000		2,641,000		136,000		5.1	%
Average Price Received	$	2.35	$	2.90	$	(0.55)		(19.0	)%

Gas Revenue (In 000’s)	$	6,526	$	7,665	$	(1,139)		(14.9	)%

Barrels of Natural Gas Liquids Sold		334,000		182,000		152,000		83.5	%
Average Price Received	$	28.71	$	21.43	$	7.27		33.9	%

Natural Gas Liquids Revenue (In 000’s)	$	9,588	$	3,901	$	5,687		145.8	%

Total Oil & Gas Revenue (In 000’s)	$	73,797	$	39,045	$	34,752		89.0	%


			Three months ended September 30,										Six months ended June 30,
	2018		2017		Increase / (Decrease)			Increase / (Decrease)			2019		2018		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Produced		332,000		190,000		142,000			74.7	%
Average Price Received	$	63.13	$	45.09	$	18.04			40.0	%

Oil Revenue (In 000’s)	$	20,960	$	8,568	$	12,392			144.6	%

Mcf of Gas Sold		906,000		947,000		(41,000	)		(4.3	)%
Average Price Received	$	2.40	$	2.64	$	(0.24)			(9.2	)%	$	1.60	$	2.33	$	(0.73	)		(31	)%

Gas Revenue (In 000’s)	$	2,174	$	2,502	$	(328)			(13.1	)%	$	3,590	$	4,352	$	(762	)		(18	)%

Barrels of Natural Gas Liquids Sold		121,000		72,000		49,000			68.1	%		288,000		213,000		75,000			35	%
Average Price Received	$	32.15	$	21.31	$	10.84			50.9	%	$	18.14	$	26.75	$	(8.61	)		(32	)%

Natural Gas Liquids Revenue (In 000’s)	$	3,890	$	1,534	$	2,356			153.6	%	$	5,219	$	5,698	$	(479	)		(8	)%

Total Oil & Gas Revenue (In 000’s)	$	27,024	$	12,604	$	14,420			114.4	%	$	47,251	$	46,773	$	478			1	%


	Three Months Ended September 30,						Nine months Ended September 30,					Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017		2019			2018			2019			2018
				($ in thousand)											($ in thousand)
Oil derivatives – realized gains (losses)	$	(1,261)		$	159		$	(2,895)		$	81	$	(964	)	$	(1,156	)	$	(876	)	$	(1,634	)
Oil derivatives – unrealized gains (losses)		(1,716	)		(108	)		(7,148	)		1,383		2,637			(3,564	)		(3,101	)		(5,432	)

Total gains (losses) on oil derivatives	$	(2,977)		$	51		$	(10,043)		$	1,464	$	1,673		$	(4,720	)	$	(3,977	)	$	(7,066	)
Natural gas derivatives – realized gains (losses)	$	39		$	19		$	124		$	(130)	$	4		$	105		$	(8	)	$	85
Natural gas derivatives – unrealized gains (losses)		(31	)		396			(359	)		1,709		156			(249	)		151			(328	)

Total gains (losses) on natural gas derivatives	$	8		$	415		$	(235)		$	1,579	$	160		$	(144	)	$	143		$	(243	)
NGL derivatives – realized (losses)	$	(127)		$	—		$	(154)		$	—
NGL derivatives – realized gain (losses)												$	109		$	(30	)	$	111		$	(27	)
NGL derivatives – unrealized gains (losses)		(448	)		—			(645	)		—		69			(323	)		60			(197	)

Total gains (losses) on NGL derivatives		(575	)		—			(799	)		—		178			(353	)		171			(225	)

Total gains (losses) on oil, natural gas and NGL derivatives	$	(3,544)		$	466		$	(11,077)		$	3,043	$	2,011		$	(5,217	)	$	(3,663	)	$	(7,533	)


	Volumes						Prices
	2018		2019		2020		2018		2019		2020		2019		2020		2019		2020
Natural Gas (MMBTU)		600,000		749,000		180,000	$	2.97	$	2.93	$	2.95		180,000		180,000	$	2.77	$	2.95
Natural Gas Liquids (barrels)		18,000		60,000		—	$	22.73	$	21.66				30,000		—	$	21.66		—
Oil (barrels)		71,700		540,500		100,500	$	51.95	$	53.53	$	56.11		264,000		225,500	$	53.00	$	58.43


2018 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		178	$	55.55		122,736
February		64,841	$	50.18		57,895
March		2,199	$	52.50		55,696
April		4,787	$	54.08		50,909
May		417	$	69.81		50,492
June		417	$	69.35		250,075
July		34,522	$	74.99		215,553
August		93	$	75.49		215,460
September		111	$	75.43		214,349

Total/Average		107,565	$	58.57


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

Total/Average		22,411	$	134.40


Exhibit No.

3.1		~~Restated~~ Certificate of Incorporation of PrimeEnergy Resources Corporation, ~~(effective July~~as amended and restated of December ~~1, 2009) (Incorporated by reference to~~21, 2018, (filed as Exhibit 3.1 toof PrimeEnergy Resources Corporation Form~~10-Q~~8-K ~~for the quarter ended June~~on December ~~30, 2009)~~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 Form10-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).


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).

~~10.23.1~~		~~Loan and Security Agreement dated July~~ 31, 2013, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.23.1 to PrimeEnergy Corporation Form~~10-Q~~ ~~for the quarter ended September~~ ~~30, 2013).~~

~~10.23.2~~		~~Business Purpose Promissory Note dated July~~ 31, 2013, made by Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company to JP Morgan Chase Bank N.A. (Incorporated by reference to Exhibit 10.23.2 to PrimeEnergy Corporation Form~~10-Q~~ ~~for the quarter ended September~~ ~~30, 2013).~~

~~10.23.3~~		~~Guaranty dated July~~ ~~31, 2013, made by PrimeEnergy Corporation in favor of JP Morgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.23.3 to PrimeEnergy Corporation Form~~ ~~10-Q~~ ~~for the quarter ended September~~ ~~30, 2013).~~


~~Exhibit No.~~

~~10.23.4~~		~~Agreement of Equipment Substitution dated January~~ 15, 2014, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.23.4 to PrimeEnergy Corporation Form~~10-Q~~ ~~for the quarter ended March~~ ~~31, 2014).~~

~~10.24.1~~		~~Loan and Security Agreement dated July~~ 29, 2014, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.24.1 to PrimeEnergy Corporation Form~~10-Q~~ ~~for the quarter ended September~~ ~~30, 2014).~~

~~10.24.2~~		~~Business Purpose Promissory Note dated July~~ 29, 2014, made by Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company to JP Morgan Chase Bank N.A. (Incorporated by reference to Exhibit 10.24.2 to PrimeEnergy Corporation Form~~10-Q~~ ~~for the quarter ended September~~ ~~30, 2014).~~

~~10.24.3~~		~~Guaranty dated July~~ ~~29, 2014, made by PrimeEnergy Corporation in favor of JP Morgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.24.3 to PrimeEnergy Corporation Form10-Q~~ ~~for the quarter ended~~ ~~September~~ ~~30, 2014).~~

~~10.25~~		~~Purchase and Sale Agreement dated as of January~~ ~~25, 2017, among PrimeEnergy Corporation, PrimeEnergy Management Corporation, PrimeEnergy Operating Company, PrimeEnergy Asset and Income Fund, L.P.A-2,~~ ~~PrimeEnergy Asset and Income Fund, L.P.A-3,~~ ~~PrimeEnergy Asset and Income Fund, L.P.AA-2,~~ ~~and PrimeEnergy Asset and Income Fund, L.P.AA-4,~~ ~~as Sellers and Guidon Operating LLC, as Purchaser (Incorporated by reference to Exhibit 10.25 to PrimeEnergy Corporation Form10-K~~ ~~for the year ended December~~ ~~31, 2016)~~.

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)


				PrimeEnergy Resources Corporation
				(Registrant)

~~November 16, 2018~~August 14, 2019				/s/ Charles E. Drimal, Jr.
(Date)				Charles E. Drimal, Jr.
				President
				Principal Executive Officer

~~November 16, 2018~~August 14, 2019				/s/ Beverly A. Cummings
(Date)				Beverly A. Cummings
				Executive Vice President
				Principal Financial Officer

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