PNRG 10-Q Quarter ended March 31, 2019

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended March 31, 2019

Or

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

For the Transition Period From to

Commission File Number 0-7406

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(s)		Name of each exchange on which registered

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-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 Rule 12b-2 of the Exchange Act.

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

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

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

The number of shares outstanding of each class of the Registrant’s Common Stock as of May 14, 2019 was: Common Stock, $0.10 par value 2,026,148 shares.

PrimeEnergy Resources Corporation

Index to Form 10-Q

March 31, 2019

		Page
Part I - Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets – March  31, 2019 and December 31, 2018			3
Condensed Consolidated Statements of Operations – For the three months ended March 31, 2019 and 2018			4
Condensed Consolidated Statement of Equity – For the three months ended March 31, 2019 and 2018			5
Condensed Consolidated Statements of Cash Flows – For the three months ended March 31, 2019 and 2018			6
Notes to Condensed Consolidated Financial Statements – March  31, 2019			7-14
Item  2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation			15-22
Item 3. Quantitative and Qualitative Disclosures About Market Risk			23
Item 4. Controls and Procedures			23
Part II - Other Information
Item 1. Legal Proceedings			23
Item 1A. Risk Factors			23
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			23
Item 3. Defaults Upon Senior Securities			23
Item 4. Reserved			24
Item 5. Other Information			24
Item 6. Exhibits			25-26
Signatures			27

2

PART I—FINANCIAL INFORMATION

Item 1.

FINANCIAL STATEMENTS

PRIMEENERGY RESOURCES CORPORATION

C ONDENSED C ONSOLIDATED B ALANCE S HEETS – Unaudited

(Thousands of dollars)

		March 31, 2019				December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents		$	8,251			$	6,315
Accounts receivable, net			21,868				14,961
Prepaid obligations			585				640
Derivative asset short-term			71				1,674
Other current assets			677				144
Total Current Assets			31,452				23,734
Property and Equipment, at cost
Oil and gas properties (successful efforts method), net			220,263				223,669
Field and office equipment, net			6,534				6,756
Total Property and Equipment, Net			226,797				230,425
Derivative asset long-term and other assets.			281				893
Total Assets		$	258,530			$	255,052
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable		$	15,963			$	9,553
Accrued liabilities			8,579				18,431
Current portion of long-term debt			440				698
Current portion of asset retirement and other obligations			2,220				1,687
Derivative liability short-term			3,574				88
Due to Related Parties			—				5
Total Current Liabilities			30,776				30,462
Long-Term Bank Debt			73,524				65,547
Asset Retirement Obligations			19,593				19,647
Derivative Liability Long-Term			—				10
Deferred Income Taxes			32,037				32,828
Other Long-Term Obligations			619				555
Total Liabilities			156,549				149,049
Commitments and Contingencies
Equity
Common stock, $.10 par value; 2019 and 2018: Authorized and Issued: 2,810,000 shares; outstanding 2019: 2,033,956 shares; 2018: 2,039,919 shares			281				281
Paid-in capital			7,612				7,388
Retained earnings			122,606				125,644
Treasury stock, at cost; 2019: 776,044 shares; 2018: 770,081 shares			(32,039	)			(31,304	)
Total Stockholders’ Equity – PrimeEnergy			98,460				102,009
Non-controlling interest			3,521				3,994
Total Equity			101,981				106,003
Total Liabilities and Equity		$	258,530			$	255,052

3

PRIMEENERGY RESOURCES CORPORATION

C ONDENSED C ONSOLIDATED S TATEMENTS OF O PERATIONS – Unaudited

Three Months Ended March 31, 2019 and 2018

(Thousands of dollars, except per share amounts)

		2019				2018
Revenues
Oil sales		$	18,798			$	20,101
Natural gas sales			2,235				2,363
Natural gas liquids sales			2,844				2,600
Realized gain (loss) on derivative instruments, net			78				(495	)
Field service income			4,733				4,215
Administrative overhead fees			1,424				1,504
Unrealized (loss) on derivative instruments, net			(5,752	)			(1,821	)
Other income			59				—
Total Revenues			24,419				28,467
Costs and Expenses
Lease operating expense			8,076				8,579
Field service expense			3,665				3,210
Depreciation, depletion, amortization and accretion on discounted liabilities			9,258				7,923
General and administrative expense			6,876				5,976
Total Costs and Expenses			27,875				25,688
Gain on Sale and Exchange of Assets			666				2,472
(Loss) Income from Operations			(2,790	)			5,251
Other Income (Expense)
Interest income			7				11
Interest expense			(975	)			(862	)
(Loss) Income Before (Benefit from) Provision for Income Taxes			(3,758	)			4,400
(Benefit from) Provision for Income Taxes			(727	)			1,099
Net (Loss) Income			(3,031	)			3,301
Less: Net Income Attributable to Non-Controlling Interests			7				15
Net (Loss) Income Attributable to PrimeEnergy		$	(3,038	)		$	3,286
Basic (Loss) Income Per Common Share		$	(1.49	)		$	1.53
Diluted (Loss) Income Per Common Share		$	(1.49	)		$	1.14

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

4

PRIMEENERGY RESOURCES CORPORATION

C ONDENSED C ONSOLIDATED S TATEMENT OF E QUITY – Unaudited

Three Months Ended March 31, 2019 and 2018

(Thousands of dollars)

		Common Stock								Additional Paid-In Capital				Retained Earnings				Treasury Stock				Total Stockholders’ Equity – PrimeEnergy				Non- Controlling Interest				Total Equity
		Shares				Amount
Balance at December 31, 2017			3,836,397			$	383			$	8,729			$	138,320			$	(52,123	)		$	95,309			$	7,130			$	102,439
Repurchase 67,218 shares of common stock			—				—				—				—				(3,379	)			(3,379	)			—				(3,379	)
Net income			—				—				—				3,286				—				3,286				15				3,301
Balance at March 31, 2018			3,836,397			$	383			$	8,729			$	141,606			$	(55,502	)		$	95,216			$	7,145			$	102,361
Balance at December 31, 2018			2,810,000			$	281			$	7,388			$	125,644			$	(31,304	)		$	102,009			$	3,994			$	106,003
Purchase 5,693 shares of common stock			—				—				—				—				(735	)			(735	)			—				(735	)
Net income			—				—				—				(3,038	)			—				(3,038	)			7				(3,031	)
Purchase of non-controlling interest			—				—				224				—				—				224				(480	)			(256	)
Balance at March 31, 2019			2,810,000				281				7,612				122,606				(32,039	)			98,460				3,521				101,981

5

PRIMEENERGY RESOURCES CORPORATION

C ONDENSED C ONSOLIDATED S TATEMENTS OF C ASH F LOWS – Unaudited

Three Months Ended March 31, 2019 and 2018

(Thousands of dollars)

		2019				2018
Cash Flows from Operating Activities:
Net (Loss) Income		$	(3,031	)		$	3,301
Adjustments to reconcile net (loss) income to net cash used in by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities			9,258				7,923
Gain on sale and exchange of assets			(666	)			(2,472	)
Unrealized loss on derivative instruments, net			5,752				1,821
(Benefit) Provision for deferred income taxes			( 727	)			905
Changes in assets and liabilities:
Accounts receivable			(6,907	)			4,343
Due from related parties			—				(14	)
Due to related parties			(5	)			166
Prepaids and other assets			(478	)			243
Accounts payable			6,410				(13,537	)
Accrued liabilities			(9,852	)			(4,264	)
Net (Used in) Operating Activities			(246	)			(1,585	)
Cash Flows from Investing Activities:
Capital expenditures, including exploration expense			(5,213	)			(10,734	)
Proceeds from sale of properties and equipment			668				1,816
Net Cash (Used in) Investing Activities			(4,545	)			(8,918	)
Cash Flows from Financing Activities:
Purchase of stock for treasury			(735	)			(3,379	)
Purchase of non-controlling interests			(256	)			—
Proceeds from long-term bank debt and other long-term obligations			8,000				27,300
Repayment of long-term bank debt and other long-term obligations			(282	)			(13,439	)
Net Cash Provided by Financing Activities			6,727				10,482
Net Increase (decrease) increase in Cash and Cash Equivalents			1,936				(21	)
Cash and Cash Equivalents at the Beginning of the Period			6,315				8,438
Cash and Cash Equivalents at the End of the Period		$	8,251			$	8,417
Supplemental Disclosures:
Income taxes paid		$	64			$	5
Interest paid		$	977			$	772

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

6

PRIMEENERGY RESOURCES CORPORATION

N OTES TO C ONDENSED C ONSOLIDATED F INANCIAL S TATEMENTS

March 31, 2019

(1) Basis of Presentation:

The accompanying condensed consolidated financial statements of PrimeEnergy Resources Corporation (“PrimeEnergy” or the “Company”) have not been audited by independent public accountants. Pursuant to applicable Securities and Exchange Commission (“SEC”) rules and regulations, the accompanying interim financial statements do not include all disclosures presented in annual financial statements and the reader should refer to the Company’s Form 10-K for the year ended December 31, 2018. In the opinion of management, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the Company’s condensed consolidated balance sheets as of March 31, 2019 and December 31, 2018, the condensed consolidated results of operations, cash flows and equity for the three months ended March 31, 2019 and 2018.

As of March 31, 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 Form 10-K for the fiscal year ended December 31, 2018, with the exception of Accounting Standards Update (ASU) 2016-02, “Leases (Topic 842)” discussed below. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the condensed consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.

Recently Adopted Accounting Pronouncements

Leases. In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, “Leases (Topic 842)” (“ASC 842”) which supersedes the lease recognition requirements in Accounting Standards Codification (“ASC”) 840, “Leases” (“ASC 840”), and requires lessees to recognize lease assets and lease liabilities for those leases previously classified as operating leases. The Company adopted ASC 842 as of January 1, 2019 using the modified retrospective transition method. The Company elected to apply the transition guidance under ASU 2018-11, “Leases (Topic 842) Targeted Improvements,” in which ASC 842 is applied at the adoption date, while the comparative periods continue to be reported in accordance with historic accounting under ASC 840. This standard does not apply to leases to explore for or use minerals, oil or gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.

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

As of March 31, 2019, the Company has operating lease assets and liabilities of $597 thousand on the consolidated balance sheet, in accordance with ASC 842. The adoption of ASC 842 did not have a material impact on the consolidated statements of operations and had no impact on cash flows. The Company did not record a change to its opening retained earnings as of January 1, 2019, as there was no material change to the timing or pattern of recognition of lease costs due to the adoption of ASC 842.

New Pronouncements Issued But Not Yet Adopted

In August 2018, the FASB issued ASU 2018-13, “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. ASU 2018-13 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.

7

In August 2018, the FASB issued ASU 2018-15, “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 obtain internal-use software. This pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued. The Company is currently evaluating the impact of adoption of this ASU on its consolidated financial statements and does not expect it to have a material impact.

( 2) Acquisitions and Dispositions:

Historically the Company has repurchased the interests of the partners and trust unit holders in the oil and gas limited partnerships (the “Partnerships”) and the asset and business income trusts (the “Trusts”) managed by the Company as general partner and as managing trustee, respectively. The Company had no such repurchases during the three months ended March 31, 2018. During the three months ending March 31, 2019 the Company purchased such interest totaling $256,000.

During the first quarter of 2019 and 2018, the Company sold or farmed out interests in certain non-core oil and natural gas properties and undeveloped acreage through a number of separate, individually negotiated transactions in exchange for cash or cash and a royalty or working interest in Texas, Oklahoma, Kansas and Colorado. Proceeds under these agreements were $0.7 million and $2.8 million, respectively.

During the first quarter of 2018, the Company completed two transactions acquiring 464 net mineral acres, 53 oil and gas wells with working interests ranging from 16.6% to 33.4% and one commercial salt-water disposal well operated by the Company, all located in Reagan County, Texas, for $6,080,000.

(3) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

(Thousands of dollars)		March 31, 2019				December 31, 2018
Accounts Receivable :
Joint interest billing		$	2,899			$	1,976
Trade receivables			2,258				1,979
Oil and gas sales			11,377				6,112
Tax refund receivable			4,760				4,760
Other			798				358
			22,092				15,185
Less: Allowance for doubtful accounts			(224	)			(224	)
Total		$	21,868			$	14,961
Accounts Payable:
Trade		$	8,682			$	1,174
Royalty and other owners			5,165				6,197
Partner advances			1,197				1,143
Prepaid drilling deposits			160				214
Other			759				825
Total		$	15,963			$	9,553
Accrued Liabilities:
Compensation and related expenses		$	3,345			$	2,907
Property costs			5,085				14,993
Other			149				531
Total		$	8,579			$	18,431

8

(4) Property and Equipment:

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

(Thousands of dollars)		March 31, 2019				December 31, 2018
Proved oil and gas properties, at cost		$	520,016			$	514,821
Less: Accumulated depletion and depreciation			(299,753	)			(291,152	)
Oil and Gas Properties, Net		$	220,263			$	223,669
Field and office equipment		$	27,406			$	27,252
Less: Accumulated depreciation			(20,872	)			(20,496	)
Field and Office Equipment, Net		$	6,534			$	6,756
Total Property and Equipment, Net		$	226,797			$	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.

At March 31, 2019, the Company had a total of $73.5 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 5.44% and $26.5 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 5.46% for the three months ended March 31, 2019 as compared to 5.25% for three months ended March 31, 2018. The Company’s borrowings under this credit facility approximates fair value because the interest rates are variable and reflective of market rates.

9

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 March 31, 2019, the Company had a total of $464 thousand 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 Company determined these loans are Level 3 liabilities in the fair-value hierarchy and estimated their fair value as $434 thousand and $2.097 million at March 31, 2019 and 2018, respectively, using a discounted cash flow model.

(6) Other Long-Term Obligations and Commitments:

Operating Leases:

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

Lease costs for the three months ended March 31, 2019 were $149 thousand. Cash paid for amounts included in lease costs for the three months ended March 31, 2019 were $138 thousand. The weighted-average remaining lease terms is 14 months and the weighted-average discount rate is 5.5%.

The payment schedule for the Company’s operating lease obligations as of March 31, 2019 is as follows:

(Thousands of dollars)		Operating Leases
2019		$	445
2020			155
2021			17
Total undiscounted lease payments		$	617
Less: Amount associated with discounting			(20	)
Net operating lease liabilities		$	597

10

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the three months ended March 31, 2019 is as follows:

(Thousands of dollars)		March 31, 2019
Asset retirement obligation at December 31, 2018		$	21,334
Liabilities incurred			—
Liabilities settled			(334	)
Accretion expense			280
Revisions in estimated liabilities			—
Asset retirement obligation at March 31, 2019		$	21,280

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 March 31, 2019 and 2018, remaining options held by two key executive officers on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.

(9) Related Party Transactions:

The Company, as managing general partner or managing trustee, makes an annual offer to repurchase the interests of the partners and trust unit holders in certain of the Partnerships or Trusts. The Company purchased interests totaling $256,000 for the three months ended March 31, 2019.

Payables owed to related parties primarily represent receipts collected by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors, for oil and gas sales net of expenses.

11

(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 March 31, 2019 and December 31, 2018:

March 31, 2019		Quoted Prices in Active Markets For Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Balance at March 31, 2019
(Thousands of dollars)
Assets
Commodity derivative contracts		$	—			$	—			$	—			$	118
Total assets			—			$	—			$	—			$	118
Liabilities
Commodity derivative contracts		$	—			$	—			$	—			$	(3,574	)
Total liabilities		$	—			$	—			$	—			$	(3,574	)
December 31, 2018		Quoted Prices in Active Markets For Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Balance at December 31, 2018
(Thousands of dollars)
Assets
Commodity derivative contracts		$	—			$	—			$	2,394			$	2,394
Total assets		$	—			$	—			$	2,394			$	2,394
Liabilities
Commodity derivative contract		$	—			$	—			$	(98	)		$	(98	)
Total liabilities		$	—			$	—			$	(98	)		$	(98	)

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

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

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2019.

(Thousands of dollars)
Net Asset– December 31, 2018		$	2,296
Total realized and unrealized (gains) losses:
Included in earnings (a)			(5,674	)
Purchases, sales, issuances and settlements			(78	)
Net Liabilities—March 31, 2019		$	(3,456	)

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.

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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 March 31, 2019 and December 31, 2018.

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

				Fair Value
(Thousands of dollars)		Balance Sheet Location		March 31, 2019				December 31, 2018
Asset Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Natural gas commodity contracts		Derivative asset short-term		$	2			$	63
Natural gas liquid contracts		Derivative asset short-term			69				138
Crude oil commodity contracts		Derivative asset short-term			—				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
Natural gas liquid contracts		Derivative asset long-term and other assets			47				—
Total				$	118			$	2,394
Liability Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts		Derivative liability short-term		$	(3,552	)		$	—
Natural gas commodity contracts		Derivative liability short-term			(22	)			(75	)
Natural gas liquid contracts		Derivative liability short-term			—				(13	)
Natural gas commodity contracts		Derivative liability long-term			—				(10	)
Total				$	(3,574	)		$	(98	)
Total derivative instruments				$	(3,456	)		$	2,296

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The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the three month period ended March 31, 2019 and 2018:

		Location of gain (loss) recognized in income		Amount of gain/loss recognized in income
(Thousands of dollars)				2019				2018
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts		Unrealized (loss) on derivative instruments, net		$	(5	)		$	(79	)
Crude oil commodity contracts		Unrealized (loss) on derivative instruments, net			(5,738	)			(1,868	)
Natural gas liquids contracts		Unrealized (loss) gain on derivative instruments, net			(9	)			126
Natural gas commodity contracts		Realized (loss) on derivative instruments, net			(12	)			(20	)
Crude oil commodity contracts		Realized gain (loss) on derivative instruments, net			88				(478	)
Natural gas liquids contracts		Realized gain on derivative instruments, net			2				2
				$	(5,674	)		$	(2,317	)

(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:

		Three Months Ended March 31,
		2019												2018
		Net Income (In 000’s)				Weighted Average Number of Shares Outstanding				Per Share Amount				Net Income (In 000’s)				Weighted Average Number of Shares Outstanding				Per Share Amount
Basic		$	(3,038	)			2,037,080			$	(1.49	)		$	3,286				2,142,396			$	1.53
Effect of dilutive securities:
Options (a)			—				—								—				751,326
Diluted		$	(3,038	)			2,037,080			$	(1.49	)		$	3,286				2,893,722			$	1.14

(a)	The effect of the 767,500 outstanding stock option is anti-dilutive for the three months ended March 31, 2019 due to net loss for the period.

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

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 and non-producing properties located primarily in Texas, Oklahoma and West Virginia. In addition, we own a substantial amount of well servicing equipment. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential.

We are the operator of the majority of our developed and undeveloped acreage which is nearly all held by production. In the Permian Basin of West Texas and eastern New Mexico the Company maintains an acreage position of approximately 20,400 gross (12,700 net) acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused. We believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional horizontal drilling that could support the drilling of as many as 250 additional horizontal wells. In Oklahoma we maintain an acreage position of approximately 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 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 161 new horizontal wells based on an estimate of four to ten wells per section, depending on the reservoir target area. Should we choose to participate with a working interest in future development, our share of these future capital expenditures would be approximately $82 million at an average 10% ownership level.

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

District Information:

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

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

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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 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 are in the Spraberry, 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 20,292 gross (12,824 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. At December 31, 2018, the Company was participating in three Probable Undeveloped horizontal drilling locations not included in the 2018 year-end reserve report. All three of these wells have been drilled and are expected to be completed and producing in the second quarter of 2019.

Mid-Continent Region

Our Mid-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 the Mid-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 the Mid-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. Our Mid-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 plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian, Woodford, and Hunton formations. As of March 31, 2019, the Mid-Continent region is participating in the drilling and completion of seven wells included as Proved Undeveloped in the 2018 year-end reserve report.

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 a per-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,

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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 March 31, 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 March 31, 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 our year-end reserves by our independent third-party engineers, Ryder Scott Company, L.P. The members of our district and central groups consist of degreed engineers and geologists with between approximately twenty and thirty-five years of industry experience, and over ten years of experience managing our reserves. Our Engineering Data manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over twenty-five years of experience, holds a Bachelor’s degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist.

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

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

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

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

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

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In 2018, the Company completed and put on production nine horizontal wells in West Texas and six horizontal wells in Oklahoma. Proved Developed reserves at year-end included an additional eight Shut-In horizontal wells in West Texas that have been brought on production in February, 2019 and five Shut-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 quarter of 2019.

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, 2018, are summarized as follows (in thousands of dollars):

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

The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV 10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. We use this measure when assessing the potential return on investment related to oil and gas properties. The PV 10 of future income taxes represents the sole reconciling item between this non-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 to non-controlling interests in the Partnerships. These interests represent less than 3% of our reserves.

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

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

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

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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 of non-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 2019, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2019 capital budget is reflective of current commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures.

RECENT ACTIVITIES

In 2018, the Company participated in a total of 28 gross (6.1 net) horizontal wells. Capital investment in this group of wells was approximately $41 million net to the Company. In 2018, nine horizontal wells, drilled in our West Texas horizontal development program, were completed and brought on production and six horizontal wells in our Scoop-Stack horizontal development program of Oklahoma were completed and producing by year-end. In addition, the Company had 13 new horizontal wells completed in 2018 that have been brought into production in the first quarter of 2019: eight are located in West Texas and five are located in Oklahoma.

In the first quarter of 2019, in our West Texas horizontal drilling program, the Company participated for 49.3% interest in eight wells that were brought on production in February. The total cost for drilling, completion and facilities for these eight wells will be approximately $48.2 million, with the Company’s share being approximately $23.8 million.

Also in our West Texas horizontal drilling program, in 2019, the Company is participating in two horizontal wells for 46% interest each, one targeting the Jo Mill and one the Lower Spraberry; and we are participating in a third horizontal well for 5.3% interest, targeting the Wolfcamp “A” reservoir. All three wells are in the clean out process after being recently fracture stimulated and are expected to be on-line in June of this year. These wells were designated as Probable Undeveloped as of December 31, 2018 and, therefore, were not included in the proved reserves of our year-end reserve report. PrimeEnergy’s share of the gross $26 million drilling and completion costs for these wells will be approximately $8.6 million. These three horizontals are important tests of the economic viability of each target reservoir not only for the 1,300 acre block in which they were drilled, where Prime holds between 5% and 48% working interest, but also for our nearby 2,600 leasehold acre block that we believe holds the same potential.

If favorable results are achieved from these three probable undeveloped wells described above, an additional 21 locations are likely to be drilled in the near future in this 1,300 acre block at a gross cost of approximately $182 million, with the Company’s share being approximately $60 million. In the nearby 2,600 acre block, Prime holds from 14% to 56% interest, and if favorable results do occur it is likely to spur the drilling of as many as 96 additional horizontal wells on this block 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.

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In the Permian Basin of West Texas, the Company maintains an acreage position of approximately 20,400 gross (12,700 net) acres, primarily in Reagan, Upton, Martin and Midland counties and we believe this acreage has significant resource potential in as many as 10 reservoirs, including benches of the Spraberry, Jo Mill, and Wolfcamp formations that support drilling potential for as many as 250 additional horizontal wells.

In Oklahoma, in 2018, the Company participated in 11 wells drilled and completed by December 31, 2018, however, six of these were designated as Shut-In at year-end. In March 2019, these six wells were brought into production. Also during 2018, the Company participated in the drilling of seven wells in Oklahoma that were designated as Proved Undeveloped at year-end, as these had not yet been completed. The Company has 10% interest in one of these seven wells and less than one percent interest in the remaining six. All seven of these wells are located in Grady County, Oklahoma and the estimated total expenditure is approximately $1.46 Million net to the Company’s interest. We anticipate these seven wells will be completed and put into production in the second quarter of 2019.

In Oklahoma, the Company’s horizontal activity is primarily focused in Canadian, Grady, Kingfisher, and Garvin counties where we have approximately 2,215 net leasehold acres. We believe this acreage has significant additional resource potential that could support the drilling of as many as 161 new horizontal wells based on an estimate of four to ten wells per section, depending on the reservoir target area. Should we choose to participate with a working interest in future development, our share of these future capital expenditures would be approximately $82 million at an average 10% ownership level; the Company will otherwise sell its rights for cash, or cash plus a royalty or working interest.

RESULTS OF OPERATIONS

2019 and 2018 Compared

We report a net loss of $3.04 million, $1.49 per share, for the three months ended March 2018 compared with net income of $3.29 million, $1.53 per share, for the same period of 2018. The current year net loss reflects an unrealized loss on derivatives, decreases in oil, gas and NGLs sales due to lower commodity prices and a decrease in gains related to the sale of acreage during the three months ended March 2019 compared to the same period in 2018. The significant components of income and expense are discussed below.

Oil, gas and NGLs sales decreased $1.2 million, or 4.7% from $25.1 million for the three months ended March 31, 2018 to $23.9 million for the three months ended March 31, 2019. Sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices decreased an average of, $9.43 per barrel, or 15% on crude oil, decreased an average of $0.25 per mcf, or 10% on natural gas and decreased an average of $5.98 per barrel, or 23% on NGLs, during the three months ended March 31, 2019 from the same period in 2018.

Our crude oil production increased by 33,000 barrels, or 10% from 323,000 barrels for the first quarter 2018 to 356,000 barrels for the first quarter 2019. Our natural gas production increased by 41,000 mcf, or 5% from 907,000 mcf for the first quarter 2018 to 948,000 mcf for the first quarter 2019. Our natural gas liquids production increased by 42,000 barrels, or 42% from 100,000 barrels for the first quarter 2018 to 142,000 barrels for the first quarter 2019. The net increase in production volumes reflect by production from new wells added in February and March 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 March 31, 2019 and 2018 (excluding realized gains and losses from derivatives).

						Three Months Ended March 31,
		2019				2018				Increase / (Decrease)				Increase / (Decrease)
Barrels of Oil Produced			356,000				323,000				33,000				10	%
Average Price Received		$	52.80			$	62.23			$	(9.43	)			(15	)
Oil Revenue (In 000’s)		$	18,798			$	20,101			$	(1,303	)			6	%
Mcf of Gas Sold			948,000				907,000				41,000				5	%
Average Price Received		$	2.36			$	2.61			$	(0.25	)			(10	)%
Gas Revenue (In 000’s)		$	2,235			$	2,363			$	(128	)			(5	)%
Barrels of Natural Gas Liquids Sold			142,000				100,000				42,000				42	%
Average Price Received		$	20.02			$	26.00			$	(5.98	)			(23	)%
Natural Gas Liquids Revenue (In 000’s)		$	2,844			$	2,600			$	244				9	%
Total Oil & Gas Revenue (In 000’s)		$	23,877			$	25,064			$	1,187				(5	)%

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Realized net losses on derivative instruments include net gains of $0.002 million and $0.089 million on the settlements of natural gas liquids and crude oil derivatives, and net losses on the settlements of natural gas derivatives, respectively for the first quarter 2019, and net losses of $0.02 million and $0.48 million on the settlements of natural gas and crude oil derivatives, and net gains on the settlements of natural gas liquids derivatives, respectively for the first quarter 2018.

We do not apply hedge accounting to any of our commodity-based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. Changes in market values in the first quarter of 2018 resulted in net unrealized losses of $0.08 million associated with natural gas fixed swap contracts and $1.87 million associated with crude oil fixed swaps and $0.13 million in net unrealized gains associated with natural gas liquids fixed swaps. Changes in market values in the first quarter of 2019 resulted in net unrealized losses of $5.738 million, $0.005 million and $0.009 million associated with crude oil fixed swaps, natural gas fixed swap contracts and natural gas liquids fixed swaps, respectively.

Prices received for the three months ended March 31, 2019 and 2018, respectively, including the impact of derivatives were:

		2019				2018
Oil Price		$	53.09			$	60.75
Gas Price		$	2.34			$	2.58
NGLS Price		$	20.07			$	25.98

Field service income increased $0.5 million or 12% for the first quarter 2019 to $4.7 million from $4.2 for the first quarter 2018. This increase is a combined result of increased utilization and rates charged to customers during the 2019 period. Workover rig services, hot oil treatments, salt water hauling and disposal represent the bulk of our field service operations.

Lease operating expense decreased $0.5 million or 20% from $8.58 million for the first quarter 2018 to $8.08 million for the first quarter 2019. This decrease is primarily due to the sales of high lifting cost properties during 2018 combined with lower production taxes related to lower commodity prices, offset by costs related to new wells brought on-line and general rate increases on vendor services during the first three months of 2019 as compared to the same period of 2018.

Field service expense increased $0.45 million or 14% to $3.67 million for the first quarter 2019 from $3.21 million for the first quarter 2018. Field service expenses primarily consist of salaries and vehicle operating expenses which have increased during the three months ended March 31, 2019 over the same period of 2018 as a direct result of increased services and utilization of the equipment.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $1.3 million or 16.8% from $7.92 million for the first quarter 2018 to $9.23 million for the first quarter 2019 reflecting the increased production related to new wells placed on production late in 2018 and the first quarter of 2019.

General and administrative expense increased $4.24 million, or 244% from $5.98 million for the three months ended March 31, 2018 to $6.88 million for the three months ended March 31, 2019. This increase in 2019 reflects the combination of a reduction in reimbursements related to the decrease in gains on sales of properties from 2018 to 2019, and increases in personnel costs.

Gain on sale and exchange of assets decreased $1.08 million from $2.47 million for the three months ended March 31, 2018 to $0.66 million for the three months ended March 31, 2019. These sales primarily consist of sales of non-essential oil and gas interests and field service equipment.

Interest expense increased $0.12 million or 42% from $0.86 million for the first quarter 2018 to $0.98 million for the first quarter 2018. This increase reflects the increase in current borrowings under our revolving credit agreement.

Income tax benefit and expense for the March 31, 2018 and 2019 quarters varied due to the change in net income for those periods.

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LIQUIDITY AND CAPITAL RESOURCES

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

Net cash used in our operating activities for the three months ended March 31, 2019 was $0.25 million compared to $1.59 million for the three months ended March 31, 2018. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.

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

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

The Company maintains Equipment Financing term loans with JPMorgan Chase with a current outstanding balance of $369 thousand as of May 14, 2019. We intend to pay off the balance of these loans by June 1, 2019.

We currently maintain a credit facility totaling $300 million, with a borrowing base of $100 million. As of May 14, 2019 the Company has $71.5 million in outstanding borrowings and $28.5 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 June 2019. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the redetermined borrowing base.

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 and natural gas.

		2019				2020				2019				2020
Natural Gas (MMBTU)			360,000				180,000			$	2.72			$	2.95
Natural Gas Liquids (barrels)			45,000				—			$	21.66				—
Oil (barrels)			404,000				225,500			$	53.00			$	58.43

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2019, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2019 capital budget is reflective of decreased commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures. We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit facility should our borrowing base become limited due to the deterioration of commodity prices.

We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2019. As of May 14, 2019, we have spent $2.085 million under these programs during 2019.

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Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Item 4.

CONTROLS AND PROCEDURES

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

There were no changes in the Company’s internal control over financial reporting that occurred during the first three months of 2017 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS

None.

Item 1A.

RISK FACTORS

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

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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

During the three months ended March 31, 2019, the Company purchased the following shares of common stock as treasury shares.

2019 Month		Number of Shares				Average Price Paid per share				Maximum Number of Shares that May Yet Be Purchased Under The Program at Month - End (1)
January			1,386			$	80.50				192,077
February			2,716			$	122.36				189,361
March			1,861			$	156.23				187,500
Total/Average			5,963			$	123.20

(1)

In December 1993, we announced that the Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of the common stock from time-to-time, in open market transactions or negotiated sales. On October 31, 2012 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 March 31, 2019, a total of 3,512,500 shares have been repurchased under this program for $69,471,064 at an average price of $19.78 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

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Item 4.

RESERVED

Item 5.

OTHER INFORMATION

None

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Item 6.

EXHIBITS

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

Exhibit No.
3.1		Certificate of Incorporation of PrimeEnergy Resources Corporation, as amended and restated of December  21, 2018, (filed as Exhibit 3.1 of PrimeEnergy Resources Corporation Form 8-K on December 27, 2018, and incorporated herein by reference).
3.2		Bylaws of PrimeEnergy Resources Corporation as amended and restated as of May  20, 2015 (filed as Exhibit 3.2 of PrimeEnergy Resources Corporation Form 8-K on May 21, 2015 and incorporated herein by reference).
10.18		Composite copy of Non-Statutory Option Agreements (Incorporated by reference to Exhibit  10.18 of PrimeEnergy Resources Corporation Form 10-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 Form 10-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 Form 10-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 Form 10-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 Form 10-K for the year ended December 31, 2018).
10.22.5.11		Amended, Restated and Consolidated Guaranty dated as of February  15, 2017, among PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, EOWS Midland Company and Prime Offshore L.L.C. in favor of Compass Bank, as Administrative Agent for the Lenders (Incorporated by reference to Exhibit 10.22.5.11 to PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2016).
10.22.5.12		Amended, Restated and Consolidated Pledge and Security Agreement dated as of February  15, 2017, among PrimeEnergy Resources Corporation, PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, EOWS Midland Company and Prime Offshore L.L.C. and Compass Bank, as Administrative Agent for the Secured Parties (Incorporated by reference to Exhibit 10.22.5.12 to PrimeEnergy Resources Corporation Form 10-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 Form 10-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 Form 10-Q for the quarter ended March 31, 2017).
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 Form 10-Q for the quarter ended March 31, 2017).

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Exhibit No.
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 Resources 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 Resources Corporation Form 10-Q for the quarter ended September 30, 2013).
10.23.3		Guaranty dated July  31, 2013, made by PrimeEnergy Resources Corporation in favor of JP Morgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.23.3 to PrimeEnergy Resources Corporation Form  10-Q for the quarter ended September 30, 2013).
10.23.4		Agreement of Equipment Substitution dated January  15, 2014, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.23.4 to PrimeEnergy Resources 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 Resources 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 Resources Corporation Form 10-Q for the quarter ended September 30, 2014).
10.24.3		Guaranty dated July 29, 2014, made by PrimeEnergy Resources Corporation in favor of JP  Morgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.24.3 to PrimeEnergy Resources Corporation Form 10-Q for the quarter ended September 30, 2014).
31.1		Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).
31.2		Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
101.INS		XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith)
101.SCH		XBRL Taxonomy Extension Schema Document (filed herewith)
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith)
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document (filed herewith)
101.LAB		XBRL Taxonomy Extension Label Linkbase Document (filed herewith)
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith)

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SIGNATURES

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

						PrimeEnergy Resources Corporation
						(Registrant)
May 20, 2019						/s/ Charles E. Drimal, Jr.
(Date)						Charles E. Drimal, Jr.
						President
						Principal Executive Officer
May 20, 2019						/s/ Beverly A. Cummings
(Date)						Beverly A. Cummings
						Executive Vice President
						Principal Financial Officer

27