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10-Q 1 d37897d10q.htm 10-Q 10-Q

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 June 30, 2020

☐	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.

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 August 19, 2020 was: Common Stock, $0.10 par value 1,994,177 shares.

PrimeEnergy Resources Corporation

Index to Form 10-Q

June 30, 2020


	Page
Part I—Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets –June 30, 2020 and December 31, 2019		3
Condensed Consolidated Statements of Operations– For the three and six months ended June 30, 2020 and 2019		4
Condensed Consolidated Statement of Equity – For the six months ended June 30, 2020 and 2019		5
Condensed Consolidated Statements of Cash Flows – For the six months ended June 30, 2020 and 2019		6
Notes to Condensed Consolidated Financial Statements – June 30, 2020		7-13
Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation		14-24
Item 3. Quantitative and Qualitative Disclosures About Market Risk		24
Item 4. Controls and Procedures		24
Part II—Other Information
Item 1. Legal Proceedings		25
Item 1A. Risk Factors		25
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		25
Item 3. Defaults Upon Senior Securities		25
Item 4. Reserved		25
Item 5. Other Information		25
Item 6. Exhibits		26-27
Signatures		28

PART I—FINANCIAL INFORMATION

Item 1.

FINANCIAL STATEMENTS

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – Unaudited

(Thousands of dollars)


	June 30, 2020			December 31, 2019
ASSETS
Current Assets
Cash and cash equivalents	$	4,500		$	1,015
Accounts receivable, net		9,017			14,360
Prepaid obligations		686			625
Derivative asset short-term		649			272
Other current assets		489			127

Total Current Assets		15,341			16,399
Property and Equipment, at cost
Oil and gas properties (successful efforts method), net		196,848			205,320
Field and office equipment, net		6,607			6,780

Total Property and Equipment, Net		203,455			212,100

Other assets		134			866

Total Assets	$	218,930		$	229,365

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	8,760		$	6,634
Accrued liabilities		3,940			6,836
Current portion of long-term debt		53,500			—
Current portion of asset retirement and other long-term obligations		1,685			1,369
Derivative liability short-term		141			753

Total Current Liabilities		68,026			15,592
Long-Term Bank Debt		1,243			53,500
Asset Retirement Obligations		19,778			20,330
Derivative Liability Long-Term		48
Deferred Income Taxes		33,609			35,924
Other Long-Term Obligations		562			656

Total Liabilities		123,266			126,002
Commitments and Contingencies
Equity
Common stock, $.10 par value; 2020 and 2019: Authorized and Issued: 2,810,000 shares; outstanding 2020: 1,994,177 shares; 2019: 1,998,978 shares		281			281
Paid-in capital		7,505			7,505
Retained earnings		122,684			129,120
Treasury stock, at cost; 2020: 815,823 shares; 2019: 811,022 shares		(37,501	)		(36,792	)

Total Stockholders’ Equity – PrimeEnergy Resources		92,969			100,114
Non-controlling interest		2,695			3,249

Total Equity		95,664			103,363

Total Liabilities and Equity	$	218,930		$	229,365

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

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – Unaudited

Three and six months ended June 30, 2020 and 2019

(Thousands of dollars, except per share amounts)


	Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019
Revenues
Oil sales	$	3,613		$	19,644		$	14,324		$	38,442
Natural gas sales		543			1,355			1,389			3,590
Natural gas liquids sales		495			2,375			1,738			5,219
Realized loss on derivative instruments, net		4,757			(851	)		5,954			(773	)
Field service income		2,381			4,757			6,681			9,490
Administrative overhead fees		968			1,388			2,194			2,812
Unrealized gain (loss) on derivative instruments, net		(5,615	)		2,862			941			(2,890	)
Other income		136			4			165			63

Total Revenues		7,278			31,534			33,386			55,953
Costs and Expenses
Lease operating expense		6,230			8,149			12,574			16,225
Field service expense		1,925			3,979			5,474			7,644
Depreciation, depletion, amortization and accretion on discounted liabilities		6,900			9,292			15,093			18,550
General and administrative expense		2,570			2,895			10,306			9,771

Total Costs and Expenses		17,625			24,315			43,447			52,190
Gain on Sale and Exchange of Assets		82			1,023			194			1,689

Income from Operations		(10,265	)		8,242			(9,867	)		5,452
Other Income (Expense)
Interest Income		—			3			—			10
Interest (Expense)		(500	)		(1,013	)		(1,159	)		(1,988	)

Income (Loss) Before Income Taxes		(10,765	)		7,232			(11,026	)		3,474
Income Taxes Expense (Benefit)		(3,979	)		1,410			(4,036	)		683

Net Income (Loss)		(6,786	)		5,822			(6,990	)		2,791
Less: Net Income (Loss) Attributable to Non-Controlling Interests		(520	)		47			(554	)		54

Net Income (Loss) Attributable to PrimeEnergy		(6,266	)	$	5,775		$	(6,436	)		2,737

Basic Income (Loss) Per Common Share	$	(3.14	)	$	2.85		$	(3.23	)	$	1.35

Diluted Income (Loss) Per Common Share	$	(3.14	)	$	2.07		$	(3.23	)	$	0.98

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

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF EQUITY – Unaudited

Six months ended Ended June 30, 2020 and 2019

(Thousands of dollars)


	Common Stock				Additional Paid-In Capital		Retained Earnings			Treasury Stock			Total Stockholders’ Equity – PrimeEnergy			Non- Controlling Interest			Total Equity
	Shares		Amount		Additional Paid-In Capital		Retained Earnings			Treasury Stock			Total Stockholders’ Equity – PrimeEnergy			Non- Controlling Interest			Total Equity
Balance at December 31, 2019		2,810,000	$	281	$	7,505	$	129,120		$	(36,792	)	$	100,114		$	3,249		$	103,363
Purchase 4,801 shares of common stock		—		—		—		—			(709	)		(709	)		—			(709	)
Net Income		—		—		—		(6,436	)		—			(6,436	)		(554	)		(6,990	)

Balance at June 30, 2020		2,810,000	$	281	$	7,505	$	122,684		$	(37,501	)	$	92,969		$	2,695		$	95,664

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

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

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited

Six Months Ended June 30, 2020 and 2019

(Thousands of dollars)


	2020			2019
Cash Flows from Operating Activities:
Net Income (loss)	$	(6,990	)	$	2,791
Adjustments to reconcile net Income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities		15,093			18,550
Gain on sale and exchange of assets		(194	)		(1,689	)
Unrealized (gain) loss on derivative instruments, net		(941	)		2,890
Deferred income taxes		(2,315	)		706
Changes in assets and liabilities:
Accounts receivable		5,343			(1,887	)
Due to related parties		—			(5	)
Prepaids and other assets		(423	)		160
Accounts payable		2,126			3,887
Accrued liabilities		(2,896	)		(11,664	)

Net Cash Provided by Operating Activities		8,803			13,739

Cash Flows from Investing Activities:
Capital expenditures, including exploration expense		(6,046	)		(11,412	)
Proceeds from sale of properties and equipment		194			1,693

Net Cash (Used in) Investing Activities		(5,852	)		(9,719	)

Cash Flows from Financing Activities:
Purchase of stock for treasury		(709	)		(3,012	)
Purchase of non-controlling interests		—			(256	)
Proceeds from long-term bank debt and other long-term obligations		6,243			13,000
Repayment of long-term bank debt and other long-term obligations		(5,000	)		(17,246	)

Net Cash Provided by (Used in) Financing Activities		534			(7,514	)

Net Increase (decrease) in Cash and Cash Equivalents		3,485			(3,494	)
Cash and Cash Equivalents at the Beginning of the Period		1,015			6,315

Cash and Cash Equivalents at the End of the Period	$	4,500		$	2,821

Supplemental Disclosures:
Income taxes paid	$	—		$	130
Interest paid	$	1,182		$	2,015

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

PRIMEENERGY RESOURCES CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2020

(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, 2019. 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 June 30, 2020 and December 31, 2019, the condensed consolidated results of operations, cash flows and equity for the six months ended June 30, 2020 and 2019.

As of June 30, 2020, 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, 2019. 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.

(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. During the six months ending June 30, 2019 the Company purchased such interest totaling $256,000. The Company had no such repurchases during the six months ended June 30, 2020.

Subsequent to June 30, 2020 the Company entered into an agreement to sell the Company’s marginal properties in West Virginia effective August 1, 2020 for $200,000 and retaining an overriding royalty on approximately 31,000 undeveloped acres. The Company also entered an agreement to sell approximately 2,000 acres in West Texas in a transaction expected to close during August 2020 for approximately $10 million.

(3) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:


(Thousands of dollars)	June 30, 2020			December 31, 2019
Accounts Receivable:
Joint interest billing	$	1,306		$	3,339
Trade receivables		555			2,246
Oil and gas sales		3,141			7,284
Tax refund receivable		3,440			1,720
Other		993			189

		9,435			14,778
Less: Allowance for doubtful accounts		(418	)		(418	)

Total	$	9,017		$	14,360

Accounts Payable:
Trade	$	2,923		$	261
Royalty and other owners		3,889			4,227
Partner advances		853			1,024
Other		1,095			1,122

Total	$	8,760		$	6,634

Accrued Liabilities:
Compensation and related expenses	$	2,609		$	3,620
Property costs		1,331			2,829
Other		—			387

Total	$	3,940		$	6,836

(4) Property and Equipment:

Property and equipment at June 30, 2020 and December 31, 2019 consisted of the following:


(Thousands of dollars)	June 30, 2020			December 31, 2019
Proved oil and gas properties, at cost	$	533,097		$	527,729
Less: Accumulated depletion and depreciation		(336,249	)		(322,409	)

Oil and Gas Properties, Net	$	196,848		$	205,320

Field and office equipment	$	28,120		$	27,542
Less: Accumulated depreciation		(21,513	)		(20,762	)

Field and Office Equipment, Net	$	6,607		$	6,780

Total Property and Equipment, Net	$	203,455		$	212,100

(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 Company’s 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. Pursuant to borrowing base redeterminations on June 26, 2019 and December 18, 2019, the borrowing base was set at $90, million and $72, million respectively.

At June 30, 2020, the Company had a total of $53.5 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.23 % and $18.5 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 4.22% for the six months ended June 30, 2020 as compared to 5.53% for six months ended June 30, 2019. The Company’s borrowings under this credit facility approximates fair value because the interest rates are variable and reflective of market rates.

Paycheck Protection Program Loans

forgiveness (if any) under the CARES Act, which can be up to 10 months after the end of the related notes covered period (which is defined as 24 weeks after the date of the loan) (the “Deferral Period”). The note may be prepaid at any time prior to maturity with no prepayment penalties. Funds from the PPP Loans may be used only for payroll and related costs, costs used to continue group health care benefits, mortgage payments, rent, utilities, and interest on other debt obligations that were incurred prior to February 15, 2020 (the “Qualifying Expenses”). Under the terms of the PPP Loans, certain amounts thereunder may be forgiven if they are used for Qualifying Expenses as described in and in compliance with the CARES Act. While the Company intends to use the PPP Loan proceeds exclusively for Qualifying Expenses, it is unclear and uncertain whether the conditions for forgiveness of the PPP Loans will be met under the current guidelines of the CARES Act. Accordingly, we cannot make any assurance that the Company will be eligible for forgiveness of the PPP Loans, in whole or in part. To the extent, if any, that any or all of the PPP loans are not forgiven, beginning one month following expiration of the Deferral Period, and continuing monthly until 24 months from the date of each applicable Note (the “Maturity Date”), the Company is obligated to make monthly payments of principal and interest to the Lender with respect to any unforgiven portion of the Note, in such equal amounts required to fully amortize the principal amount outstanding on such Note as of the last day of the applicable Deferral Period by the applicable Maturity Date. The Company accounts for these loans as financial liabilities.

(6) Other Long-Term Obligations and Commitments:

Operating Leases:

The Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Leases assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. A new finance lease for office equipment is included in property and equipment, other current liabilities and other long-term liabilities this quarter. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The weighted average discount rate used was 5.5%. Certain leases may contain variable costs above the minimum required payments and are not included in 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.

Operating lease costs for the six months ended June 30, 2020 were $290 thousand. Cash payments included in the operating lease cost for six months ended June 30, 2020 were $307 thousand. The weighted-average remaining operating lease terms is 7 months. The amortization and interest expense for financing lease amounted to $3,632 and the cash payment for the lease was $3,828 and the lease term remaining was for 10 months.

The Company amended certain leases for office space in Texas and Oklahoma providing for payments of $461 thousand and $89 thousand in 2020 and 2021, respectively.

Rent expense for office space for the six months ended June 30, 2020 and 2019 was $331,000 and $315,000, respectively.

The payment schedule for the Company’s operating and financing lease obligations as of June 30, 2020 is as follows:


(Thousands of dollars)	Operating Leases			Financing Leases
2021	$	106		$	2
2020		309			4

Total undiscounted lease payments	$	415		$	6
Less: Amount associated with discounting		(35	)		(1	)

Net operating lease liabilities	$	380		$	5

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the six months ended June 30, 2020 is as follows:


(Thousands of dollars)	June 30, 2020
Asset retirement obligation at December 31, 2019	$	21,118
Liabilities settled		(1,053	)
Accretion expense		502

Asset retirement obligation at June 30, 2020	$	20,567

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, 2020 and 2019, 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 six months ended June 30, 2019. The Company had no such repurchases during the six months ended June 30, 2020.

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 June 30, 2020 and December 31, 2019:


June 30, 2020	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, 2020
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	649		$	649

Total assets		—	$	—	$	649		$	649

Liabilities
Commodity derivative contracts	$	—	$	—	$	(189	)	$	(189	)

Total liabilities	$	—	$	—	$	(189	)	$	(189	)


December 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 December 31, 2019
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	272		$	272

Total assets	$	—	$	—	$	272		$	272

Liabilities
Commodity derivative contract	$	—	$	—	$	(753	)	$	(753	)

Total liabilities	$	—	$	—	$	(753	)	$	(753	)

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 period ended June 30, 2020.


(Thousands of dollars)
Net Liability– December 31, 2019	$	(481	)
Total realized and unrealized (gains) losses:
Included in earnings (a)		6,895
Purchases, sales, issuances and settlements		(5,954	)

Net Asset June 30, 2020	$	460

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, 2020 and December 31, 2019.

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at June 30, 2020 and December 31, 2019:


		Fair Value
(Thousands of dollars)	Balance Sheet Location	June 30, 2020			December 31, 2019
Asset Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Natural gas commodity contracts	Derivative asset short-term	$	334		$	146
Crude oil commodity contracts	Derivative asset short-term		315			126

Total		$	649		$	272

Liability Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts	Derivative liability short-term	$	(69	)	$	(715	)
Natural gas commodity contracts	Derivative liability short-term		(72	)		(38	)
Natural gas commodity contracts	Derivative liability long-term		(48	)

Total		$	(189	)	$	(753	)

Total derivative instruments		$	460		$	(481	)

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the six-months ended June 30, 2020 and 2019:


	Location of gain (loss) recognized in income	Amount of gain/loss recognized in income
(Thousands of dollars)	Location of gain (loss) recognized in income	2020		2019
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized gain (loss) on derivative instruments, net	$	87	$	151
Crude oil commodity contracts	Unrealized gain (loss) on derivative instruments, net		854		(3,101	)
Natural gas liquids contracts	Unrealized (loss) on derivative instruments, net		—		60
Natural gas commodity contracts	Realized gain (loss) on derivative instruments, net		409		(8	)
Crude oil commodity contracts	Realized gain on derivative instruments, net		5,545		(876	)
Natural gas liquids contracts	Realized gain on derivative instruments, net		—		111

		$	6,895	$	(3,663	)

(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:


	Six Months Ended June 30,
	2020								2019
	Net Loss (In 000’s)			Weighted Average Number of Shares Outstanding		Per Share Amount			Net Loss (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	(6,436	)		1,994,675	$	(3.23	)	$	2,737		2,031,569	$	1.35
Effect of dilutive securities:
Options (a)		—			—					—		761,169

Diluted	$	(6,436	)		1,994,675	$	(3.23	)	$	2,737		2,792,738	$	0.98


	Three Months Ended June 30,
	2020								2019
	Net Loss (In 000’s)			Weighted Average Number of Shares Outstanding		Per Share Amount			Net Loss (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	(6,266	)		1,994,177	$	(3.14	)	$	5,775		2,026,119	$	2.85
Effect of dilutive securities:
Options (a)		—			—					—		761,583

Diluted	$	(6,266	)		1,994,177	$	(3.14	)	$	5,775		2,787,702	$	2.07

(a)	The effect of the 767,500 outstanding stock option is anti-dilutive for the six and three months ended June 30, 2020, due to net loss for the period.

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 attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. 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 to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient basis.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.

On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency due to the COVID-19 outbreak, which originated in Wuhan, China, and the risks to the international community as the virus spreads globally beyond its point of origin. In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally. In addition, in March 2020, members of OPEC failed to agree on production levels which has caused an increased supply and has led to a substantial decrease in oil prices and an increasingly volatile market. The oil price war ended with a deal to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. There has been an increase in supply which has pushed prices down further since March. If the depressed pricing continues for an extended period it will lead to i) further reductions in the borrowing base under our credit facility which would require us to make additional borrowing base deficiency payments, ii) reductions in reserves, and iii) additional impairment of proved and unproved oil and gas properties. We also expect disclosures of supplemental oil and gas information to be impacted by price declines.

In response to recent commodity prices our efforts to reduce costs include reducing operating costs and electing to shut-in marginal wells. The Company reviewed field operations to minimize costs and identify wells for short term shut-ins. The Company has also implemented a reduction in workforce to further reduce general and administrative costs. The full impact of the COVID-19 outbreak and the decline in oil prices continues to evolve as of the date of this report. As such, it is uncertain as to the full magnitude that these events will have on the Company’s financial condition, liquidity, and future results of operations.

Management is actively monitoring the global situation on its financial condition, liquidity, operations, suppliers, industry, and workforce. Given the daily evolution of the COVID-19 outbreak and the global responses to curb its spread, the Company is not able to estimate the effects of the COVID-19 outbreak on its results of operations, financial condition, or liquidity for fiscal year 2020. These matters may have a continued material adverse impact on economic and market conditions and trigger a period of global economic slowdown, which may impair the Company’s asset values, including reserve estimates. Further, consumer demand has decreased since the spread of the outbreak and new travel restrictions placed by governments in an effort to curtail the spread of the coronavirus. Although the Company cannot estimate the length or gravity of the impacts of these events at this time, if the pandemic and/or decreased oil prices continue, they may have a material adverse effect on the Company’s results of future operations, financial position, and liquidity in fiscal year 2020.

Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. In addition, our realized prices are further impacted by our derivative and hedging activities.

We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we

may receive for our oil, natural gas and NGLs. The price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to failed Organization of Petroleum Exporting Countries (“OPEC”) negotiations as well as concerns about the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas. The resulting precipitous decline in oil and gas pricing experienced during March 2020, through the date of this report, if prolonged. or a further deterioration of the market price for oil and natural gas, will negatively impact our cash flows.

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 3,460 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 52 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 $40 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, 2019.


	Appalachian		Gulf Coast		Mid- Continent		West Texas		Other		Total
Proved Reserves as of December 31, 2019 (MBoe)
Developed		296		726		2,013		7,582		11		10,628
Undeveloped		—		—		81		3,526		—		3,607
Total		296		726		2,094		11,108		11		14,235
Average Daily Production (Boe per day)		240		348		840		3703		4		5,133
Gross Productive Wells (Working Interest and ORRI Wells)		528		263		567		561		105		2,024
Gross Productive Wells (Working Interest Only)		481		233		418		522		45		1,699
Net Productive Wells (Working Interest Only)		451		143		216		257		4		1,071
Gross Operated Productive Wells		438		125		144		298		—		1,005
Gross Operated Water Disposal, Injection and Supply wells		1		7		44		7		—		59

In several of our producing regions we have 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.

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, 2019, we had interest in 481 wells (451 net), of which 438 wells are operated. Multiple producing intervals here 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 2019 was 240 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, 2019, we had 296 MBoe of proved developed reserves (substantially all natural gas) in the Appalachian region, constituting 2.1% of our total proved reserves. We maintain an acreage position of approximately 35,790 gross (35,350 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, 2020, 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. Effective August 1, 2020 the Company sold our Appalachian properties for $200,000 and retained an overriding royalty on approximately 31,000 undeveloped acres.

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 233 producing wells (143 net) in the Gulf Coast region as of December 31, 2019, of which 125 wells are operated by us. Average net daily production in 2019 was 348 Boe. At December 31, 2019, we had 726 MBoe of proved reserves in the Gulf Coast region, which represented 5.1% 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, 2020, 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.

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, 2019, we had 418 wells (216 net) in the Mid-Continent area, of which 144 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 2019 was 840 Boe. At December 31, 2019, we had 2,094 MBoe of proved reserves in the Mid-Continent area, or 14.7% of our total proved reserves. We maintain an acreage position of approximately 55,880 gross (10,690 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, 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, and Woodford formations. As of March 31, 2020, in the Mid-Continent region, the Company was is participating in the drilling and/or completion of four wells, with overriding royalty only in eight additional wells, all included as Proved Undeveloped in the 2019 year-end reserve report.

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 five intervals; 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, 2019, we had 522 wells (257 net) in the West Texas area, of which 298 wells are operated by us. Principal producing intervals are in the Spraberry, Wolfcamp, and San Andres formations at depths ranging from 4,200 to 12,500 feet. Average net daily production in 2019 was 3,703 Boe. At December 31, 2019, we had 11,108 MBoe of proved reserves in the West Texas area, or 78% of our total proved reserves. We maintain an acreage position of approximately 19,910 gross (12,560 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing nine workover rigs, four hot oiler trucks, one kill truck and two roustabout trucks. 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, 2019, the Company had committed to participate in the drilling of ten Proved Undeveloped horizontal drilling locations. Seven of the nine wells were drilled by April 15, 2020, but are not expected to be completed and producing until the fourth quarter of 2020.

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, 2019. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates. 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 between eight and twenty-five 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 degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist. See Part II, Item 8 “Financial Statements and Supplementary Data”, for additional discussions regarding proved reserves and their related cash flows.

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)
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
2019		4,381		2,914		19,995		10,268		1,833		1,017		4,547		3,608		6,214		3,931		24,542		14,235

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

In 2018, the Company drilled and completed seventeen horizontal wells in West Texas and eleven horizontal wells in Oklahoma. In addition, the Company added reserves through overriding royalty interest in 16 wells, primarily in Oklahoma and Texas. At year-end 2018, thirteen of the seventeen wells completed in 2018 were designated as Shut-In: eight in our West Texas horizontal development program, which were brought on production in February, 2019, and five in our Oklahoma Scoop-Stack development program, which were brought on production in March, 2019.

At December 31, 2018, our reserve report included 43 MBoe of proved undeveloped reserves attributable to eight horizontal wells that had been drilled but had not yet been completed: three of these were completed in 2019, converting 24 Mboe of undeveloped reserves to proved developed, and five remained uncompleted as of December 31, 2019, which account for 18 Mboe of the 43 Mboe. The Company has 9% ownership in one of these five wells and less than 1% in four wells.

In 2019, in West Texas, in addition to the eight wells classified as Shut-in at year-end 2018 that were brought on production in February, we participated in the drilling and completion of three wells on our Kashmir tract: two wells with an average 49% interest, and a third well for 5.3% interest. One of each of these wells was completed in the Wolfcamp “A”, Jo Mill, and Lower Spraberry. All three wells were brought on production in May of 2019.

In our Oklahoma, Scoop-Stack play, in 2019, we participated in the drilling and completion of six wells on our WM Wallace tract for 7.67% interest, and nine wells, included on Slash, Osborn, and Leon tracts, with an average 1.34% interest. In addition, three wells drilled in Oklahoma in 2018, designated as proved undeveloped at year-end 2018, were completed in 2019 converting 24 Mboe of reserves to proved developed. Also in Oklahoma, six wells designated as Shut-in on December 31, 2018, were brought into production in 2019: five located on our Ruthie tract, and one on our Braum tract. In the Gulf Coast region, we added production through the recompletion of three vertical wells in Polk County, Texas: one operated by the Company in which we have 72.5% interest, and two operated by Unit Petroleum in which the Company owns 2.81% working interest and 3.77% net revenue interest.

At December 31, 2019, the Company had 3,607 Mboe of undeveloped reserves attributable to 22 wells operated by others that are anticipated to be drilled and completed primarily in 2020: ten of these are located in our West Texas horizontal development program and account for 3,526 Mboe of the total, and 12 wells are located in our Oklahoma Scoop-Stack horizontal program and account for 81 Mboe of the total. Nine of the ten wells in West Texas are located on our 1,300 acre Kashmir tract in Upton County, operated by Apache Corporation and, as of April 15, 2020, six of these have been drilled and are awaiting completion, which is expected to occur in the fourth quarter of 2020. Our average 47.76% share of the cost of these six horizontal wells will be approximately $19.4 million. Drilling of the remaining three wells will likely occur in 2021.

In the first half of 2020, the Company participated in a horizontal well for 8.36% interest operated by Pioneer Natural Resources completed and brought into production in July 2020. Our total net expenditure for this well will be approximately $630,000. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.

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, 2019, 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
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
2019	$	116,592	$	82,155	$	42,700	$	17,876	$	159,292	$	100,031	$	18,419	$	81,612

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 PV10 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 PV10 of future income taxes represents the sole reconciling item between this non-GAAP PV10 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 relatively major expenditure is required for recompletion. Our reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% 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 be reasonably 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.

RECENT ACTIVITIES

Since the start of our West Texas horizontal drilling program in 2015 and through the second quarter of 2020 the Company has participated in 74 horizontal wells in the Permian Basin, seven of which were drilled in the first half of 2020. Through July 2020, the Company has invested approximately $111 MM in our West Texas horizontal drilling program. Of the 74 total horizontal wells participated in, we have an average of 24% working interest. In 2019, 11 wells were brought on production: the Company has 49% interest in eight of these wells, all one-mile in length, located on our CC-33 tract, and an average 48% interest in two horizontals and 5.3% interest in one additional horizontal, that are each two-miles in length, located on the Kashmir tract. The Company invested approximately $31.5 million in these 11 wells brought on production in 2019. Through the second quarter of 2020, the Company participated in seven new horizontal wells, all located in Upton County, Texas. Six of these are operated by Apache Corporation and one is operated by Pioneer Natural Resources. The Pioneer well was completed in late June and came on production in early July 2020. The six Apache operated wells are anticipated to be completed in the fourth quarter of 2020.

In Upton County, West Texas, we are developing a contiguous 3,260-acre block with our joint venture partner, Apache Corporation. In this block the Company has 2,600 leasehold acres with interest between 14% and 56%, depending on the particular lease and depth being developed. In 2018, in this block, eight wells drilled horizontally in the Wolfcamp “B”, were participated in for 49% interest. This is believed to be full development of the Wolfcamp “B” reservoir for this lease block. Apache will likely now set its sights on development of the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs for this block, following the recent successful testing in 2019 of these reservoirs on our offset 1,300-acre lease block. Given the favorable results achieved by the initial three wells on the offset block, it is expected that as many as 54 additional horizontals will be slated for development on the 3,260-acre block in the near future. The cost of such development would be approximately $370.6 million with the Company’s share being approximately $170.8 million. In addition, there is a fourth target reservoir, the Middle Spraberry, that is also prospective for development. The potential of the Middle Spraberry, on the 3,280-acre block, is for 18 horizontal wells to be drilled, with the Company likely participating for approximately $61.8 million. The actual number of wells that are eventually drilled as well as the cost and the timing of drilling will vary based upon many factors, including commodity market conditions.

In addition to the 3,260 acreage block under development, the Company is also developing an offsetting 1,300-acre block in Upton County, Texas with Apache Corporation as operator. In the second quarter of 2019 three horizontal wells were completed and brought on production from reservoirs above the Middle Wolfcamp: one in the Wolfcamp “A”, one in the Jo Mill, and one in the Lower Spraberry, confirming the economic viability of these reservoirs on our acreage. Prime holds between 5% and 48% working interest in various depths of this acreage, and of the $26.7 million development cost for these three wells, our share was approximately $9.2 million. As a result of the success of these three wells, six horizontals were drilled in the first half of 2020 on this acreage block. We have an average 47.76% share of these wells. In addition to the six development locations in the Wolfcamp “A”, Jo Mill and Lower Sprayberry of our 1,300-acre block, there are four locations in the Middle Spraberry that are likely to be considered for future development at an estimated gross cost of approximately $30.2 million, with the Company’s share being approximately $14.2 million. Also in the first half of 2020, the Company participated in a horizontal well for 8.36% interest operated by Pioneer Natural Resources completed and brought into production in July, 2020. Our total net expenditure for this well will be approximately $630,000.

Also in the Permian Basin of West Texas, we are developing a 965-acre block with Concho Resources in Martin County, Texas. In 2016 and 2017, four horizontal wells were drilled and completed and put on production. 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 are encouraging for the future development of multiple landing zones within this acreage block.

In Central Reagan County, of West Texas, the Company has entered into a contract to sell deep rights covering approximately 1,950 acres for a purchase price of approximately $10.7 MM. The sale is planned to close on or before September 01, 2020.

Since the start of our Oklahoma Scoop-Stack horizontal development program, which began in 2013, the Company has participated in 41 horizontal wells for approximately $23.5 million through 2019 with an average of approximately 7% interest. There have been no new wells participated in through the second quarter of 2020. During this same period the Company chose to retain an overriding royalty interest in an additional 62 horizontal wells. In 2019, the Company participated for an average 5.78% interest in 20 horizontal wells in Canadian, Grady, and Kingfisher counties for a net cost of approximately $8.8 million. All 20 wells were completed in 2019, and of these 20 wells, twelve are operated by Encana/Newfield. In addition, the Company is also participating in four wells in Grady County, Oklahoma spud in 2018 that have not yet been completed. During 2019, the Company retained an overriding royalty interest in eighteen wells, nine of which were completed in 2019, and nine of which have yet to be completed.

Our horizontal activity in Oklahoma is focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 3,401 net acres. We believe this acreage has significant additional resource potential that could support the drilling of as many as 49 new horizontals based on an estimate of six wells per section: three in the Mississippian and three in the Woodford Shale. Should we choose to participate in future development, our share of the capital expenditures would be approximately $3.4 million at an average 10% ownership level; the Company will otherwise sell its rights for cash, or cash plus a royalty or working interest.

In 2019, in the Gulf Coast region of Texas, the Company participated with Unit Petroleum in the successful recompletion of two wells in the Wilcox Formation of the Jazz field in Polk County, Texas. The Company has a 2.8125% working interest and a 3.768% net revenue interest in these wells and participated for approximately $45,000. Also in 2019, the Company successfully recompleted a shallow straight hole well in the Segno field of Polk County, Texas with a 72.5% working interest.

In early August 2020, the Company closed on the sale of its West Virginia District operated assets. The sale includes 456 producing wells, along with approximately 31,000 leasehold acres, one salt water disposal well, and operating equipment. The Company has retained an overriding royalty interest in most properties of up to 12.5% interest.

RESULTS OF OPERATIONS

2020 and 2019 Compared

We report a net loss of $170 thousand, $0.09 per share, for the three months ended March 2020 compared with net loss of $3.04 million, $1.49 per share, for the same period of 2019. The current year net loss reflects decreases in oil, gas and NGLs sales due to lower commodity prices offset by an unrealized gain on derivatives. The significant components of income and expense are discussed below.

Oil, gas and NGLs sales decreased $11.08 million, or 46.4% from $23.88 million for the three months ended March 31, 2019 to $12.8 million for the three months ended March 31, 2020. Sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices decreased an average of $7.03 per barrel, or 13.3% on crude oil, decreased an average of $1.46 per mcf, or 61.7% on natural gas and decreased an average of $10.24 per barrel, or 51.1% on NGLs, during the three months ended March 31, 2020 from the same period in 2019.

Our crude oil production decreased by 122,000 barrels, or 34.3% from 356,000 barrels for the first quarter 2019 to 234,000 barrels for the first quarter 2020. Our natural gas production decreased by 10,000 mcf, or 1.1% from 948,000 mcf for the first quarter 2019 to 938,000 mcf for the first quarter 2020. Our natural gas liquids production decreased by 15,000 barrels, or 10.6% from 142,000 barrels for the first quarter 2019 to 127,000 barrels for the first quarter 2020. The decrease in production volumes reflect the natural decline of our properties combined with the shut-in of high lifting cost properties as commodity prices decreased during the quarter.

The following tables summarizes the primary components of production volumes and average sales prices realized for the three and six months ended June 30, 2020 and 2019 (excluding realized gains and losses from derivatives).


			Six months ended June 30,
	2020		2019		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Produced		378,000		688,000		(310,000	)		(45.1	)%
Average Price Received	$	37.89	$	55.84	$	(17.95	)		(32.1	)%

Oil Revenue (In 000’s)	$	14,324	$	38,442	$	(24,118	)		(62.7	)%

Mcf of Gas Sold		1,812,000		2,243,000		(431,000	)		(19.2	)%
Average Price Received	$	0.77	$	1.60	$	(0.83	)		(52.1	)%

Gas Revenue (In 000’s)	$	1,389	$	3,590	$	(2,201	)		(61.3	)%

Barrels of Natural Gas Liquids Sold		213,000		288,000		(75,000	)		(26.0	)%
Average Price Received	$	8.16	$	18.14	$	(9.98	)		(55.0	)%

Natural Gas Liquids Revenue (In 000’s)	$	1,738	$	5,219	$	(3,481	)		(66.7	)%

Total Oil & Gas Revenue (In 000’s)	$	17,451	$	47,251	$	(29,800	)		(63.1	)%


				Three months ended June 30,
	2020			2019		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Produced		144,000			332,000		(188,000	)		(10.8	)%
Average Price Received	$	(7.88	)	$	59.17	$	(11	)		(18.8	)%

Oil Revenue (In 000’s)	$	(3,613	)	$	19,644	$	(16,031	)		(19.7	)%

Mcf of Gas Sold		874,000			1,295,000		(421,000	)		(18.1	)%
Average Price Received	$	(0.13	)	$	1.05	$	0.63			9.6	%

Gas Revenue (In 000’s)	$	543		$	1,355	$	(812	)		0.8	%

Barrels of Natural Gas Liquids Sold		86,000			146,000		(60,000	)		(15.4	)%
Average Price Received	$	(1.63	)	$	16.27	$	0.26			(3.9	)%

Natural Gas Liquids Revenue (In 000’s)	$	495		$	2,375	$	(1,880	)		(10.4	)%

Total Oil & Gas Revenue (In 000’s)	$	4,651		$	23,374	$	(18,723	)		(16.70	)%

Oil, Natural Gas and NGL Derivatives 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. The following table summarizes the results of our derivative instruments for the three and six months ended June 2020 and 2019:


	Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020		2019
				($ in thousand)
Oil derivatives – realized gains (losses)	$	4,539		$	(964	)	$	5,545	$	(876	)
Oil derivatives – unrealized gains (losses)		(5,397	)		2,637			854		(3,101	)

Total gains (losses) on oil derivatives	$	(858	)	$	1,673		$	6,399	$	(3,977	)
Natural gas derivatives – realized gains (losses)	$	218		$	4		$	409	$	(8	)
Natural gas derivatives – unrealized gains (losses)		(218	)		156			87		151

Total gains (losses) on natural gas derivatives	$	—		$	160		$	496	$	143
NGL derivatives – realized gain (losses)	$	—		$	109		$	—	$	111
NGL derivatives – unrealized gains (losses)		—			69			—		60

Total gains (losses) on NGL derivatives		—			178		$	—	$	171

Total gains (losses) on oil, natural gas and NGL derivatives	$	(858	)	$	2,011		$	6,895	$	(3,663	)

Prices received for the six months ended June 30, 2020 and 2019, respectively, including the impact of derivatives were:


	2020		2019
Oil Price	$	52.56	$	54.56
Gas Price	$	0.99	$	1.00
NGLS Price	$	8.16	$	18.52

Field service income decreased $2.4 million or 49.95% from $4.8 million for the second quarter 2019 to $2.4 million for the second quarter 2020 and $2.8 million, or 29.60% from $9.5 million for the six months ended June 30, 2019 to $6.7 million for the six months ended June 30, 2020. This decrease is a combined result of decreased utilization and rates charged to customers as oil and gas prices declined during 2020. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations.

Lease operating expense decreased $1.9 million or 23.55% from $8.1 million for the second quarter 2019 to $6.2 million for the second quarter 2020, and decreased $3.6 million or 22.50% from $16.2 million for the six months ended June 30, 2019 to $12.6 million for the six months ended June 30, 2020. This decrease is primarily due to the shut-in of high lifting cost properties during 2020 combined with lower production taxes related to lower commodity prices.

Field service expense decreased $2.1 million or 1.92% from $4.0 million for the second quarter 2019 to $1.9 million for the second quarter 2019 and decreased $2.2 million, or 28.39% from $7.6 million for the six months ended June 30, 2019 to $5.5 million for the six months ended June 30, 2020. Field service expenses primarily consist of salaries and vehicle operating expenses which have decreased during the three and six months ended June 30, 2020 over the same periods of 2019 related to decreased utilization of the equipment as oil and gas prices declined during 2020.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $2.4 million, or 25.74% from $9.3 million for the second quarter 2019 to $6.9 million for the second quarter 2020 and $3.5 million, or 18.64% from $18.6 million for the six months ended June 30, 2019 to $15.1 million for the six months ended June 30, 2020, reflecting the reduced production rates in the first half of 2020.

General and administrative expense increased $0.5 million, or 5.48% from $9.8 million for the six months ended June 30, 2019 to $10.3 million for the six months ended June 30, 2020, and decreased $0.3 million, or 11.23% from $2.9 million for the three months ended June 30, 2019 to $2.6 million for the three months ended June 30, 2020. This overall increase in 2020 is primarily due to increases in employee wages and benefits during the first quarter offset by staff reductions reflected in the second quarter decrease.

Gain on sale and exchange of assets of $0.2 million and $1.7 million for the six months ended June 30, 2020 and June 30, 2019, respectively consists of sales of non-essential oil and gas interests and field service equipment.

Interest expense decreased from $1.0 million for the second quarter 2019 to $0.5 million for the second quarter 2020 and from $2.0 million for the six months ended June 30, 2019 to $1.2 million for the six months ended June 30, 2020. This decrease reflects the decrease in rates and current borrowings under our revolving credit agreement.

Income tax expense or benefit for the June 30, 2020 and 2019 periods varied due to the change in net income or loss for those periods. The tax benefit recorded for the six months ended June 30, 2020 includes the benefits related to tax changes under the CARES Act.

LIQUIDITY AND CAPITAL RESOURCES

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

Net cash provided by operating activities for the six months ended June 30, 2020 was $8.8 million. 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 to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through bank financing.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2020, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2020 capital budget is reflective of 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 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.

The Company maintains a Credit Agreement with a maturity date of February 15, 2021, providing for a credit facility totaling $300 million, with a borrowing base of $72 million. As of August 19, 2020, the Company has $53.5 million in outstanding borrowings and $18.5 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 re-determined estimate of proved oil and gas reserves. The borrowing base review is in progress and due to declines in commodity prices we expect our borrowing base to be set at an amount

substantially reducing our availability under the line and requiring paydowns of our current outstanding balance during the third and fourth quarters. We expect cash flows from producing properties combined with proceeds from the sale of acreage to fund these paydowns. 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 credit agreement required us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. Accordingly the Company has in place the following swap and put agreements for oil and natural gas.


	2020		2021		2020		2021
Swap Agreements
Natural Gas (MMBTU)		—		951,000	$	—	$	2.41

	2020		2021		2020		2021
Put Agreements
Natural Gas (MMBTU)		1,090,000		500,000	$	2.25	$	2.00
Oil (barrels)		61,400		66,000	$	48.27	$	35.00

On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations, increased limitations on qualified charitable contributions, and technical corrections to tax depreciation methods for qualified improvement property.

We have experienced significant disruptions to our business and operations. In particular, COVID-19 restrictions have limited access to our corporate offices and required our corporate personnel, including our legal and accounting staff.

Paycheck Protection Program Loans

During May 2020, Prime Operating Company and Eastern Oil Well Services Corporation, subsidiaries of the Company received loan proceeds in the amount of $1.28 million and $0.47 million , respectively, under the Paycheck Protection Program (the “PPP”) of the CARES Act. The PPP Loans are evidenced by a promissory note in favor of the Lender, which bears interest at the rate of 1.00% per annum. No payments of principal or interest are due under the note until the date on which the amount of loan forgiveness (if any) under the CARES Act, which can be up to 10 months after the end of the related notes covered period (which is defined as 24 weeks after the date of the loan) (the “Deferral Period”). The note may be prepaid at any time prior to maturity with no prepayment penalties. Funds from the PPP Loans may be used only for payroll and related costs, costs used to continue group health care benefits, mortgage payments, rent, utilities, and interest on other debt obligations that were incurred prior to February 15, 2020 (the “Qualifying Expenses”). Under the terms of the PPP Loans, certain amounts thereunder may be forgiven if they are used for Qualifying Expenses as described in and in compliance with the CARES Act. While the Company intends to use the PPP Loan proceeds exclusively for Qualifying Expenses, it is unclear and uncertain whether the conditions for forgiveness of the PPP Loans will be met under the current guidelines of the CARES Act. Accordingly, we cannot make any assurance that the Company will be eligible for forgiveness of the PPP Loans, in whole or in part. To the extent, if any, that any or all of the PPP loans are not forgiven, beginning one month following expiration of the Deferral Period, and continuing monthly until 24 months from the date of each applicable Note (the “Maturity Date”), the Company is obligated to make monthly payments of principal and interest to the Lender with respect to any unforgiven portion of the Note, in such equal amounts required to fully amortize the principal amount outstanding on such Note as of the last day of the applicable Deferral Period by the applicable Maturity Date.

The Company’s activities include development and exploratory drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential. In 2016, based upon the results of horizontal wells and historical vertical well performance, we decided to reduce the number of vertical wells in our drilling program and focus primarily on horizontal well drilling. We believe horizontal development of our resource base provides superior returns relative to vertical development, due to the ability of horizontals to come in contact with and drain from a greater volume of reservoir rock over more acreage, with less infrastructure, and thus at a lower cost of development per acre.

We participated in 18 gross (1.6 net) horizontal wells drilled and completed in 2019, all of which were producing at year-end. In addition, 14 gross (4.63 net) wells that had been completed at year-end 2018 and in which we had participated, were also brought on-line in 2019. Of the total 18 wells completed in 2019, three are located in West Texas, while 13 are in our Oklahoma Scoop-Stack horizontal development program. The three wells drilled in West Texas in 2019 added significantly to our reserve base, as these probable undeveloped locations were the initial test wells in intervals above the Middle Wolfcamp: one in the Wolfcamp “A”, one in the Jo Mill and one in the Lower Spraberry, and have proved up these reservoirs for the 1,300 acre block in which they were drilled. Our share of the cost of these three wells is approximately $9.2 million. Not only did these wells add proved developed reserves, but as a result, nine additional locations in these reservoirs were proven for horizontal development. Six of the nine horizontals were drilled as of April 15, 2020. The successful development of these reservoirs has also proved-up locations to be drilled on our nearby 2,600-acre block in which the Company holds between 14% and 56% interest. It is anticipated that development of as many as 54 additional horizontal wells on this 2,600-acre block will occur over the coming years. The cost of such development would be approximately $370.6 million with the Company’s share being approximately $170.8 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 early 2020, the Company participated in the drilling of six wells in Upton County, Texas, operated by Apache Corporation. These wells are expected to be completed in the fourth quarter of 2020 with a total anticipated investment of $19.4 million. Also in the first half of 2020, the Company participated in a horizontal well for 8.36% interest operated by Pioneer Natural Resources completed and brought into production in July 2020. Our total net expenditure for this well will be approximately $630,000. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.

The focus of our future activity will be on the continued development of our resource’s potential in the West Texas horizontal drilling program as well as our Scoop-Stack horizontal drilling program acreage in Oklahoma in order to maximize cash flow and return on investment.

The Company maintains an acreage position of 19,910 gross (12,560 net) acres in the Permian Basin in West Texas, 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 that support the potential drilling of as many as 180 additional horizontal wells.

In Oklahoma, the Company’s horizontal activity is primarily focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 3,460 net leasehold acres. We believe this acreage has significant additional resource potential that could support the drilling of as many as 52 new horizontal wells based on an estimate of six wells per section: three in the Mississippian and three in the Woodford Shale. Should we choose to participate in future development, our share of the capital expenditures would be approximately $40 million at an average 10% ownership level; the Company will otherwise sell its rights for cash, or cash plus a royalty or working interest.

The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.

The Company has in place both a stock repurchase program and a limited partnership interest repurchase program. Spending under these programs in 2020 and 2019 was $0.71 million and $5.9 million, respectively. In the current price environment, the Company will suspend their stock repurchase program.

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 six months of 2020 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 six months ended June 30, 2020, the Company purchased the following shares of common stock as treasury shares.


2020 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		3,701	$	149.30		148,821
February		900	$	143.31		147,921
March		200	$	139.68		147,921
April		—	$	—		147,921
May		—	$	—		147,921
June		—	$	—		147,721

Total/Average		4,801	$	147.78

(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 shares respectively, 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 June 30, 2020, a total of 3,552,279 shares have been repurchased under this program for $74,934,725 at an average price of $21.09 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		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 April 24, 2020 (filed as Exhibit 3.2 of PrimeEnergy Resources Corporation Form 8-K on April 27, 2020 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		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).

10.22.5.10.2		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).


Exhibit No.

14		PrimeEnergy Resources Corporation Code of Business Conduct and Ethics, as amended December 16, 2011 (Incorporated by reference to Exhibit 14 of PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2011).

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.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)

August 19, 2020						/s/ Charles E. Drimal, Jr.
(Date)						Charles E. Drimal, Jr.
						President
						Principal Executive Officer

August 19, 2020						/s/ Beverly A. Cummings
(Date)						Beverly A. Cummings
						Executive Vice President
						Principal Financial Officer

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