10-Q

Large Accelerated Filer

Accelerated Filer

Non-Accelerated Filer

Smaller Reporting Company

Emerging growth company

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, 2021

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

For the Transition Period From

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

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

, 2021was: Common Stock, $0.10 par value 1,994,177 shares.

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PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

PRIMEENERGY RESOURCES CORPORATION

ONDENSED

ONSOLIDATED

ALANCE

HEETS

– Unaudited

(Thousands of dollars)


	June 30, 2021			December 31, 2020
ASSETS
Current Assets
Cash and cash equivalents	$	3,797		$	996
Accounts receivable, net		10,243			7,221
Prepaid obligations		1,529			590
Other current assets		104			104

Total Current Assets		15,673			8,911
Property and Equipment, at cost
Oil and gas properties (successful efforts method), net		176,493			185,098
Field and office equipment, net		5,901			5,955

Total Property and Equipment, Net		182,394			191,053

Other assets		438			520

Total Assets	$	198,505		$	200,484

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	8,544		$	5,217
Accrued liabilities		5,297			6,787
Due to related parties		—			38
Current portion of long-term debt		1,072			487
Current portion of asset retirement and other long-term obligations		893			867
Derivative liability short-term		4,860			724

Total Current Liabilities		20,666			14,120
Long-Term Bank Debt		32,682			38,267
Asset Retirement Obligations		13,906			12,891
Derivative Liability Long-Term		1,780			44
Deferred Income Taxes		34,853			36,367
Other Long-Term Obligations		489			797

Total Liabilities		104,376			102,486
Commitments and Contingencies
Equity
Common stock, $.10 par value; Authorized: 2,810,000 shares, Outstanding: 1,994,177 shares		281			281
Paid-in capital		7,541			7,541
Retained earnings		122,946			126,804
Treasury stock, at cost; 2021: 815,823 shares		(37,502	)		(37,502	)

Total Stockholders’ Equity – PrimeEnergy Resources		93,266			97,124
Non-controlling interest		863			874

Total Equity		94,129			97,998

Total Liabilities and Equity	$	198,505		$	200,484

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

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PRIMEENERGY RESOURCES CORPORATION

ONDENSED

ONSOLIDATED

TATEMENTS

PERATIONS

– Unaudited

Three and six months ended June 30, 2021 and 2020

(Thousands of dollars, except per share amounts)


	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
Revenues
Oil sales	$	10,664		$	3,613		$	19,934		$	14,324
Natural gas sales		2,292			543			3,950			1,389
Natural gas liquids sales		2,404			495			4,149			1,738
Realized gain (loss) on derivative instruments, net		(701	)		4,757			(913	)		5,954
Field service income		2,900			2,381			5,163			6,681
Administrative overhead fees		1,161			968			2,291			2,194
Unrealized gain (loss) on derivative instruments, net		(5,057	)		(5,615	)		(5,968	)		941
Other income		—			136			29			165

Total Revenues		13,663			7,278			28,635			33,386
Costs and Expenses
Lease operating expense		5,290			6,230			10,572			12,574
Field service expense		2,378			1,925			4,331			5,474
Depreciation, depletion, amortization and accretion on discounted liabilities		6,610			6,900			13,107			15,093
General and administrative expense		2,473			2,570			5,107			10,306

Total Costs and Expenses		16,751			17,625			33,117			43,447
Gain on Sale and Exchange of Assets		106			82			106			194

(Loss) from Operations		(2,982	)		(10,265	)		(4,376	)		(9,867	)
Other (Expense)
Interest (Expense)		(484	)		(500	)		(1,007	)		(1,159	)

(Loss) Before Income Taxes		(3,466	)		(10,765	)		(5,383	)		(11,026	)
Income Taxes (Benefit)		(1,054	)		(3,979	)		(1,514	)		(4,036	)

Net (Loss)		(2,412	)		(6,786	)		(3,869	)		(6,990	)
Less: Net (Loss) Attributable to Non-Controlling Interests		(9	)		(520	)		(11	)		(554	)

Net (Loss) Attributable to PrimeEnergy		(2,403	)		(6,266	)	$	(3,858	)	$	(6,436	)

Basic (Loss) Per Common Share	$	(1.20	)	$	(3.14	)	$	(1.93	)	$	(3.23	)

Diluted (Loss) Per Common Share	$	(1.20	)	$	(3.14	)	$	(1.93	)	$	(3.23	)

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

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PRIMEENERGY RESOURCES CORPORATION

ONDENSED

ONSOLIDATED

TATEMENTS

ASH

LOWS

– Unaudited

Six Months Ended June 30, 2021 and 2020

(Thousands of dollars)


	2021			2020
Cash Flows from Operating Activities:
Net (loss)	$	(3,869	)	$	(6,990	)
Adjustments to reconcile net (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities		13,107			15,093
Gain on sale and exchange of assets		(106	)		(194	)
Unrealized (gain) loss on derivative instruments, net		5,968			(941	)
Deferred income taxes		(1,514	)		(2,315	)
Changes in assets and liabilities:
Accounts receivable		(3,022	)		5,343
Due to related parties		(38	)		—
Prepaids and other assets		(939	)		(423	)
Accounts payable		3,327			2,126
Accrued liabilities		(1,490	)		(2,896	)

Net Cash Provided by Operating Activities		11,424			8,803

Cash Flows from Investing Activities:
Capital expenditures, including exploration expense		(3,729	)		(6,046	)
Proceeds from sale of properties and equipment		106			194

Net Cash (Used in) Investing Activities		(3,623	)		(5,852	)

Cash Flows from Financing Activities:
Purchase of stock for treasury		—			(709	)
Proceeds from long-term bank debt and other long-term obligations		3,000			6,243
Repayment of long-term bank debt and other long-term obligations		(8,000	)		(5,000	)

Net Cash (Used in) Provided by Financing Activities		(5,000	)		534

Net Increase in Cash and Cash Equivalents		2,801			3,485
Cash and Cash Equivalents at the Beginning of the Period		996			1,015

Cash and Cash Equivalents at the End of the Period	$	3,797		$	4,500

Supplemental Disclosures:
Income taxes paid	$	—		$	—
Interest paid	$	1,009		$	1,182

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

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PRIMEENERGY RESOURCES CORPORATION

OTES

ONDENSED

ONSOLIDATED

INANCIAL

TATEMENTS

June 30, 2021

(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, 2020. 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, 2021 and December 31, 2020, the condensed consolidated results of operations, cash flows and equity for the six months ended June 30, 2021 and 2020.

As of June 30, 2021, 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, 2020. 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. The Company had

such repurchases during the six months ending June 30, 2021 and 2020.

(3) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:


(Thousands of dollars)	June 30, 2021			December 31, 2020
Accounts Receivable:
Joint interest billing	$	2,038		$	2,475
Trade receivables		1,267			1,073
Oil and gas sales		7,292			3,469
Other		244			802

		10,841			7,819
Less: Allowance for doubtful accounts		(598	)		(598	)

Total	$	10,243		$	7,221

Accounts Payable:
Trade	$	1,234		$	876
Royalty and other owners		7,118			3,569
Partner advances		192			193
Other		—			579

Total	$	8,544		$	5,217

Accrued Liabilities:
Compensation and related expenses	$	3,371		$	3,331
Property costs		910			2,056
Taxes		1,016			1,016
Other		—			384

Total	$	5,297		$	6,787

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(4) Property and Equipment:

Property and equipment at June 30, 2021 and December 31, 2020 consisted of the following:


(Thousands of dollars)	June 30, 2021			December 31, 2020
Proved oil and gas properties, at cost	$	524,350		$	520,488
Less: Accumulated depletion and depreciation		(347,857	)		(335,390	)

Oil and Gas Properties, Net	$	176,493		$	185,098

Field and office equipment	$	27,011		$	26,797
Less: Accumulated depreciation		(21,110	)		(20,842	)

Field and Office Equipment, Net	$	5,901		$	5,955

Total Property and Equipment, Net	$	182,394		$	191,053

(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. Under 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 and total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) 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.

During 2020, the 2017 Credit Agreement was amended to add loans under the Paycheck Protection Program to the Permitted loans, as defined in the agreement.

On February 11, 2021, the Company and its lenders entered into a Sixth Amendment to the 2017 Credit Agreement. Under this amendment the Company’s borrowing base is $40 million. Borrowings under the 2017 Credit Agreement will bear interest at a base rate plus an applicable margin ranging from 2.00% to 3.00% or at the Company’s option, at LIBOR plus an applicable margin ranging from 3.00% to 4.00%. The 2017 Credit Agreement will mature on February 11, 2023. The Company’s borrowings under this credit facility approximates fair value because the interest rates are variable and reflective of market rates.

On June 30, 2021, the Company had a total of $32 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 5.22% and $8 million was available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 5.31% for the six months ended June 30, 2021 as compared to 4.22% for six months ended June 30, 2020.

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, which was enacted March 27, 2020. 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. The Company utilized the PPP Loan proceeds exclusively for Qualifying Expenses during the

24-week

coverage period and has submitted its application for forgiveness in accordance with the terms of the CARES Act and related guidance. In the event the PPP Loan or any portion thereof is forgiven, the amount forgiven is applied to the outstanding principal.

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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 on the balance sheet as financial liabilities reported within the following lines: Current portion of long-term debt in the amount of $1.07 million and included as part of the long-term bank debt in the amount of $682 thousand.

(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. 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, 2021 were $287 thousand. Cash payments included in the operating lease cost for six months ended June 31, 2021 were $300 thousand. The weighted-average remaining operating lease terms is 14.5 months. The amortization and interest expense for the financing lease amounted to $2,302 and the cash payment for the lease was $2,552 and the lease term expired in April 2021.

The Company amended certain leases for office space in Texas providing for payments of $299,000 in 2021, $158,000 in 2022 and $17,000 in 2023.

Rent expense for office space for the six months ended June 30, 2021 and 2020 was $328,000 and $331,000, respectively.

The payment schedule for the Company’s operating lease obligations as of June 30, 2021 is as follows:


(Thousands of dollars)	Operating Leases
2021	$	299
2022		158
2023		17

Total undiscounted lease payments	$	474
Less: Amount associated with discounting		(21	)

Net operating lease liabilities	$	453

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the six months ended June 30, 2021 is as follows:


(Thousands of dollars)	June 30, 2021
Asset retirement obligation at December 31, 2020	$	13,660
Liabilities incurred		721
Liabilities settled		(281	)
Accretion expense		306

Asset retirement obligation at June 30, 2021	$	14,406

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(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 June 30, 2021 and 2020, 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 had no such repurchases during the six months ended June 30, 2021 and 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 Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at June 30, 2021 and December 31, 2020:


June 30, 2021	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, 2021
(Thousands of dollars)
Liabilities
Commodity derivative contracts	$	—	$	—	$	(6,640	)	$	(6,640	)

Total liabilities	$	—	$	—	$	(6,640	)	$	(6,640	)


December 31, 2020	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, 2020
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	97		$	97

Total assets	$	—	$	—	$	97		$	97

Liabilities
Commodity derivative contract	$	—	$	—	$	(768	)	$	(768	)

Total liabilities	$	—	$	—	$	(768	)	$	(768	)

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

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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 quarter ended June 30, 2021.


(Thousands of dollars)
Net Liabilities – December 31, 2020	$	(671	)
Total realized and unrealized (gains) losses:
Included in earnings (a)		(6,881	)
Purchases, sales, issuances and settlements		912

Net Liabilities — June 30, 2021	$	(6,640	)

(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.

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at June 30, 2021 and December 31, 2020:


			Fair Value
(Thousands of dollars)	Balance Sheet Location		June 30, 2021			December 31, 2020
Asset Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Natural gas commodity contracts		Derivative asset long-term and other assets		—		$	97

Total			$	—		$	97

Liability Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts		Derivative liability short-term	$	(3,759	)	$	(428	)
Natural gas commodity contracts		Derivative liability short-term		(1,101	)		(296	)
Crude oil commodity contracts		Derivative liability long-term		(1,552	)		—
Natural gas commodity contracts		Derivative liability long-term		(228	)		(44	)

Total			$	(6,640	)	$	(768	)

Total derivative instruments			$	(6,640	)	$	(671	)

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The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the six months ended June 30, 2021 and 2020:


	Location of gain/loss recognized in income	Amount of gain/loss recognized in income
(Thousands of dollars)	Location of gain/loss recognized in income	2021			2020
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized gain (loss) on derivative instruments, net		(1,085	)		87
Crude oil commodity contracts	Unrealized (loss) gain on derivative instruments, net		(4,883	)		854
Natural gas commodity contracts	Realized gain (loss) on derivative instruments, net		(277	)		409
Crude oil commodity contracts	Realized (loss) on derivative instruments, net		(636	)		5,545

		$	(6,881	)	$	6,895

(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,
	2021								2020
	Net Loss (In 000’s)			Weighted Average Number of Shares Outstanding		Per Share Amount			Net Income (In 000’s)			Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	(3,858	)		1,994,177	$	(1.93	)	$	(6,436	)		1,994,675	$	(3.23	)
Effect of dilutive securities:
Options (a)		—			—					—			—

Diluted	$	(3,858	)		1,994,177	$	(1.93	)	$	(6,436	)		1,994,675	$	(3.23	)


	Three Months Ended June 30,
	2021								2020
	Net Loss (In 000’s)			Weighted Average Number of Shares Outstanding		Per Share Amount			Net Income (In 000’s)			Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	(2,403	)		1,994,177	$	(1.20	)	$	(6,266	)		1,994,177	$	(3.14	)
Effect of dilutive securities:
Options (a)		—			—					—			—

Diluted	$	(2,403	)		1,994,177	$	(1.20	)	$	(6,266	)		1,994,177	$	(3.14	)

(a)	The effect of the 767,500 outstanding stock option is anti-dilutive for the six and three months ended June 30, 2021 and 2020, due to net loss for the period.

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

The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Condensed Consolidated Financial Statements and the accompanying Notes to the Condensed Consolidated Financial Statements included elsewhere in this Report contain additional information that should be referred to when reviewing this material.

OVERVIEW

The Company’s activities include development drilling. Our strategy is to develop the Company’s extensive oil and gas reserves primarily through horizontal drilling. This strategy includes targeting reservoirs with high initial production rates and cash flow as well as targeting reservoirs with lower initial production rates but with higher expected return on investment. We believe that with today’s technology, horizontal development of our reserves provides superior economic results as compared to vertical development, by delivering higher production rates through greater contact and stimulation of a larger volume of reservoir rock while minimizing the surface footprint required to develop those same reserves.

Our cash flows depend on many factors, including the price of oil, gas and natural gas liquids (NGL’s), 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 commodity 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.

Our financial results depend on many factors, particularly the price of natural gas, crude oil and natural gas liquids and our ability to market our products 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. Index prices for oil, natural gas, and NGL’s have improved since the lows of 2020, however, we expect prices to remain volatile and consequently cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenue.

We are the operator of the majority of our developed and undeveloped acreage which is nearly all held by production. In the Permian Basin of West Texas and eastern New Mexico, the Company maintains an acreage position of approximately 19,680 gross (12,460 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 52,800 gross (10,300 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 49 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 $34 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.

Table of Contents

District Information

The following table represents certain reserve and well information as of December 31, 2020.


	Gulf Coast		Mid- Continent		West Texas		Other		Total
Proved Reserves as of December 31, 2020 (MBoe)
Developed		517		1,575		5,116		6		7,214
Undeveloped		—		95		3,126		—		3,221
Total		517		1,670		8,242		6		10,435
Average Daily Production (Boe per day)		297		788		3,178		2		4,265
Gross Productive Wells (Working Interest and ORRI Wells)		239		549		556		170		1,514
Gross Productive Wells (Working Interest Only)		209		485		518		69		1,281
Net Productive Wells (Working Interest Only)		124		217		263		2		606
Gross Operated Productive Wells		158		209		325		—		692
Gross Operated Water Disposal, Injection and Supply wells		9		53		6		—		68

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 and swab rigs, water transport trucks, hot oil trucks, saltwater disposal facilities, various land excavating equipment, and trucks we own and that are operated by our field employees.

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 239 producing wells (124 net) in the Gulf Coast region as of December 31, 2020, of which 158 wells are operated by us. Average net daily production in our Gulf Coast Region in 2020 was 297 Boe. On December 31, 2020, we had 517 MBoe of proved reserves in the Gulf Coast region, which represented 5% of our total proved reserves. We maintain an acreage position of over 11,900 gross (4,300 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, two hot oilers, 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 operated wells and locations. As of June 30, 2021, 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, 2020, we had 549 wells (217 net) in the

Mid-Continent

area, of which 209 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 our

Mid-Continent

Region in 2020 was 788 Boe. On December 31, 2020, we had 1,670 MBoe of proved reserves in the

Mid-Continent

area, or 16% of our total proved reserves. We maintain an acreage position of approximately 52,800 gross (10,300 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties. 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 June 30, 2021, in the

Mid-Continent

region, the Company was participating in the completion of four wells included as Proved Undeveloped in the 2020

year-end

reserve report: one for 9.9% interest and three for less than one percent interest. In addition, the Company has committed to participate for 11.25% working interest in the drilling and completion of four wells in Canadian County, Oklahoma. Our share of these wells will be approximately $1.98 million. As of August 16, 2021, these four wells have been drilled and are currently awaiting completion.

West Texas Region

Our West Texas activities are concentrated in the Permian Basin of West Texas and New Mexico. The basin covers more than 75,000 square miles and extends across 52 Counties. The Wolfcamp and Spraberry reservoirs of this basin are among the largest contiguous accumulations of oil and gas in the United States. Production from these reservoirs is West Texas Intermediate Sweet Crude oil and high quality casing-head gas. This region is managed from our office in Midland, Texas. As of December 31, 2020, we

had 556 wells (263 net) in the West Texas area, of which 325 wells are operated by us. Principal producing intervals are in the Wolfcamp and Spraberry formations at depths ranging from 5,500 to 12,500 feet. The average net daily production in Our West Texas Region in 2020 was 3,178 Boe. On December 31, 2020, we had 8,242 MBoe of proved reserves in the West Texas area, or 79% of our total proved reserves. We maintain an acreage position of approximately 19,679 gross (12,461 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 operated wells and locations.

In the spring of 2020, the Company participated with Apache Corporation in the drilling of six horizontal wells on our Kashmir acreage in Upton County, Texas. In March of 2021, we drilled an additional three wells on the same acreage block. As of June 30, 2021, the Company was participating in the completion of these nine horizontal wells for an average of 47.5% interest with an estimated total investment of approximately $27.8 million. As of August 23, 2021, all nine wells have been completed and are in the process of being placed on production.

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, 2020. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in the Company’s 2020 Form 10K 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 thirty years of experience, holds a Bachelor’s degree in Geology and an MBA in finance, and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist.

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


	Reserve Category
	Proved Developed								Proved Undeveloped								Total
As of December 31,	Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)
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
2020		2,684		2,258		13,633		7,214		1,784		787		3,897		3,221		4,468		3,045		17,530		10,435

(a)	In computing total reserves on a barrel 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.

On December 31, 2020, the Company had 3,221 Mboe of proved undeveloped (PUD) reserves attributable to 13 wells operated by others, three of which are new wells spud in 2020 but not drilled until the first quarter of 2021, and 10 of which that were drilled as of

year-end

but not yet completed. The three new horizontal wells along with six uncompleted wells are located on our Kashmir tract in Upton County, Texas. They are operated by Apache Corporation and in the process of being completed and will be on production in the third quarter of 2021. These nine wells account for 3,127 Mboe of the total undeveloped reserves at

year-end.

Our average 47.5% share of the total cost of these nine horizontal wells will be approximately $27.8 million. The four remaining PUD wells, drilled but not completed at

year-end,

are located in Grady County, Oklahoma and account for 95 Mboe of the total undeveloped reserves.

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 proven reserves that have demonstrated consistent results capable of repetition. The technologies being used in the estimation of our proved reserves include, but are not limited to, decline curve and volumetric analysis, analogy, geologic mapping, as well as evaluation of reservoir properties, production, 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, 2020, 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
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
2020	$	43,886	$	34,717	$	37,346	$	21,823	$	81,232	$	56,539	$	14,920	$	41,619

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 before 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.

Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $1.985 per MMBtu in 2020 as compared to $2.58 per MMBtu in 2019, and $3.10 per MMBtu in 2018. Oil prices, based on the NYMEX first of the month average price, were $39.57 per barrel in 2020 as compared to $55.69 per barrel in 2019, and $65.56 per barrel in 2018.

RECENT ACTIVITIES

non-strategic

assets, or enter into strategic joint ventures.

In Upton County, West Texas, we are actively developing a contiguous 3,260 acre Area of Mutual Interest (AMI) with our joint venture partner, Apache Corporation. In this acreage block, the Company has leasehold acres with interest between 14% and 56% depending on the particular lease and depth being developed. Development to date has been from the Wolfcamp “B” reservoir where we have 34 horizontals currently producing. Planning now is for the development of the shallower Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs that have been proven economical by near-offset completions. We have 36 horizontals slated for the development of these three reservoirs, with 18 of these planned as

3-mile

laterals. In addition, there is a Middle Spraberry target reservoir that will likely be developed with 12 horizontals. In total, we anticipate 48 horizontal wells will develop these four reservoirs with a cost estimate of $146 million net to the Company. 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.

Two miles east of the AMI acreage described above, the Company is also developing a

1,280-acre

block with Apache Corporation. Initially, six horizontal wells developed the Middle Wolfcamp reservoir. In 2019, three horizontals proved the viability of production from the Wolfcamp “A”, Jo Mill, and Lower Spraberry. Since early 2020, the Company and Apache drilled nine more laterals targeting these three reservoirs, three of which were drilled in the first quarter of 2021. As of August 23, 2021, all nine wells have been completed and are in the process of being placed on production. Prime holds an average 47.5% working interest in these wells. Our share of the cost of these nine horizontal wells will be approximately $27.8 million in total. In addition to these shallow reservoirs, the Middle Spraberry is also being considered as a target. Future development of the Middle Spraberry is likely to occur using four horizontals. The approximate completed cost of these four wells is $30.2 million, with the Company’s share being $14.2 million.

Also in the Permian Basin of West Texas, we are developing a

965-acre

block with ConocoPhillips in Martin County, Texas. In 2016 and 2017, four horizontal wells were drilled and have been producing from the Wolfcamp. The Company owns between 35% and 38% interest in various leases of this joint venture acreage where ConocoPhillips is the operator. No near-term additional drilling plans have been received, however, development of offset acreage by other operators has demonstrated the potential for good economic production from multiple landing zones on our acreage block.

In Reagan County, Texas, the Company and Pioneer Natural Resources have agreed to jointly develop approximately 3,680 gross acres. This agreement facilitates the drilling of as many as 108 horizontal laterals where the company would have an average of 34.5% working interest and invest approximately $236 million. We believe this agreement represents significant future value for PrimeEnergy.

Also in Reagan County, Texas, the Company has separate joint development projects with BTA Producers, Inc. and Hibernia Energy III, LLC. These two development blocks can accommodate the drilling of 144 horizontal wells to produce from five prospective reservoirs, four of which are proven. The Company’s share is expected to be 50% and the potential investment net to the Company would be approximately $442 million. The actual number of wells eventually drilled, and the cost and the timing of such wells are dependent upon many factors including commodity market conditions.

In Canadian County, Oklahoma, the Company is participating in the drilling of four

2-mile

long horizontal laterals operated by Ovintiv

Mid-Continent

Inc. These wells have spud and will target reservoirs of the Mississippian and Woodford formations at roughly 8,900’. As of August 16, 2021, the wells have been drilled and are awaiting completion. The Company has an 11.25% interest and will invest approximately $1.98 million in the drilling and completion of these wells.

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, 2021 was $11.4 million compared to $8.8 million for the same period of 2020. 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 2021, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2021 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, 2023, providing for a credit facility totaling $300 million, with a borrowing base of $40 million. As of August 23, 2021, the Company has $32 million in outstanding borrowings and $8 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 next borrowing base review is scheduled for October 2021. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the

re-determined

borrowing base.

Our credit agreement requires us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. Accordingly, as of June 30, 2021, the Company has in place the following swap and put agreements for oil and natural gas.


	2021		2022		2023		2021		2022		2023
Swap Agreements
Natural Gas (MMBTU)		734,000		928,000		131,000	$	2.55	$	2.67	$	2.81
Oil (barrels)		157,500		196,200		27,200	$	53.57	$	51.99	$	50.31

The Company’s activities include development 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.

Our primary focus is the development of our leasehold acreage in the Permian Basin of West Texas where the Company currently holds an acreage position of 19,680 gross (12,460 net) acres, the majority of which is in Reagan, Upton, Martin and Midland counties. We believe this acreage has significant resource potential in as many as 10 reservoirs, including benches of the Spraberry, Jo Mill, and Wolfcamp, and can support the potential drilling of as many as 250 additional horizontal wells.

The Middle Wolfcamp has been the primary target for production in the area until, however, in 2019, in Upton County, the Company drilled three horizontal wells with Apache Corporation targeting shallower reservoirs in the Wolfcamp “A”, the Jo Mill, and the Lower Spraberry. These three test wells proved the productive capability of these reservoirs for the 1,280 acre block in which they were drilled and led to the drilling of nine additional wells in early 2020 and the first quarter of 2021. As of August 23, 2021, all nine wells have been completed and are in the process of being placed on production. We have an average 47.5% interest in these wells and anticipated a total investment net to the Company of approximately $27.8 million.

The successful development of these reservoirs has proven the productive potential of these reservoirs on our nearby

3,260-acre

AMI block with Apache Corporation in Upton County, Texas. Here the Company holds between 14% and 56% interest and anticipates the future development of as many as 48 additional horizontal wells targeting four reservoirs from the Wolfcamp “A” through the Middle Spraberry. The cost of such development will be approximately $370 million with the Company’s share being approximately $146 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 Reagan County, Texas, the Company holds 12,700 Gross (8.870 net) acres with exceptional potential. Offset operators have proven the productive capability of four reservoirs from the Middle Wolfcamp to the Lower Spraberry. Here the Company could participate in as many as 352 horizontals with a net cost of approximately $890 million. Near-term development plans being discussed include the drilling of three 12,500’ laterals on one acreage block, and six horizontal laterals on a second acreage block with laterals from 7,500’ to 10,000’ in length. The Company’s share of these wells would average about 37.5% and cost approximately $35.2 million net.

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.

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 with exceptional development potential. We believe this acreage could support the drilling of as many as 49 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 $34 million at an average 10% ownership; otherwise the Company will 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 was $1.45 million. The Company expects continued spending under these programs in 2021.

RESULTS OF OPERATIONS

2021 and 2020 Compared

We reported net losses of $3.9 million, or $1.93 per share and $2.4 million, or $1.20 per share for the six and three months ended June 30, 2021, respectively, as compared to net losses of $6.4 million, or $3.23 per share and $6.3 million, or $3.14 per share for the six and three months ended June 30, 2020, respectively. Current year net income reflects decreases in production offset by commodity price increases over the three and six months ended June 30, 2021, fluctuations in gains related to the sale of assets and changes related to the valuation of derivative instruments. The significant components of income and expense are discussed below.

Oil, gas and NGLs sales

increased $10.7 million, or 230.3% from $4.7 million for the three months ended June 30, 2020 to $15.4 million for the three months ended June 30, 2021 and $10.6 million, or 60.6% from $17.5 million for the six months ended June 30, 2020 to $28.0 million for the six months ended June 30, 2021.


			Three months ended June 30,
	2021		2020		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Produced		165,000		144,000		21,000			14.6	%
Average Price Received	$	64.63	$	25.09	$	39.54			157.6	%

Oil Revenue (In 000’s)	$	10,664	$	3,613	$	7,051			195.2	%

Mcf of Gas Sold		780,000		874,000		(94,000	)		(10.8	)%
Average Price Received	$	2.94	$	0.62	$	2.32			373.9	%

Gas Revenue (In 000’s)	$	2,292	$	543	$	1,749			322.1	%

Barrels of Natural Gas Liquids Sold		109,000		56,000		53,000			94.6	%
Average Price Received	$	22.06	$	5.76	$	16.30			282.9	%

Natural Gas Liquids Revenue (In 000’s)	$	2,404	$	495	$	1,909			385.7	%

Total Oil & Gas Revenue (In 000’s)	$	15,360	$	4,651	$	10,709			230.3	%

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 2021 and 2020:


	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
				($ in thousand)
Oil derivatives – realized gains (losses)	$	(484	)	$	4,539		$	(636	)	$	5,545
Oil derivatives – unrealized gains (losses)		(3,987	)		(5,397	)		(4,883	)		854

Total gains (losses) on oil derivatives	$	(4,471	)	$	(858	)	$	(5,519	)	$	6,399

Natural gas derivatives – realized gains (losses)	$	(217	)	$	218		$	(277	)	$	409
Natural gas derivatives – unrealized gains (losses)		(1,070	)		(218	)		(1,085	)		87

Total gains (losses) on natural gas derivatives	$	(1,287	)	$	—		$	(1,362	)	$	496

Total gains (losses) on oil and natural gas derivatives	$	(5,758	)	$	(858	)	$	(6,881	)	$	6,895

Prices received for the six months ended June 30, 2021 and 2020, respectively, including the impact of derivatives were:


	2021		2020
Oil Price	$	58.84	$	52.56
Gas Price	$	2.54	$	0.99
NGLS Price	$	21.28	$	8.16

Field service income

increased $0.5 million or 21.8% from $2.4 million for the second quarter 2020 to $2.9 million for the second quarter 2021 however decreased $1.5 million, or 22.7% from $6.7 million for the six months ended June 30, 2020 to $5.2 million for the six months ended June 30, 2021. These changes reflect the variation in utilization and rates resulting from the oil and gas price volatility during these periods. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations.

Lease operating expense

decreased $0.9 million or 15.1% from $6.2 million for the second quarter 2020 to $5.3 million for the second quarter 2021 and decreased $2.0 million or 15.9% from $12.6 million for the six months ended June 30, 2020 to $10.6 million for the six months ended June 30, 2021. This decrease is primarily due to the sale or

shut-in

of high lifting cost properties during 2020 offset by higher production taxes related to higher commodity prices.

Field service expense

increased $0.5 million or 23.5% from $1.9 million for the second quarter 2020 to $2.4 million for the second quarter 2021 and decreased $1.1 million, or 20.9% from $5.4 million for the six months ended June 30, 2020 to $4.3 million for the six months ended June 30, 2021. Field service expenses primarily consist of wages and vehicle operating expenses which have fluctuated during the three and six months ended June 30, 2021 compared with the same periods of 2020. These changes reflect the variation in utilization and rates resulting from the oil and gas price volatility during these periods.

Depreciation, depletion, amortization and accretion on discounted liabilities

decreased $0.3 million, or 4.2% from $6.9 million for the second quarter 2020 to $6.6 million for the second quarter 2021 and $2.0 million, or 13.2% from $15.1 million for the six months ended June 30, 2020 to $13.1 million for the six months ended June 30, 2021. These declines reflect the decrease in the property basis combined with production increases in 2021.

General and administrative expense

decreased $5.2 million, or 50.4% from $10.3 million for the six months ended June 30, 2020 to $5.1 million for the six months ended June 30, 2021, and decreased $0.1 million, or 3.8% from $2.6 million for the three months ended June 30, 2020 to $2.5 million for the three months ended June 30, 2021. These changes reflect staff reductions and decreases in compensation and benefits implemented in during the past year.

Interest expense

decreased from $500 thousand for the second quarter 2020 to $484 thousand for the second quarter 2021 and from $1.2 million for the six months ended June 30, 2020 to $1.0 million for the six months ended June 30, 2021. This decrease reflects the increase in rates and lower current borrowings under our revolving credit agreement.

Income tax benefit

for the June 30, 2021 and 2020 periods varied due to the change in net income or loss for those periods.

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 2021 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. There was no purchase of equity securities by the Company during the period covered by this report.


2021 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		—	$	—		147,721
February		—	$	—		147,721
March		—	$	—		147,721
April		—	$	—		147,721
May		—	$	—		147,721
June		—	$	—		147,721

Total/Average		—	$	—

(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, 2021, 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


	Page
Part I—Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets –June 30, 2021 and December 31, 2020		3
Condensed Consolidated Statements of Operations– For the three and six months ended June 30, 2021 and 2020		4
Condensed Consolidated Statement of Equity – For the six months ended June 30, 2021 and 2020		5
Condensed Consolidated Statements of Cash Flows – For the six months ended June 30, 2021 and 2020		6
Notes to Condensed Consolidated Financial Statements – June 30, 2021		7-13
Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation		14-23
Item 3. Quantitative and Qualitative Disclosures About Market Risk		23
Item 4. Controls and Procedures		23
Part II—Other Information
Item 1. Legal Proceedings		24
Item 1A. Risk Factors		24
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		24
Item 3. Defaults Upon Senior Securities		24
Item 4. Reserved		24
Item 5. Other Information		24
Item 6. Exhibits		25-26
Signatures		27


			Six months ended June 30,
	2021		2020		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Produced		328,000		378,000		(50,000	)		(13.2	)%
Average Price Received	$	60.77	$	37.89	$	22.88			60.4	%

Oil Revenue (In 000’s)	$	19,934	$	14,324	$	5,610			39.2	%

Mcf of Gas Sold		1,445,000		1,812,000		(367,000	)		(20.36	)%
Average Price Received	$	2.73	$	0.77	$	1.96			254.5	%

Gas Revenue (In 000’s)	$	3,950	$	1,389	$	2,561			184.4	%

Barrels of Natural Gas Liquids Sold		195,000		213,000		(18,000	)		(8.5	)%
Average Price Received	$	21.28	$	8.16	$	13.12			160.7	%

Natural Gas Liquids Revenue (In 000’s)	$	4,149	$	1,738	$	2,411			138.7	%

Total Oil & Gas Revenue (In 000’s)	$	28,033	$	17,451	$	10,582			60.6	%


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		FIRST AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of December 22, 2017 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 10.22.5.10.1 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2017).

10.22.5.10.2		SECOND AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of July 17, 2018 among PRIMEENERGY CORPORATION, as Borrower, THE LENDERS PARTY HERETO, COMPASS BANK, as Administrative Agent, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Documentation Agent, and BBVA COMPASS, as Sole Lead Arranger and Sole Book Runner, (Incorporated by reference to Exhibit 10.22.5.10.2 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2018).

10.22.5.10.3		THIRD AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of January 8, 2019, among PRIMEENERGY RESOURCES CORPORATION, as Borrower, THE LENDERS PARTY HERETO, COMPASS BANK, as Administrative Agent, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Documentation Agent, and BBVA COMPASS, as Sole Lead Arranger and Sole Book Runner (Incorporated by reference to Exhibit 10.22.5.10.3 to PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2018).

10.22.5.10.4		FOURTH AMENDMENT TO THE THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of May 8, 2020 among PRIMEENERGY RESOURCES CORPORATION, as Borrower, THE LENDERS PARTY HERETO, BBVA USA (f/k/a COMPASS BANK), as Administrative Agent, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Documentation Agent, and BBVA USA, as Sole Lead Arranger and Sole Book Runner (Incorporated by reference to 10.22.5.10.4 to PrimeEnergy Resources Corporation Form 10-Q for the quarter ended September 30, 2020).

10.22.5.10.5		FIFTH AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of September 4, 2020, among PRIMEENERGY RESOURCES CORPORATION, as Borrower, THE LENDERS PARTY HERETO, BBVA USA (f/k/a COMPASS BANK,) as Administrative Agent, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Documentation Agent, and BBVA USA, as Sole Lead Arranger and Sole Book Runner (Incorporated by reference to 10.22.5.10.5 to PrimeEnergy Resources Corporation Form 10-Q for the quarter ended September 30, 2020).

10.22.5.10.6		SIXTH AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of FEBRUARY 11, 2021, among PRIMEENERGY RESOURCES CORPORATION, as Borrower, THE GUARANTORS PARTY HERETO, THE LENDERS PARTY, HERETO, BBVA USA, as Administrative Agent and BBVA USA, as Sole Lead Arranger and Sole Book Runner (Incorporated by reference to Exhibit 10.22.5.10.6 to PrimeEnergy Resources Corporation Form 8-K dated February 16, 2021).


Exhibit No.

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).

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.LAB		XBRL Taxonomy Extension Label Linkbase Document (filed herewith)

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith)

104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)


	Common Stock					Additional Paid-In Capital		Retained Earnings			Treasury Stock			Total Stockholders’ Equity – PrimeEnergy			Non- Controlling Interest			Total Equity
	Shares Outstanding			Common Stock		Additional Paid-In Capital		Retained Earnings			Treasury Stock			Total Stockholders’ Equity – PrimeEnergy			Non- Controlling Interest			Total Equity

Balance at December 31, 2020		1,994,177		$	281	$	7,541	$	126,804		$	(37,502	)	$	97,124		$	874		$	97,998
Net Loss		—			—		—		(3,858	)		—			(3,858	)		(11	)		(3,869	)

Balance at June 30, 2021		1,994,177		$	281	$	7,541	$	122,946		$	(37,502	)	$	93,266		$	863		$	94,129


Balance at December 31, 2019		1,998,978		$	281	$	7,505	$	129,120		$	(36,792	)	$	100,114		$	3,249		$	103,363
Purchase 4,801 shares of common stock		(4,801	)	$	—	$	—	$	—		$	(709	)	$	(709	)	$	—		$	(709	)
Net Loss		—			—		—		(6,436	)		—			(6,436	)		(554	)		(6,990	)

Balance at June 30, 2020		1,994,177		$	281	$	7,505	$	122,684		$	(37,501	)	$	92,969		$	2,695		$	95,664