PrimeEnergy Resources (PNRG) 10-Q 2021 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended March 31, 2021

Or

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

For the Transition Period From                 to                 

Commission File Number 0-7406

PrimeEnergy Resources Corporation

(Exact name of registrant as specified in its charter)

Delaware	84-0637348
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer Identification No.)

9821 Katy Freeway, Houston, Texas 77024

(Address of principal executive offices)

(713) 735-0000

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filings required for the past 90 days.    Yes  ☒    No  ☐

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

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

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

The number of shares outstanding of each class of the Registrant’s Common Stock as of May 17, 2021 was: Common Stock, $0.10 par value 1,994,177 shares.

PrimeEnergy Resources Corporation

Index to Form 10-Q

March 31, 2021

	Page
Part I—Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets –March  31, 2021 and December 31, 2020		3
Condensed Consolidated Statements of Operations – For the three months ended March 31, 2021 and 2020		4
Condensed Consolidated Statement of Equity – For the three months ended March 31, 2021 and 2020		5
Condensed Consolidated Statements of Cash Flows – For the three months ended March 31, 2021 and 2020		6
Notes to Condensed Consolidated Financial Statements – March  31, 2021		7-13
Item  2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation		13-21
Item 3. Quantitative and Qualitative Disclosures About Market Risk		21
Item 4. Controls and Procedures		21
Part II - Other Information
Item 1. Legal Proceedings		22
Item 1A. Risk Factors		22
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		22
Item 3. Defaults Upon Senior Securities		22
Item 4. Reserved		22
Item 5. Other Information		22
Item 6. Exhibits		23-24
Signatures		25

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PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – Unaudited

(Thousands of dollars)

	March 31, 2021			December 31, 2020
ASSETS
Current Assets
Cash and cash equivalents	$	4,018		$	996
Accounts receivable, net		7,377			7,221
Prepaid obligations		1,030			590
Derivative asset short-term		17			—
Other current assets		536			104
Total Current Assets		12,978			8,911
Property and Equipment, at cost
Oil and gas properties (successful efforts method), net		179,441			185,098
Field and office equipment, net		5,915			5,955
Total Property and Equipment, Net		185,356			191,053
Other assets.		1,004			520
Total Assets	$	199,338		$	200,484
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	4,986		$	5,217
Accrued liabilities		7,287			6,787
Due to related parties		38			38
Current portion of long-term debt		780			487
Current portion of asset retirement and other long-term obligations		1,315			868
Derivative liability short-term		1,284			723
Total Current Liabilities		15,690			14,120
Long-Term Bank Debt		36,925			38,267
Asset Retirement Obligations		13,016			12,891
Deferred Income Taxes		35,907			36,367
Other Long-Term Obligations		1,259			841
Total Liabilities		102,797			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		125,349			126,804
Treasury stock, at cost; 815,823 shares		(37,502	)		(37,502	)
Total Stockholders’ Equity – PrimeEnergy Resources		95,669			97,124
Non-controlling interest		872			874
Total Equity		96,541			97,998
Total Liabilities and Equity	$	199,338		$	200,484

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

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PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTSOF OPERATIONS – Unaudited

Three Months Ended March 31, 2021 and 2020

(Thousands of dollars, except per share amounts)

	2021			2020
Revenues
Oil sales	$	9,270		$	10,711
Natural gas sales		1,658			846
Natural gas liquids sales		1,745			1,243
Realized (loss) gain on derivative instruments, net		(212	)		1,197
Field service income		2,263			4,300
Administrative overhead fees		1,130			1,226
Unrealized (loss) gain on derivative instruments, net		(911	)		6,556
Other income		29			29
Total Revenues		14,972			26,108
Costs and Expenses
Lease operating expense		5,282			6,344
Field service expense		1,953			3,549
Depreciation, depletion, amortization and accretion on discounted liabilities		6,497			8,193
General and administrative expense		2,634			7,736
Total Costs and Expenses		16,366			25,822
Gain on Sale and Exchange of Assets		—			112
(Loss) Income from Operations		(1,394	)		398
Other (Expense)
Interest expense		(523	)		(659	)
(Loss) Before (Benefit from) Income Taxes		(1,917	)		(261	)
(Benefit from) Income Taxes		(460	)		(57	)
Net (Loss)		(1,457	)		(204	)
Less: Net (Loss) Attributable to Non-Controlling Interests		(2	)		(34	)
Net (Loss) Attributable to PrimeEnergy Resources	$	(1,455	)	$	(170	)
Basic (Loss) Per Common Share	$	(0.73	)	$	(0.09	)
Diluted (Loss) Per Common Share	$	(0.73	)	$	(0.09	)

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

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PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTOF EQUITY – Unaudited

Three Months Ended March 31, 2021 and 2020

(Thousands of dollars)

	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)		—			—		—		(1,455	)		—			(1,455	)		(2	)		(1,457	)
Balance at March 31, 2021		1,994,177		$	281	$	7,541	$	125,349		$	(37,502	)	$	95,669		$	872		$	96,541
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)		—			—		—		(170	)		—			(170	)		(34	)		(204	)
Balance at March 31, 2020		1,994,177		$	281	$	7,505	$	128,950		$	(37,501	)	$	99,235		$	3,215		$	102,450

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

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PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTSOF CASH FLOWS – Unaudited

Three Months Ended March 31, 2021 and 2020

(Thousands of dollars)

	2021			2020
Cash Flows from Operating Activities:
Net (Loss)	$	(1,457	)	$	(204	)
Adjustments to reconcile net (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities		6,497			8,193
Gain on sale and exchange of assets		—			(112	)
Unrealized (gain) loss on derivative instruments, net		911			(6,556	)
Deferred income taxes		(460	)		(57	)
Changes in assets and liabilities:
Accounts receivable		(156	)		4,634
Prepaids and other assets		(872	)		(512	)
Accounts payable		(231	)		3,096
Accrued liabilities		500			(1,102	)
Net Cash provided by Operating Activities		4,732			7,380
Cash Flows from Investing Activities:
Capital expenditures, including exploration expense		(660	)		(1,583	)
Proceeds from sale of properties and equipment		—			112
Net Cash (Used in) Investing Activities		(660	)		(1,471	)
Cash Flows from Financing Activities:
Purchase of stock for treasury		—			(709	)
Proceeds from long-term bank debt and other long-term obligations		3,000			5,000
Repayment of long-term bank debt and other long-term obligations		(4,050	)		(5,000	)
Net Cash (Used in) Financing Activities		(1,050	)		(709	)
Net Increase in Cash and Cash Equivalents		3,022			5,200
Cash and Cash Equivalents at the Beginning of the Period		996			1,015
Cash and Cash Equivalents at the End of the Period	$	4,018		$	6,215
Supplemental Disclosures:
Income taxes paid	$	—		$	—
Interest paid	$	355		$	450

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

6

PRIMEENERGY RESOURCES CORPORATION

NOTESTO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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 March 31, 2021 and December 31, 2020, the condensed consolidated results of operations, cash flows and equity for the three months ended March 31, 2021 and 2020.

As of March 31, 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) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

(Thousands of dollars)	March 31, 2021			December 31, 2020
Accounts Receivable:
Joint interest billing	$	1,487		$	2,475
Trade receivables		782			1,073
Oil and gas sales		5,706			3,469
Other		—			802
		7,975			7,819
Less: Allowance for doubtful accounts		(598	)		(598	)
Total	$	7,377		$	7,221
Accounts Payable:
Trade	$	1,450		$	876
Royalty and other owners		3,009			3,569
Partner advances		227			193
Other		300			579
Total	$	4,986		$	5,217
Accrued Liabilities:
Compensation and related expenses	$	3,943		$	3,331
Property costs		2,161			2,056
Taxes		1,016			1,016
Other		167			384
Total	$	7,287		$	6,787

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(3) Property and Equipment:

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

(Thousands of dollars)	March 31, 2021			December 31, 2020
Proved oil and gas properties, at cost	$	521,035		$	520,488
Less: Accumulated depletion and depreciation		(341,594	)		(335,390	)
Oil and Gas Properties, Net	$	179,441		$	185,098
Field and office equipment	$	26,894		$	26,797
Less: Accumulated depreciation		(20,979	)		(20,842	)
Field and Office Equipment, Net	$	5,915		$	5,955
Total Property and Equipment, Net	$	185,356		$	191,053

(4) 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 March 31, 2021, the Company had a total of $35.95 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 5.31% and $4.05 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 5.27% for the quarter ended March 31, 2021 as compared to 4.81% for quarter ended March 31, 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 will submit 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 $780 thousand and included as part of the long-term bank debt in the amount of $975 thousand.

(5) 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 three months ended March 31, 2021 were $140 thousand. Cash payments included in the operating lease cost for three months ended March 31, 2021 were $151 thousand. The weighted-average remaining operating lease terms is 17.5 months. The amortization and interest expense for financing lease amounted to $1,828 and the cash payment for the lease was $1,913 and the lease term remaining was for 13 months.

The Company amended certain leases for office space in Texas providing for payments of $599,000 in 2021, $157,000 in 2022 and $17,000 in 2023.

Rent expense for office space for the quarters ended March 31, 2021 and 2020 was $162,000 and $163,000, respectively.

The payment schedule for the Company’s operating and financing lease obligations as of March 31, 2021 is as follows:

(Thousands of dollars)	Operating Leases			Financing Leases
2021	$	449		$	1
2022		157			—
2023		17			—
Total undiscounted lease payments	$	623		$	1
Less: Amount associated with discounting		(23	)		—
Net operating lease liabilities	$	600		$	1

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the three months ended March 31, 2021 is as follows:

(Thousands of dollars)	March 31, 2021
Asset retirement obligation at December 31, 2020	$	13,660
Liabilities incurred		12
Liabilities settled		(40	)
Accretion expense		153
Asset retirement obligation at March 31, 2021	$	13,785

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.

9

(6) 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.

(7) 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, 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.

(8) Related Party Transactions:

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.

(9) 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 March 31, 2021 and December 31, 2020:

March 31, 2021	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at March 31, 2021
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	94		$	94
Total assets	$	—	$	—	$	94		$	94
Liabilities
Commodity derivative contracts	$	—	$	—	$	(1,676	)	$	(1,676	)
Total liabilities	$	—	$	—	$	(1,676	)	$	(1,676	)
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

10

March 31, 2021	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at March 31, 2021
(Thousands of dollars)
Liabilities
Commodity derivative contract	$	—	$	—	$	(768	)	$	(768	)
Total liabilities	$	—	$	—	$	(768	)	$	(768	)

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 March 31, 2021.

(Thousands of dollars)
Net Liabilities – December 31, 2020	$	(671	)
Total realized and unrealized (gains) losses:
Included in earnings (a)		(1,145	)
Purchases, sales, issuances and settlements		234
Net Liabilities — March 31, 2021	$	(1,582	)

(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 March 31, 2021 and December 31, 2020:

			Fair Value
(Thousands of dollars)	Balance Sheet Location		March 31, 2021			December 31, 2020
Asset Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Natural gas commodity contracts		Derivative asset short-term	$	17		$	—
Natural gas commodity contracts		Derivative asset long-term and other assets		77			97
Total			$	94		$	97
Liability Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts		Derivative liability short-term	$	(938	)	$	(428	)
Natural gas commodity contracts		Derivative liability short-term		(346	)		(296	)
Crude oil commodity contracts		Derivative liability long-term		(385	)		—
Natural gas commodity contracts		Derivative liability long-term		(7	)		(44	)
Total			$	(1,676	)	$	(768	)
Total derivative instruments			$	(1,582	)	$	(671	)

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The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the quarters ended March 31, 2021 and 2020:

	Location of gain/loss recognized in income	Amount of gain/loss recognized in income
(Thousands of dollars)		2021			2020
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized (loss) gain on derivative instruments, net	$	(15	)	$	305
Crude oil commodity contracts	Unrealized (loss) gain on derivative instruments, net		(896	)		6,251
Natural gas commodity contracts	Realized (loss) gain on derivative instruments, net		(60	)		191
Crude oil commodity contracts	Realized (loss) gain on derivative instruments, net		(152	)		1,006
		$	(1,123	)	$	7,753

(10) 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:

	Quarter Ended March 31,
	2021								2020
	Net Income (In 000’s)			Weighted Average Number of Shares Outstanding		Per Share Amount			Net Income (In 000’s)			Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	(1,455	)		1,994,197	$	(0.73	)	$	(170	)		1,995,174	$	(0.09	)
Effect of dilutive securities:
Options(a)													—
Diluted	$	(1,455	)		1,994,197	$	(0.73	)	$	(170	)		1,995,174	$	(0.09	)

(a) The effect of the 767,000 outstanding stock options is antidilutive for the quarter ended March 31, 2021 and 2020, due to net loss for this 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.

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. 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 56,090 gross (10,355 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 $12 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.

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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 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.

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. At 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 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, 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. At December 31, 2020, we had 1670 MBoe of proved reserves in the Mid-Continent area, or 16% of our total proved reserves. We maintain an acreage position of approximately 56,000 gross (10,355 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, 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.

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, 2020, we had 556 wells (263 net) in the West Texas area,

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of which 325 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 Our West Texas Region in 2020 was 3,178 Boe. At 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 own operated wells and locations.

At December 31, 2020, the Company was committed to participate with Apache Corporation in the drilling of three Proved Undeveloped horizontal locations in Upton County, Texas and the completion of these along with six other wells drilled in 2020 on the same tract. The three new horizontals have been drilled and cased as of April 1, 2021. Completion operations for all nine are scheduled for June 2021.

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 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 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.

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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 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, 2020, the Company had 3,221 Mboe of proved undeveloped 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 were drilled as of year-end. The three new horizontals along with six uncompleted wells are located in Upton County, Texas and are in the process of being completed and we expect them to be placed on production by the end of the second quarter of 2021. Apache Corporation is the operator of these wells. These nine PUD wells account for 3,127 Mboe of the total undeveloped reserves. The nine wells mentioned above are located on our 1,300 acre Kashmir tract in Upton County, operated by Apache Corporation. Our average 47.5% share of the total cost of these nine horizontal wells will be approximately $26 million. The four remaining PUD wells, drilled but not completed, 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 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, 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 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.

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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

The Company’s activities include development and exploratory 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.

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 current commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures.

In accordance with SEC rules governing the scheduling of development of proved undeveloped (PUD) reserves, our year-end reserve report includes only those three wells that were slated to be drilled in 2021 along with 10 PUD locations that at year-end 2020 had been drilled but not yet completed. The three new wells drilled in the first quarter of 2021 and the six wells drilled in 2020 on the same Upton County, Texas tract are slated to be completed and on production by the end of the second quarter of 2021. The Company has an average of 47.5% interest in these nine wells. The remaining four PUD horizontal wells, drilled but not completed at year-end, are located in Grady County, Oklahoma. Of these, the Company has 10% interest in one well and less than one percent interest in each of three wells.

Since the start of our West Texas horizontal drilling program in 2015 and through the first quarter of 2021 the Company has participated in 77 horizontal wells in the Permian Basin, one of which was drilled and brought into production in 2020. As of year-end, the Company has invested approximately $108 MM in this drilling program, including over $4 million in six wells drilled in 2020 that will be completed in 2021. In addition, the Company has invested another $3.2 million in three new horizontals drilled in the first quarter of 2021. All nine of these wells are designated as proved undeveloped in the year-end reserve report and are to be completed and on-line by the end of the second quarter of 2021. Of the total 77 horizontal wells in this program, the Company has an average of 30.75% interest in 62 wells, and less than one percent interest in 15 wells.

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 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 and brought on production in February, 2019. This is believed to be full development of the Wolfcamp “B” reservoir for this lease block. Future development is expected in the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs for this block, following the 2019 successful development of these reservoirs on our offset 1,280 acre lease block of the Kashmir Tract. Given the favorable results achieved by the initial three wells on the 1,280 block it is expected that as many as 54 additional horizontals will be developed on this 3,260 acre block in the near future. The cost of development would be approximately $370.6 million with the Company’s share being approximately $170.8 million. In addition to the 54 wells likely to be drilled for these three reservoirs, there is a fourth target reservoir, the Middle Spraberry, that is also prospective for future development. The potential of the Middle Spraberry on the 3,260

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acre block is for 18 horizontal wells to be drilled and completed at a gross cost of approximately $126.3 million with the Company’s share being 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 acre block being developed, as described above, the Company is also developing an offsetting 1,280 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 47.5% working interest in these reservoirs. As a result of the success of the initial three wells, nine new horizontals were spud in the first quarter of 2020 with six being fully drilled by May, 2020. The three remaining wells were drilled in the first quarter of 2021. All nine of these wells are slated for completion and to be on production by the end of the second quarter of 2021. Our average 47.5% share of the cost of these nine horizontal wells will be approximately $26.7 million in total.    In addition to the nine new development locations in the Wolfcamp “A”, Jo Mill and Lower Sprayberry, four locations in the Middle Spraberry will 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 Permian Basin of West Texas, we are developing a 965 acre block with Connoco Phillips 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 Connoco Phillips is the operator. No near-term additional drilling plans have been received from Connoco Phillips, however, offset operators have been actively drilling and their results are encouraging for the future development of multiple landing zones within this acreage block.

DoublePoint Energy, acquired by Pioneer Natural Resources, entered into a joint development agreement for the horizontal development of lands located in Reagan County, Texas in February of 2021 with PrimeEnergy . The agreement covers approximately 3,680 gross acres of blocked up leasehold to allow for 1.5 and 2 mile horizontal laterals. We believe this agreement represents significant future value for PrimeEnergy.

On May 10, 2021, the Company agreed to participate in the drilling of four wells in Canadian County, Oklahoma with Ovintiv Mid-Continent Inc. Drilling of these horizontal wells is expected to occur in the third quarter of 2021 and target the proven oil reservoirs of the Mississippian and Woodford Formations at roughly 8,900’ in depth with laterals of approximately 10,000’ in length. The Company has an 11.25% interest and will invest approximately $1.98 million in the drilling and completion of these wells.

RESULTS OF OPERATIONS

We reported a net loss of $1.46 million, $0.73 per share, for the three months ended March 2021 compared with net loss of $170 thousand, $0.09 per share, for the same period of 2020. The current year net loss reflects changes in oil, gas and NGLs sales related to decreased production combined with higher commodity prices offset by an unrealized loss on derivatives. The significant components of income and expense are discussed below.

Oil, gas and NGLs sales remained flat at $12.67 million and $12.80 million for the three months ended March 31, 2021 and 2020 respectively. Sales vary due to changes in volumes of production sold and realized commodity prices. There were substantial price increases in prices during the first quarter of 2021 compared to the same period in 2020. Our realized prices increased an average of $11.10 per barrel, or 24% on crude oil, increased an average of $1.59 per mcf, or 177% on natural gas and increased an average of $10.50 per barrel, or 107% on NGLs, during the three months ended March 31, 2021 from the same period in 2020.

Our crude oil production decreased by 71,000 barrels, or 30.34% from 234,000 barrels for the first quarter 2020 to 163,000 barrels for the first quarter 2021. Our natural gas production decreased by 273,000 mcf, or 29.1% from 938,000 mcf for the first quarter 2020 to 665,000 mcf for the first quarter 2021. Our natural gas liquids production decreased by 41,000 barrels, or 32.3% from 127,000 barrels for the first quarter 2020 to 86,000 barrels for the first quarter 2021. The decrease in production volumes reflect the natural decline of our properties combined with the shut-in of properties due to the freezing weather in Texas and Oklahoma during February 2021.

The following table summarizes the primary components of production volumes and average sales prices realized for the three months ended March 31, 2021 and 2020 (excluding realized gains and losses from derivatives).

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			Three Months Ended March 31,
	2021		2020		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Produced		163,000		234,000		(71,000	)		(30.34	)%
Average Price Received	$	56.87	$	45.77	$	11.10			24.25	%
Oil Revenue (In 000’s)	$	9,270	$	10,711	$	(1,441	)		(13.45	)%
Mcf of Gas Sold		665,000		938,000		(273,000	)		(29.10	)%
Average Price Received	$	2.49	$	0.90	$	1.59			177.03	%
Gas Revenue (In 000’s)	$	1,658	$	846	$	812			95.98	%
Barrels of Natural Gas Liquids Sold		86,000		127,000		(41,000	)		(32.28	)%
Average Price Received	$	20.29	$	9.79	$	10.50			107.26	%
Natural Gas Liquids Revenue (In 000’s)	$	1,745	$	1,243	$	502			40.39	%
Total Oil & Gas Revenue (In 000’s)	$	12,673	$	12,800	$	(127	)		(0.99	)%

Realized net gains and losses on derivative instruments include net losses of $0.06 million and $0.15 million on the settlements of natural gas and crude oil derivatives, respectively, for the first quarter 2021, and net gains of $0.19 million and $1.01 million on the settlements of natural gas and crude oil derivatives, respectively, for the first quarter 2020.

We do not apply hedge accounting to any of our commodity-based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues.

Changes in market values in the first quarter of 2021 resulted in net unrealized losses of $0.896 million and $0.015 million associated with crude oil and natural gas contracts, respectively. Changes in market values in the first quarter of 2020 resulted in net unrealized gains of $6.25 million and $0.31 million associated with crude oil and natural gas contracts, respectively.

	2021		2020
Oil Price	$	55.70	$	45.82
Gas Price	$	2.40	$	0.90
NGLS Price	$	20.29	$	9.79

Field service income decreased $2.0 million or 47.4% for the first quarter 2021 to $2.3 million from $4.3 million for the first quarter 2020. This decrease is a combined result of decreased utilization and rates charged to customers during the current quarter compared to the same quarter in 2020. Workover rig services, hot oil treatments, salt water hauling and disposal represent the bulk of our field service operations.

Lease operating expense decreased $1.06 million or 16.7% from $6.34 million for the first quarter 2020 to $5.28 million for the first quarter 2021. This decrease is primarily due to the disposition of marginal properties throughout the second half of 2020.

Field service expense decreased $1.6 million or 45% to $1.95 million for the first quarter 2021 from $3.55 million for the first quarter 2020. Field service expenses primarily consist of salaries and vehicle operating expenses which have decreased during the three months ended March 31, 2021 over the same period of 2020 related to decreased utilization of the equipment during the current quarter compared to the same quarter in 2020.

Depreciation, depletion, amortization and accretion on discounted liabilities decreased $1.7 million or 20.7% from $8.2 million for the first quarter 2020 to $6.5 million for the first quarter 2021 reflecting the reduced production rates in the first quarter of 2021.

General and administrative expense decreased $5.1 million or 66% from $7.7 million for the three months ended March 31, 2020 to $2.6 million for the three months ended March 31, 2021. This decrease in 2021 is primarily due to decreases in employee wages and benefits related to staff cut backs implemented late in the first quarter of 2020.

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Interest expense decreased $0.14 million or 20.6% from $0.66 million for the first quarter 2020 to $0.52 million for the first quarter 2021. This decrease reflects the decrease in current borrowings under our revolving credit agreement.

Income tax benefit and expense for the March 31, 2021 and 2020 quarters varied due to the change in net loss for those periods.

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 quarter ended March 31, 2021, was $4.7 million, compared to $7.4 million in the first quarter 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 May 15, 2021, the Company has $35.95 million in outstanding borrowings and $4.05 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 July 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 March 31, 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)		1,219,000		928,000		131,000	$	2.48	$	2.67	$	2.81
Oil (barrels)		157,500		196,200		27,200	$	53.60	$	51.99	$	50.31
Put Agreements
Oil (barrels)		30,000					$	35.00

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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.

In 2019, we participated in the drilling of three horizontal wells in Upton County, Texas, adding significantly to our proved reserves, as these probable undeveloped locations were the initial test wells in the Wolfcamp “A” the Jo Mill and the Lower Spraberry of this acreage. These tests proved-up these reservoirs for the 1,280 acre block in which they were drilled and led to the drilling of nine additional wells in 2020 and the first quarter of 2021.

In early 2020, six of the nine horizontals mentioned above were drilled, and in the first quarter of 2021 the remaining three were drilled. All nine wells are slated for completion and to be on production by the end of the second quarter of 2021. We have an average 47.5% interest in these wells and our anticipated total investment is expected to be approximately $27 million.

The successful development of these reservoirs has also proved-up locations to be drilled on our nearby 3,260-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 3,260-acre block will occur over the coming years. The cost of such development will be approximately $370 million with the Company’s share being approximately $170 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.

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 Company maintains an acreage position of 19,680 gross (12,460 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 $12 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 was $1,452 million. The Company expects continued spending under these programs in 2021.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Item 4. CONTROLS AND PROCEDURES

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

There were no changes in the Company’s internal control over financial reporting that occurred during the first three months of 2021 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

None.

Item 1A. RISK FACTORS

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

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no sales of equity securities by the Company during the period covered by this report. 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
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 March 31, 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

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Item 6. EXHIBITS

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

Exhibit No.
3.1	Certificate of Incorporation of PrimeEnergy Resources Corporation, as amended and restated of December  21, 2018, (filed as Exhibit 3.1 of PrimeEnergy Resources Corporation Form 8-K on December 27, 2018, and incorporated herein by reference).
3.2	Bylaws of PrimeEnergy Resources Corporation as amended and restated as of 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).
10.22.5.10.4	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 12, 2021).
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).

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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)

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SIGNATURES

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

	PrimeEnergy Resources Corporation
	(Registrant)
May 18, 2021	/s/ Charles E. Drimal, Jr.
(Date)	Charles E. Drimal, Jr.
	President
	Principal Executive Officer
	/s/ Beverly A. Cummings
May 18, 2021	Beverly A. Cummings
	Executive Vice President
	Principal Financial Officer

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