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 ~~September~~June 30, ~~2017~~

2022

☐	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
~~xx(~~ (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 ~~November 7, 2017~~August 15, 2022 was: Common Stock, $0.10 par value ~~2,181,681~~1,936,000 shares.

Table of Contents

PrimeEnergy Resources Corporation

Index to Form

10-Q

~~September~~

June 30, ~~2017~~

2022


			Page
Part ~~I -~~ I—Financial Information

Item 1.	Financial Statements

	Condensed Consolidated Balance Sheets ~~– September~~–June 30, ~~2017~~2022 and December 31, ~~2016~~2021		3

	Condensed Consolidated Statements of ~~Operations –~~Operations– For the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 and ~~2016~~2021		4

	~~Condensed Consolidated Statements of Comprehensive Income – For the nine months ended September 30, 2017 and 2016~~		5

	Condensed Consolidated Statement of Equity – For the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 and 2021		65

	Condensed Consolidated Statements of Cash Flows – For the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 and ~~2016~~2021		76

	Notes to Condensed Consolidated Financial Statements – ~~September~~June 30, ~~2017~~2022		~~8-14~~ 7-12

Item 2.	Management’s Discussion and Analysis of Financial Conditions and Results of ~~Operations~~Operation		~~15-19~~ 13-22

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		2023

Item 4.	Controls and Procedures		2023

Part ~~II -~~ II—Other Information

Item 1.	Legal Proceedings		2124

Item 1A.	Risk Factors		2124

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		21

~~Item 3.~~	~~Defaults Upon Senior Securities~~		21

~~Item 4.~~	~~Reserved~~		21

~~Item 5.~~	~~Other Information~~		21

~~Item 6.~~	~~Exhibits~~		~~22-23~~

~~Signatures~~			24
Item 3. Defaults Upon Senior Securities		24
Item 4. Reserved		24
Item 5. Other Information		24
Item 6. Exhibits		25-26
Signatures		27

Table of Contents

PART I—FINANCIAL INFORMATION

~~Item 1. FINANCIAL STATEMENTS -~~

Item 1.

FINANCIAL STATEMENTS

PRIMEENERGY RESOURCES CORPORATION

C
ONDENSED
C
ONSOLIDATED
B
ALANCE
S
HEETS
–

Unaudited

(Thousands of dollars)

June 30,

2022

December 31,

2021


ASSETS

Current Assets

Cash and cash equivalents    $ 11,067 $ 10,347
Accounts receivable, net    17,651 14,208
Prepaid obligations    482 733
Other current assets    40 40

Total Current Assets    29,240 25,328
Property and Equipment
Oil and gas properties at cost    541,419 539,484
Less: Accumulated depletion and depreciation    (373,000 ) (359,742 )

   168,419 179,742

Field and office equipment at cost    27,175 27,080
Less: Accumulated depreciation    (22,760 ) (22,159 )

   4,415 4,921

Total Property and Equipment, Net    172,834 184,663
Derivative asset long-term and other assets    898 923

Total Assets    $ 202,972 $ 210,914

LIABILITIES AND EQUITY
   ,
Current Liabilities
Accounts payable    $ 6,355 $ 7,282
Accrued liabilities    7,481 7,821
Due to related parties    12 52
Current portion of asset retirement and other long-term obligations    1,576 1,630
Derivative liability short-term    9,791 4,935

Total Current Liabilities    25,215 21,720
Long-Term Bank Debt    —   36,000
Asset Retirement Obligations    12,726 13,222
Derivative Liability Long-Term    —   650
Deferred Income Taxes    45,028 38,743
Other Long-Term Obligations    1,974 1,488

Total Liabilities    84,943 111,823
Commitments and Contingencies    0 0
Equity
Common stock, $.10 par value; 2022 and 2021: Authorized: 2,810,000 shares, outstanding 2022: 1,952,645 shares; outstanding 2021: 1,992,077 shares
.
   281 281
Paid-in
capital
   7,555 7,555
Retained earnings    151,027 128,902
Treasury stock, at cost; 2022: 857,355 shares; 2021: 817,923    (40,834 ) (37,647 )

Total Equity    118,029 99,091

Total Liabilities and Equity    $ 202,972 $ 210,914

3

Table of Contents

PRIMEENERGY RESOURCES CORPORATION

C
ONDENSED
C
ONSOLIDATED B~~ALANCE~~
S~~HEETS~~

TATEMENTS

PERATIONS

– Unaudited

Three and six months ended June 30, 2022 and 2021

(Thousands of dollars, except per share amounts)

   September 30,
2017 December 31,
2016
ASSETS

Current Assets

Cash and cash equivalents
   $ 9,920 $ 6,568
Restricted cash and cash equivalents
   4,193 3,543
Accounts receivable, net
   10,322 7,400
Other current assets
   1,086 572


Total Current Assets
   25,521 18,083
Property and Equipment, at cost

Oil and gas properties (successful efforts method), net
   200,405 187,490
Field and office equipment, net
   7,507 8,878


Total Property and Equipment, Net
   207,912 196,368
Other Assets
   183 203


Total Assets
   $ 233,616 $ 214,654


LIABILITIES AND EQUITY

Current Liabilities

Accounts payable
   $ 13,302 $ 11,965
Accrued liabilities
   16,955 8,184
Current portion of long-term debt
   2,905 2,949
Current portion of asset retirement obligations
   2,006 1,563
Derivative liability short-term
   292 2,547
Due to related parties
   31 —


Total Current Liabilities
   35,491 27,208
Long-Term Bank Debt
   50,840 66,316
Asset Retirement Obligations
   15,711 15,943
Derivative Liability Long-Term
   329 1,092
Deferred Income Taxes
   47,925 37,500
Other Long-Term Obligations
   616 715


Total Liabilities
   150,912 148,774
Commitments and Contingencies

Equity

Common stock, $.10 par value; Authorized: 4,000,000 shares, issued: 3,836,397 shares
   383 383
Paid-in capital
   8,440 8,313
Retained earnings
   116,970 96,322
Treasury stock, at cost; 1,654,101 shares and 1,552,894 shares
   (51,473 ) (46,473 )


Total Stockholders’ Equity – PrimeEnergy
   74,320 58,545
Non-controlling interest
   8,384 7,335


Total Equity
   82,704 65,880


Total Liabilities and Equity
   $ 233,616 $ 214,654


	Three Months Ended June 30,						Six Months Ended June 30,
	2022			2021			2022			2021

Revenues

Oil sales	$	25,838		$	10,664		$	52,143		$	19,934
Natural gas sales		4,657			2,292			8,403			3,950
Natural gas liquids sales		4,422			2,404			8,273			4,149
Realized (loss) on derivative instruments, net		(5,888	)		(701	)		(9,707	)		(913	)
Field service income		3,736			2,375			6,976			3,800
Unrealized gain (loss) on derivative instruments, net		2,933			(5,057	)		(4,206	)		(5,968	)
Other income		—			—			29			29

Total Revenues		35,698			11,977			61,911			24,981
Costs and Expenses
Lease operating expense		9,213			4,434			17,934			8,901
Field service expense		3,540			1,837			6,540			3,255
Depreciation, depletion, amortization and accretion on discounted liabilities		7,021			6,610			14,199			13,107
General and administrative expense		2,418			2,184			9,090			4,200

Total Costs and Expenses		22,192			15,065			47,763			29,463
Gain on Sale and Exchange of Assets		845			106			14,836			106

Income (Loss) from Operations		14,351			(2,982	)		28,984			(4,376	)
Other Income (Expense)
Interest Expense		(150	)		(484	)		(499	)		(1,007	)

Income (Loss) Before Provision for (Benefit from) Income Taxes		14,201			(3,466	)		28,485			(5,383	)
(Benefit) Provision for Income Taxes		3,218			(1,054	)		6,360			(1,514	)

Net (Loss) Income		10,983			(2,412	)		22,125			(3,869	)
Less: Net (Loss) Attributable to Non-Controlling Interests		—			(9	)		—			(11	)

Net Income (Loss) Attributable to PrimeEnergy	$	10,983		$	(2,403	)	$	22,125		$	(3,858	)

Basic Income (Loss) Per Common Share	$	5.57		$	(1.20	)	$	11.18		$	(1.93	)

Diluted Income (Loss) Per Common Share	$	4.02		$	(1.20	)	$	8.08		$	(1.93	)

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

Table of Contents

PRIMEENERGY RESOURCES CORPORATION

C
ONDENSED
C
ONSOLIDATED
S~~TATEMENTS~~
TATEMENT

OF O~~PERATIONS~~

QUITY

– Unaudited

Six months Ended June 30, 2022 and 2021

(Thousands of ~~dollars, except per share amounts)~~

   Three Months Ended
September 30, Nine Months Ended
September 30,
   2017 2016 2017 2016
Revenues

Oil and gas sales
   $ 12,604 $ 11,557 $ 39,045 $ 27,395
Realized gain (loss) on derivative instruments, net
   156 —   (49 ) —
Field service income
   4,109 3,694 12,176 11,628
Administrative overhead fees
   1,530 1,600 4,758 4,990
Unrealized (loss) gain on derivative instruments, net
   (1,262 ) (354 ) 3,092 (354 )
Other income
   47 2 169 59


Total Revenues
   17,184 16,499 59,191 43,718
Costs and Expenses

Lease operating expense
   6,762 6,285 21,058 21,758
Field service expense
   3,126 2,662 9,152 9,582
Depreciation, depletion, amortization and accretion on discounted liabilities
   7,812 7,308 23,821 18,889
General and administrative expense
   2,523 2,405 6,878 6,685


Total Costs and Expenses
   20,223 18,660 60,909 56,914
Gain on Sale and Exchange of Assets
   359 10,546 42,078 26,869


(Loss) Income from Operations
   (2,680 ) 8,385 40,360 13,673
Less: Interest expense
   594 1,002 1,659 2,809


(Loss) Income Before Provision (Benefit) for Income Taxes
   (3,274 ) 7,383 38,701 10,864
(Benefit) Provision for Income Taxes
   (1,384 ) 2,667 12,407 3,036


Net (Loss) Income
   (1,890 ) 4,716 26,294 7,828
Less: Net Income (Loss) Attributable toNon-Controlling Interests
   122 (208 ) 5,646 2,239


(Loss) Income Attributable to PrimeEnergy
   $ (2,012 ) $ 4,924 $ 20,648 $ 5,589


Basic (Loss) Income Per Common Share
   $ (1.22 ) $ 2.15 $ 9.29 $ 2.44


Diluted (Loss) Income Per Common Share
   $ (1.22 ) $ 1.62 $ 6.94 $ 1.83

dollars)


	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, 2021		1,992,077		$	281	$	7,555	$	128,902		$	(37,647	)	$	99,091		$	—		$	99,091
Purchase 39,432 shares of Common stock		(39,432	)		—		—		—			(3,187	)		(3,187	)		—			(3,187	)
Net Income		—			—		—		22,125			—			22,125			—			22,125

Balance at June 30, 2022		1,952,645		$	281	$	7,555	$	151,027		$	(40,834	)	$	118,029		$	—		$	118,029

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

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

Table of Contents

PRIMEENERGY RESOURCES CORPORATION

C
ONDENSED
C
ONSOLIDATED
S
TATEMENTS
OF
C~~OMPREHENSIVE~~ I~~NCOME~~

ASH

LOWS

– Unaudited

~~Nine~~

Six Months Ended ~~September~~June 30, ~~2017~~2022 and ~~2016~~

2021

(Thousands of dollars)

   2017 2016
Net Income
   $ 26,294 $ 7,828
Other Comprehensive Income, net of taxes:

Changes in fair value of hedge positions, net of taxes of $0 and $(2), respectively
   —   5


Total other comprehensive income
   —   5


Comprehensive Income
   26,294 7,833
Less: Comprehensive Income Attributable toNon-Controlling Interest
   (5,646 ) (2,239 )


Comprehensive Income Attributable to PrimeEnergy
   $ 20,648 $ 5,594


	2022			2021


Cash Flows from Operating Activities:
Net Income (loss)	$	22,125		$	(3,869	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities		14,199			13,107
Gain on sale and exchange of assets		(14,836	)		(106	)
Unrealized loss on derivative instruments, net		4,206			5,968
Deferred income taxes		6,285			(1,514	)
Changes in assets and liabilities:
Accounts receivable		(3,443	)		(3,022	)
Due to related parties		(40	)		(38	)
Prepaids and other assets		251			(939	)
Accounts payable		(927	)		3,327
Accrued liabilities		(340	)		(1,490	)

Net Cash Provided by Operating Activities		27,480			11,424

Cash Flows from Investing Activities:
Capital expenditures, including exploration expense		(2,409	)		(3,729	)
Proceeds from sale of properties and equipment		14,836			106

Net Cash Provided by (Used in) Investing Activities		12,427			(3,623	)

Cash Flows from Financing Activities:
Purchase of stock for treasury		(3,187	)		—
Proceeds from long-term bank debt and other long-term obligations		—			3,000
Repayment of long-term bank debt and other long-term obligations		(36,000	)		(8,000	)

Net Cash Used in Financing Activities		(39,187	)		(5,000	)

Net Increase in Cash and Cash Equivalents		720			2,801
Cash and Cash Equivalents at the Beginning of the Period		10,347			996

Cash and Cash Equivalents at the End of the Period	$	11,067		$	3,797

Supplemental Disclosures:
Income taxes paid	$	75		$	—
Interest paid	$	481		$	1,009

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

Table of Contents

PRIMEENERGY RESOURCES CORPORATION

N
OTES
TO
C
ONDENSED
C
ONSOLIDATED
F
INANCIAL
S~~TATEMENT~~OF E~~QUITY~~ ~~– Unaudited~~

~~Nine Months Ended September~~

TATEMENTS

June 30, ~~2017~~

~~(Thousands of dollars)~~

   Common Stock
Additional
Paid in
   Retained    Treasury
Total
Stockholders’
Equity –

Non-
Controlling
Total
   Shares    Amount    Capital    Earnings    Stock PrimeEnergy Interest Equity
Balance at December 31, 2016
   3,836,397    $ 383    $ 8,313    $ 96,322    $ (46,473 ) $ 58,545 $ 7,335 $ 65,880
Repurchase 101,207 shares of common stock
   —      —      —      —      (5,000 ) (5,000 ) —   (5,000 )
Net income
   —      —      —      20,648    —   20,648 5,646 26,294
Repurchase ofnon-controlling interests
   —      —      127    —      —   127 (187 ) (60 )
Distribution ofnon-controlling interests
   —      —      —      —      —   —   (4,410 ) (4,410 )










Balance at September 30, 2017
   3,836,397    $ 383    $ 8,440    $ 116,970    $ (51,473 ) $ 74,320 $ 8,384 $ 82,704

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

~~PRIMEENERGY CORPORATION~~

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

~~Nine Months Ended September 30, 2017 and 2016~~

~~(Thousands of dollars)~~

   2017 2016
Cash Flows from Operating Activities:

Net income
   $ 26,294 $ 7,828
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, depletion, amortization and accretion on discounted liabilities
   23,821 18,889
Gain on sale and exchange of assets
   (42,078 ) (26,869 )
Unrealized (gain) loss on derivative instruments, net
   (3,092 ) 354
Provision for deferred income taxes
   10,425 1,648
Changes in assets and liabilities:

(Increase) decrease in accounts receivable
   (2,922 ) 2,009
(Increase) in other current assets and restricted cash
   (1,164 ) (612 )
Increase (decrease) in accounts payable
   1,337 (2,497 )
Increase in accrued liabilities
   8,771 4,188
Increase in due to related parties
   31 22


Net Cash Provided by Operating Activities
   21,423 4,960


Cash Flows from Investing Activities:

Capital expenditures, including exploration expense
   (40,057 ) (11,701 )
Proceeds from sale of property and equipment
   46,977 28,238


Net Cash Provided by (Used in) Investing Activities
   6,920 16,537


Cash Flows from Financing Activities:

Purchase of stock for treasury
   (5,000 ) (509 )
Purchase ofnon-controlling interests
   (60 ) (187 )
Proceeds from long-term bank debt and other long-term obligations
   52,000 9,000
Repayment of long-term bank debt and other long-term obligations
   (67,521 ) (33,311 )
Distributions tonon-controlling interests
   (4,410 ) (843 )


Net Cash Used in Financing Activities
   (24,991 ) (25,850 )


Net Increase (Decrease) in Cash and Cash Equivalents
   3,352 (4,353 )
Cash and Cash Equivalents at the Beginning of the Period
   6,568 9,750


Cash and Cash Equivalents at the End of the Period
   $ 9,920 $ 5,397


Supplemental Disclosures:

Income taxes paid
   $ 2,588 $ 45
Interest paid
   $ 1,762 $ 2,798

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

~~PRIMEENERGY CORPORATION~~

N~~OTES~~ TO C~~ONDENSED~~ C~~ONSOLIDATED~~ F~~INANCIAL~~ S~~TATEMENTS~~

~~September 30, 2017~~

~~(Unaudited)~~

2022

(1) Basis of Presentation:

The accompanying condensed consolidated financial statements of PrimeEnergy Resources Corporation (“~~PEC”~~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, ~~2016.~~2021. In the opinion of management, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the Company’s condensed consolidated balance sheets as of ~~September~~June 30, ~~2017~~2022 and December 31, ~~2016,~~2021, the condensed consolidated results of operations, ~~for the three and nine months ended September 30, 2017 and 2016, and the condensed consolidated results of~~ cash flows and equity for the ~~nine~~

six

months ended ~~September~~June 30, ~~2017.~~2022 and 2021.

As of June 30, 2022, 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, 2021. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the condensed consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.

~~Recently Issued Accounting Pronouncements:~~

~~The FASB issued ASU2014-09,~~~~Revenue from Contracts with Customers (Topic 606)~~~~. This ASU supersedes the~~~~Revenue recognition~~ ~~requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic932-605.~~ ~~Extractivies – Oil and Gas Revenue Recognition.~~This ASU provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The effective date for ASU~~2014-09~~ ~~was delayed through the issuance of ASU2015-14,~~~~Revenue from Contracts with Customers~~ ~~– Deferral of the~~~~Effective Date,~~to annual and interim periods beginning in 2018 and is required to be adopted using either the retrospective or cumulative effect (modified retrospective) transition method, with early adoption permitted in 2017. The Company is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures and does not plan on early adopting.

~~The FASB issued ASU2016-02,~~~~Leases (Topic 842).~~ ~~This ASU requires lessee recognition on the balance sheet of aright-of-use~~ asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Finally, it requires classification of all cash payments within operating activities in the statement of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. This ASU will not have a material impact on the Company’s financial statements and related disclosures.

~~In August 2016, the FASB issued Accounting Standards Update (ASU)2016-15,~~ ~~Statement of Cash Flows (Topic 230). ASU2016-15~~ seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of ASU~~2016-15~~ ~~and assessing the impact, if any, it may have on its statement of consolidated cash flows.~~

~~In January 2017, the FASB issued ASUNo. 2017-03,~~ Accounting Changes and Error Corrections (Topic 250) and Investments—Equity Method and Joint Venture (Topic 323), which states that registrants should consider additional qualitative disclosures if the impact of an issued but not yet adopted ASU is unknown or cannot be reasonably estimated and to include a description of the effect of the accounting policies that the registrant expects to apply, if determined. Transition guidance in certain issued but not yet adopted ASUs, including Leases and Revenue Recognition, was also updated to reflect this amendment. This guidance is effective immediately. The adoption of this guidance had no effect on the Company’s financial statements.

(2) Acquisitions and ~~Dispositions:~~

~~Historically~~Dispositions

In the first quarter of 2022, the Company ~~has repurchased~~sold 1,809 net leasehold acres in Reagan and Midland Counties, Texas through two separate transactions receiving gross proceeds of $14.0 million.

In the ~~interests~~second quarter 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~~2022, the Company ~~as general partner and as managing trustee, respectively. The Company purchased such interests~~sold 241 net acres in ~~amounts totaling $60,000 and $187,000~~Canadian County, Oklahoma for ~~the nine months ended September 30, 2017 and 2016, respectively.~~

~~During the nine months ended September 30, 2017, The Company sold or farmed out interests in certainnon-core~~ undeveloped oil and natural gas properties through a number of separate individually negotiated transactions in exchange for cash and a royalty or working interest in West Texas, New Mexico and Oklahoma. Proceeds under these agreements were $47 million.

During the nine months of 2017, the Company acquired approximately 118 net mineral acres for $596,000 adjacent to existing Company acreage in order to facilitate the drilling of future horizontal wells.

$845,000

(3) ~~Restricted Cash and Cash Equivalents:~~

Restricted cash and cash equivalents include $4.19 million and $3.54 million at September 30, 2017 and December 31, 2016, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at September 30, 2017 and December 31, 2016 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the accompanying condensed consolidated balance sheets.

~~(4)~~ Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

(Thousands of dollars)    September 30,
2017    December 31,
2016
Accounts Receivable:

Joint interest billing
   $ 2,886    $ 2,345
Trade receivables
   1,354    1,070
Oil and gas sales
   6,087    4,078
Other
   207    204




   10,534    7,697
Less: Allowance for doubtful accounts
   (212 )    (297 )




Total
   $ 10,322    $ 7,400




Accounts Payable:

Trade
   $ 5,273    $ 3,967
Royalty and other owners
   7,174    6,501
Prepaid drilling deposits
   67    83
Other
   788    1,414




Total
   $ 13,302    $ 11,965




Accrued Liabilities:

Compensation and related expenses
   $ 2,887    $ 2,295
Property costs
   12,133    3,317
Income Tax
   1,366    1,988
Other
   569    584




Total
   $ 16,955    $ 8,184

~~(5) Property and Equipment:~~

~~Property and equipment at September 30, 2017 and December 31, 2016 consisted~~


(Thousands of dollars)	June 30, 2022			December 31, 2021


Accounts Receivable :
Joint interest billing	$	2,975		$	1,902
Trade receivables		1,638			1,429
Oil and gas sales		12,454			11,154
Other		955			94

		18,022			14,579
Less: Allowance for doubtful accounts		(371	)		(371	)

Total	$	17,651		$	14,208

Accounts Payable:
Trade	$	2,991		$	2,390
Royalty and other owners		2,246			2,802
Partner advances		1,062			1,209
Other		56			881

Total	$	6,355		$	7,282

Accrued Liabilities:
Compensation and related expenses	$	4,367		$	3,919
Property costs		2,216			2,901
Taxes		813			893
Other		85			108

Total	$	7,481		$	7,821

Table of ~~the following:~~

(Thousands of dollars)    September 30,
2017    December 31,
2016
Proved oil and gas properties, at cost
   $ 452,400    $ 417,821
Less: Accumulated depletion and depreciation
   (251,995 )    (230,331 )




Oil and Gas Properties, Net
   $ 200,405    $ 187,490




Field and office equipment
   $ 26,586    $ 26,902
Less: Accumulated depreciation
   (19,079 )    (18,024 )




Field and Office Equipment, Net
   $ 7,507    $ 8,878




Total Property and Equipment, Net
   $ 207,912    $ 196,368

6)Contents

(4) Long-Term Debt:

Bank Debt:

Effective July 30, 2010 the Company entered into a Second Amended and Restated Credit Agreement between Compass Bank as agent and a syndicated group of lenders (“Credit Agreement”). The Credit Agreement had a revolving line of credit and letter of credit facility of up to $250 million with a final maturity date of July 30, 2017. The credit facility was secured by substantially all of the Company’s oil and gas properties. The credit facility was subject to a borrowing base determined by the lenders taking into consideration the estimated value of PEC’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans.

On February 15, 2017, the Company and its lenders entered into a Third Amended and Restated Credit Agreement (the ~~“ 2017~~“2017 Credit Agreement”) with a maturity date of February 15, 2021. ~~The Second Amended and Restated Credit Agreement and subsequent amendments were amended and restated by the 2017 Credit Agreement. Pursuant to the terms and conditions of~~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. ~~As of September 30, 2017, the Company’s borrowing base was $67 million.~~ 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 and interest coverage~~ ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships.

~~At September 30,~~

On December 20, 2021 the company entered into a Seventh Amendment to the 2017 Credit Agreement and Citibank N.A was appointed as successor administrative agent replacing PNC Bank. Under this amendment the ~~Company had a total of $49.8 million of borrowings outstanding~~Company’s borrowing base is $50 million. Borrowings under ~~its revolving credit facility~~the 2017 Credit Agreement will bear interest at alternate base rate (ABR) plus an applicable margin ranging from 2.00% to 3.00% or at the Company’s option, at a ~~weighted-average interest~~ rate equal to the secured overnight financing rate (SOFR rate) as administered by the SOFR Administrator, in this case the Federal Reserve Bank of ~~4.67%~~New York, plus an applicable margin ranging from 3.00% to 4.00%. The 2017 Credit Agreement matures February 11, 2023. The current borrowing base review and ~~$17.2 million available for future borrowings. The combined weighted average interest rate paid~~maturity extension was completed on ~~outstanding bank borrowings subject to base rate and LIBO interest was 4.98% for the nine months ended September 30, 2017 as compared to 3.83% for the nine months ended September 30, 2016.~~July 5, 2022. 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, 2022, the Company had no borrowings outstanding under its revolving credit facility and $50 million was available for future borrowings. The ~~Company entered into~~combined weighted average interest rate ~~hedge agreements~~paid on outstanding bank borrowings subject to ~~help manage~~ABR base rate and SOFR interest ~~rate exposure. These contracts include interest rate swaps. Interest rate swap transactions generally involve~~was 5.98% for the ~~exchange of fixed and floating rate interest payment obligations without~~six months ended June 30, 2022 as compared to 5.31% for the ~~exchange of the underlying principal amounts. In~~six months ended June 30, 2021.

On July ~~2012,~~5, 2022 , the Company ~~entered into interest swap agreements for a period of two years, which commenced in January 2014, related to $75 million of the Company’s bank debt resulting in a LIBO fixed rate of 0.563%~~ and ~~terminated in January 2016. The Company recorded interest expense and paid $7,000 related to the settlement of interest rate swaps for the nine months ended September 30, 2016.~~

~~Equipment Loans:~~

~~On July 31, 2013, the Company~~its lenders entered into a ~~$10.0 million Loan~~Fourth Amended and ~~Security~~Restated Credit Agreement ~~with JP Morgan Chase Bank (“Equipment Loan”~~(the “2022 Credit Agreement”). The Equipment Loan is secured by a portion of the Company’s field service equipment, carries an interest rate of 3.95% per annum, requires monthly payments (principal and interest) of $184,000, and has a final maturity date of July 31, 2018. As of September 30, 2017, the Company had a total of $1.80 million outstanding on this Equipment Loan.

On July 29, 2014, the Company entered into additional equipment financing facilities (“Additional Equipment Loans”) totaling $6.0 million with JP Morgan Chase Bank. In August 2014, the Company drew down $4.8 million of this facility that is secured by field service equipment, carries an interest rate of 3.40% per annum, requires monthly payments (principal and interest) of $87,800, and has a final maturity date of July 31, 2019. The remaining $1.2 million under the Additional Equipment Loans was available for interim draws to finance the acquisition of any future field service equipment. In December 2014, the Company made an interim draw of an additional $0.5 million on this facility that is secured by recently purchased field service equipment. Interim draws on this facility carried a floating interest rate, payable monthly at the LIBO published rate plus 2.50% and on June 26, 2015 converted into a fixed term loan, with a ~~rate of 3.50% and requiring monthly payments (principal and interest) of $8,700 with a final~~ maturity date of June ~~26, 2020.~~ 1, 2026. Under the 2022 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 initial borrowing base of the agreement is $75 million. The credit facility is secured by substantially all of the Company’s oil and gas properties. The 2022 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, and commodity hedge agreements.

As of ~~September 30, 2017,~~August 15, 2022 the Company ~~had a total of $2.14 million~~has 0 borrowings outstanding ~~on the Additional Equipment Loans.~~

The Company determined these loans are Level 3 liabilities in the fair-value hierarchy and estimated their fair value as $3,941 million and $6,958 million at September 30, 2017 and 2016, respectively, using a discounted cash flow model.

~~(7)~~under its current revolving credit facility.

(5) Other Long-Term Obligations and Commitments:

Operating Leases:

The Company ~~hasnon-cancelable~~leases office facilities under operating leases ~~primarily~~and recognizes lease expense on a straight-line basis over the lease term. Leased assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. A new finance lease for ~~rental~~office equipment is included in property and equipment, other current liabilities and other long-term liabilities this quarter. As most of 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, 2022 was $306 thousand. Cash payments included in the operating lease cost for the six months ended June 30, 2022 was $324 thousand. The weighted-average remaining operating lease terms is 9 months.

The Company amended certain leases for office space ~~that have a term~~in Texas providing for payments of ~~more than one year. The future minimum lease payments for the rest of fiscal 2017~~$349,000 in 2022, $251,000 in 2023, $106,000 in 2024 and ~~thereafter for the operating leases are as follows:~~

(Thousands of dollars)    Operating
Leases
2017
   141
2018
   525


Total minimum payments
   $ 666

$27,000 in 2025.

Rent expense for office space six months ended June 30, 2022 and 2021 was $392,000 and $328,000, respectively.

Table of Contents

The payment schedule for the ~~nine months ended September~~Company’s operating lease obligations as of June 30, ~~2017 and 2016 was $509,000 and $677,000, respectively.~~

2022 is as follows:

(Thousands of dollars)

Operating

Leases

2022    $ 349
2023    $ 251
2024    $ 106
2025    27

Total undiscounted lease payments    $ 733
Less: Amount associated with discounting    (66 )

Net operating lease liabilities    $ 667

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the ~~nine~~

six

months ended ~~September~~June 30, ~~2017~~2022 is as follows:

(Thousands of dollars)
Asset retirement obligation – December 31, 2016
   $ 17,505
Liabilities incurred
   45
Liabilities settled
   (409 )
Accretion expense
   576


Asset retirement obligation – September 30, 2017
   $ 17,717


(Thousands of dollars)	June 30, 2022

Asset retirement obligation at December 31, 2021	$	14,295
Liabilities settled		(835	)
Accretion expense		339

Asset retirement obligation at June 30, 2022	$	13,799

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.

~~(8)~~

(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. At September 30, 2017, the affiliated Partnerships have established cash reserves in excess of their debts and liabilities and the Company believes these reserves will be sufficient to satisfy Partnership 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.

~~(9)~~

(7) Stock Options and Other Compensation:

In May 1989,

non-statutory

stock options were granted by the Company to ~~four~~4 key executive officers for the purchase of shares of common stock. At ~~September~~June 30, ~~2017~~2022 and ~~2016,~~2021, 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.

~~(10)~~

(8) Related Party Transactions:

The Company, as managing general partner or managing trustee, makes an annual offer to repurchase the interests of the partners and trust unit holders in certain of the Partnerships or Trusts. The Company purchased such interests in amounts totaling $60,000 and $187,000 for the nine months ended September 30, 2017 and 2016, respectively.

Receivables from related parties consist of reimbursable general and administrative costs, lease operating expenses and reimbursement for property development and related costs. These receivables are due from joint venture partners, which may include members of the Company’s Board of Directors.

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

~~(11).~~

Table of Contents

(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 ~~September~~June 30, ~~2017~~2022 and December 31, ~~2016:~~

September 30, 2017
   Quoted Prices in
Active Markets
For Identical
Assets (Level 1)    Significant
Other
Observable
Inputs (Level 2)    Significant
Unobservable
Inputs (Level 3)    Balance at
September 30,
2017
(Thousands of dollars)
Assets

Commodity derivative contracts
   $ —      $ —      $ 131    $ 131








Total assets
   $ —      $ —      $ 131    $ 131








Liabilities

Commodity derivative contracts
   $ —      $ —      $ (621 )    $ (621 )








Total liabilities
   $ —      $ —      $ (621 )    $ (621 )

December 31, 2016
   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,
2016
(Thousands of dollars)
Assets

Commodity derivative contracts
   $ —      $ —      $ 57    $ 57








Total assets
   $ —      $ —      $ 57    $ 57








Liabilities

Commodity derivative contract
   $ —      $ —      $ (3,639 )    $ (3,639 )








Total liabilities
   $ —      $ —      $ (3,639 )    $ (3,639 )

2021:


June 30, 2022	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, 2022
(Thousands of dollars)
Assets

Commodity derivative contracts	$	—	$	—	$	—		$	—

Total assets	$	—	$	—	$	—		$	—

Liabilities
Commodity derivative contracts	$	—	$	—	$	(9,791	)	$	(9,791	)

Total liabilities	$	—	$	—	$	(9,791	)	$	(9,791	)


December 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 December 31, 2021
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	—		$	—

Total assets	$	—	$	—	$	—		$	—

Liabilities

Total liabilities	$	—	$	—	$	(5,585	)	$	(5,585	)

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.

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 six months ended ~~September~~June 30, ~~2017.~~

(Thousands of dollars)
Net Liabilities – December 31, 2016
   $ (3,582 )
Total realized and unrealized (gains) losses:

Included in earnings (a)
   3043
Purchases, sales, issuances and settlements
   49


Net Liabilities – September 30, 2017
   $ (490 )

2022.


(Thousands of dollars)
Net Liabilities – December 31, 2021	$	(5,585	)
Total realized and unrealized (gains) losses:
Included in earnings (a)		(13,913	)
Purchases, sales, issuances and settlements		9,707

Net Liabilities — June 30, 2022	$	(9,791	)

a)(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, and interest rate swap instruments are reported as an increase or reduction to interest expense.~~instruments.

Table of Contents

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~~commodity-based derivatives. Both realized and unrealized gains and losses associated with commodity derivative instruments are recognized in earnings.

Interest rate swap derivatives are treated as cash-flow hedges and are used to fix our floating interest rates on existing debt. Settlements of the swaps, which began in January 2014 and concluded in January 2016, was recognized within interest expense. There were no remaining interest rate swaps as of September 30, 2017 and December 31, 2016.The value of interest rate swaps if applicable, would be recorded in accumulated other comprehensive loss, net of tax.

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at ~~September~~June 30, ~~2017~~2022 and December 31, ~~2016:~~

      Fair Value
(Thousands of dollars)
Balance Sheet Location
   September 30,
2017    December 31,
2016
Asset Derivatives:

Derivatives not designated as cash-flow hedging instruments:

Crude oil commodity contracts
   Other Current Assets    $ 12    $ —
Natural gas commodity contracts
   Other Current Assets    94    —
Crude oil commodity contracts
   Other Assets    19    —
Natural gas commodity contracts
   Other Assets    6    57




Total
      $ 131    $ 57




Liability Derivatives:

Derivatives not designated as cash-flow hedging instruments:

Crude oil commodity contracts
   Derivative liability short-term    (88 )    (1,065 )
Natural gas commodity contracts
   Derivative liability short-term    (204 )    (1,482 )
Natural gas commodity contracts
   Derivative liability long-term    (254 )    (463 )
Crude oil commodity contracts
   Derivative liability long-term    (75 )    (629 )




Total
      $ (621 )    $ (3,639 )




Total derivative instruments
      $ (490 )    $ (3,582 )

2021:


		Fair Value
(Thousands of dollars)	Balance Sheet Location	June 30, 2022			December 31, 2021
Liability Derivatives:
Derivatives not designated as cash-flow hedging instruments:

Crude oil commodity contracts	Derivative liability short-term	$	(7,722	)	$	(3,992	)
Natural gas commodity contracts	Derivative liability short-term		(2,069	)		(943	)
Crude oil commodity contracts	Derivative liability long-term		—			(490	)
Natural gas commodity contracts	Derivative liability long-term		—			(160	)

Total derivative instruments		$	(9,791	)	$	(5,585	)

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the ~~nine month periods~~six months ended ~~September~~June 30, ~~2017~~2022 and ~~2016:~~

      Amount of gain/loss
recognized in income
(Thousands of dollars)

Location of gain/loss recognized in income
   2017    2016
Derivative designated as cash-flow hedge instruments:

Interest rate swap contracts
   Interest expense    $ —      $ (7 )
Derivatives not designated as cash-flow hedge instruments:

Natural gas commodity contracts

Unrealized (loss) gain on derivative instruments, net
   1,709    —
Crude oil commodity contracts

Unrealized (loss) gain on derivative instruments, net
   1,383    —
Natural gas commodity contracts

Realized gain (loss) on derivative instruments, net
   (130 )    —
Crude oil commodity contracts

Realized gain (loss) on derivative instruments, net
   81    —




      $ 3,043    $ (7 )

~~(12)~~2021:


	Location of gain/loss recognized in income	Amount of gain/loss recognized in income
(Thousands of dollars)	Location of gain/loss recognized in income	2022			2021


Derivatives not designated as cash- flow hedge instruments:
Natural gas commodity contracts	Unrealized (loss) on derivative instruments, net	$	(966	)	$	(1,085	)
Crude oil commodity contracts	Unrealized (loss) on derivative instruments, net		(3,240	)		(4,883	)
Natural gas commodity contracts	Realized (loss) on derivative instruments, net		(1,986	)		(277	)
Crude oil commodity contracts	Realized (loss) on derivative instruments, net		(7,721	)		(636	)

		$	(13,913	)	$	(6,681	)

Table of Contents

(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:

   Nine Months Ended September 30,
   2017 2016
   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
   $ 20,648 2,223,399    $ 9.29 $ 5,589    2,294,444    $ 2.44
Effect of dilutive securities:

Options
   750,731    —      751,357







Diluted
   $ 20,648 2,974,130    $ 6.94 $ 5,589    3,045,801    $ 1.83







   Three Months Ended September 30,
   2017 2016
   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
   $ (2,012 ) 1,642,933    $ (1.22 ) $ 4,924    2,293,964    $ 2.15
Effect of dilutive securities:

Options (a)
   —   —         753,594







Diluted
   $ (2,012 ) 1,642,933    $ (1.22 ) $ 4,924    3,047,558    $ 1.62


	Six Months Ended June 30,
	2022						2021
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Loss (In 000’s)			Weighted Average Number of Shares Outstanding		Per Share Amount




Basic	$	22,125		1,979,690	$	11.18	$	(3,858	)		1,994,177	$	(1.93	)
Effect of dilutive securities:
Options (a)		—		756,879				—			—

Diluted	$	22,125		2,736,569	$	8.08	$	(3,858	)		1,994,177	$	(1.93	)


	Three Months Ended June 30,
	2022						2021
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Loss (In 000’s)			Weighted Average Number of Shares Outstanding		Per Share Amount

Basic	$	10,983		1,972,979	$	5.57	$	(2,403	)		1,994,177	$	(1.20	)
Effect of dilutive securities:
Options (a)		—		757,185				—			—

Diluted	$	10,983		2,730,164	$	4.02	$	(2,403	)		1,994,177	$	(1.20	)

(a)	The effect of the 767,500 outstanding stock options is ~~antidilutive from~~anti-dilutive for the three and six months ended ~~September~~June 30, ~~2017~~2021 due to the net loss ~~reported~~ for ~~the period.~~these periods.

Table of Contents

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

OVERVIEW

We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas. We presently own producing and

non-producing

properties located primarily in Texas, ~~Oklahoma,~~and Oklahoma. We also own a 12.5% over-riding royalty interest in over 30,000 acres in the state of West ~~Virginia, New Mexico, and Colorado.~~Virginia. In addition, we own a substantial amount of ~~well servicing equipment.~~well-servicing equipment and, through a wholly owned offshore company, a

60-mile-long

pipeline offshore on the shallow shelf of Texas. We also hold a 30% interest in a limited partnership which owns a 138,000 square foot retail shopping center on ten acres in Prattville, Alabama. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential.

We are the operator of the majority of our developed and undeveloped acreage which is nearly all held by production. In the Permian Basin of West Texas and eastern New Mexico the Company maintains an acreage position of over 21,160 gross (12,742 net) acres, approximately 92% of which is 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, Wolfcamp and other intervals for additional horizontal drilling that could support the drilling potential in excess of 400 additional horizontal wells. In Oklahoma we maintain an acreage position of approximately 82,572 gross (12,980 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 2,231 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 75 new horizontal wells based on an estimate of only two wells per section, per formation ( Woodford & Mississippian ), with our ~~share of such prospective future development being about $42 million based on an average 10.5% ownership level.~~

~~Our~~ balanced portfolio of assets ~~positions~~position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash ~~flows~~ generated from our operations ~~through~~and our ~~producing~~credit facility.

In addition to developing our oil and natural gas ~~properties, our field services business, and from sales ofnon-core~~ ~~acreage.~~

~~The Company will~~reserves, we continue to actively pursue the acquisition of ~~leasehold acreage and~~ producing ~~properties in areas where we currently operate and believe there is additional exploration and development potential and will~~properties. We attempt to assume the position of operator in all ~~such acquisitions. In order~~acquisitions of producing properties and will continue to evaluate properties for leasehold acquisition and for exploration and development operations in areas in which we own interests. 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~~income-producing assets ~~so as~~or developable leasehold acreage to build stockholder value through consistent growth inand development of our oil and gas reserve base on a ~~cost-efficient~~cost-effective basis.

Our cash flows depend on many factors, including the price of oil and gas, the ~~level~~success of our acquisition ~~disposition~~ and drilling activities, and the operational performance of our producing properties. We ~~may~~ use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements.

~~RECENT ACTIVITIES~~

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 17,228 gross (10,720 net) acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current West Texas horizontal drilling activities are 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 47,760 gross (10,410 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 5,800 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 50 new horizontal wells based on an estimate of four wells per multi-section drilling unit, two in the Mississippian and two in the Woodford Shale. Should we choose to participate with a working interest in future development, our share of these future capital expenditures would be approximately $34.6 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 reserves and well information as of December 31, 2021.


	Gulf Coast		Mid- Continent		West Texas		Other		Total
Proved Reserves as of December 31, 2021 (MBoe)
Developed		906		2,383		8,957		6		12,252
Undeveloped		—		—		—		—		—
Total		906		2,383		8,957		6		12,252
Average Net Daily Production (Boe per day)		336		747		2,878		3		3,964
Gross Productive Wells (Working Interest and ORRI Wells)		207		549		576		200		1,532
Gross Productive Wells (Working Interest Only)		189		400		530		88		1,207
Net Productive Wells (Working Interest Only)		105		189		263		6		564
Gross Operated Productive Wells		137		195		321		—		653
Gross Operated Water Disposal, Injection and Supply wells		7		44		6		—		57

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 activities in the Gulf Coast region are primarily production and development of our existing operated properties concentrated in east and 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. As of December 31, 2021, we had 207 producing wells (105 net) in the Gulf Coast region, of which 137 wells are operated by us. The Average net daily production in our Gulf Coast Region in 2021 was 336 Boe. At December 31, 2021, we had 906 MBoe of proved reserves in the Gulf Coast region, which represented 7% of our total proved reserves. We maintain an acreage position of over 11,000 gross (3,447 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, twenty-three 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. The Company also owns, through its wholly owned offshore company, a

60-mile-long

pipeline on the shallow shelf of Texas that is currently idle, but may someday have value. As of June 30, 2022, 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, 2021, we had 549 producing wells (189 net) in the

Mid-Continent

area, of which 195 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 2021 was 747 Boe. At December 31, 2021, we had 2,383 MBoe of proved reserves in the

Mid-Continent

area, representing 20% of our total proved reserves. We maintain an acreage position of approximately 47,760 gross (10,410 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 interests in several counties in the Stack and Scoop plays of Oklahoma where drilling primarily targets reservoirs of the Mississippian and Woodford formations.

In the first half of 2022, in the

Mid-Continent

region, the Company participated with 9.38% interest in the drilling of four horizontal wells in Canadian County, Oklahoma operated by Ovintiv

Mid-Continent

Inc. All four wells have been completed and are online as of August 1

. The resulting reserves of this new drilling will be an addition to our 2021

year-end

reserve base.

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West Texas Region

Our West Texas activities are concentrated in the Spraberry and Wolfcamp shale plays of the Permian Basin encompassing eight counties in West Texas. The oil produced from these shales is West Texas Intermediate Sweet and the gas is primarily casing-head gas with an average energy content of 1,400 Btu. The horizontal target depths range from 7,600 feet to 12,500 feet. This region is managed from our office in Midland, Texas.

As of December 31, 2021, we had 576 wells (263 net) in the West Texas area, of which 321 wells are operated by us. Average net daily production in Our West Texas Region in 2021 was 2,878 Boe. At December 31, 2021, we had 8,957 MBoe of proved reserves in the West Texas area, or 73% of our total proved reserves. We maintain an acreage position of approximately 17,228 gross (10,720 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.

In the first half of 2022, the Company participated with 10.3% interest in the drilling of four

1.5-mile-long

horizontal wells in Irion County, Texas operated by SEM Operating Company, LLC. All four wells have been drilled and completed and are expected to start production in August of 2022.

In addition to the eight wells drilled in the first half of 2022, the Company has received proposals for 24 new horizontal wells in West Texas: fifteen planned for the second half of 2022 and eleven for the first quarter of 2023. In the fourth quarter of this year, we expect to participate with 27% interest in the drilling of five

2.5-mile-long

horizontal wells in Martin County, Texas with ConocoPhillips and to participate with 25% interest in the drilling of ten

2-mile-long

horizontals with Hibernia Energy III, LLC. In the first quarter of 2023, we anticipate the start of nine

2.5-mile-long

horizontals with BTA Oil Producers, LLC in Reagan County, and two

3-mile-long

horizontals with Apache Corporation in Upton County. The Company will participate with an average of approximately 42% interest in the BTA wells and 47% in the Apache wells. These proved undeveloped drilling plans were added in 2022 and therefore are not represented in the

year-end

2021 reserves report.

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, 2021. 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. 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)
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
2021		5,386		2,882		23,902		12,252		—		—		—		—		5,386		2,882		23,902		12,252

(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.

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In 2019, in West Texas, we participated in the initial three shallow horizontals on our Kashmir tract with one of each of these wells completed in the Wolfcamp “A”, Jo Mill, and Lower Spraberry. The Company has 48% interest in two of these wells and 5.3% in one well. All three wells were brought on production in May of 2019.

In 2020, in West Texas we participated in the drilling of seven wells: one for 8.6% interest which was brought into production in July of 2020, and six wells with an average 47.5% interest that were drilled but not completed at

year-end

and therefore classified as Proved Undeveloped in the

year-end

reserve report. The Company invested approximately $8.0 million in these seven wells in 2020. Also in 2020, proved producing reserves were added in West Texas through the addition of 11 horizontal wells completed in Midland County, Texas, in which we receive 0.56% to 1% over-riding royalty interest.

In 2021, in West Texas, we participated with Apache in the drilling of three additional horizontals on the Kashmir Tract in Upton County, Texas and completed these three wells in September of 2021 along with six other wells drilled in 2020 on the same lease that were drilled but uncompleted at

year-end

2020. The Company has an average of 47.8% interest in these nine wells and invested approximately $30 million in these horizontal wells.

In our Oklahoma, Scoop-Stack play, in 2019, we participated in the drilling and completion of six wells on our WM Wallace tract for 7.67% interest, and nine wells, included on our Slash, Osborn, and Leon tracts, with an average 1.34% interest. In addition, three wells drilled in Oklahoma in 2018, were completed in 2019 converting 24 Mboe of reserves to proved developed. Also in Oklahoma, six wells designated as

Shut-in

on December 31, 2018, were brought into production in 2019: five located on our Ruthie tract, and one on our Braum tract.

In 2019, in our Gulf Coast region, we added production through the recompletion of three vertical wells in Polk County, Texas: one operated by the Company in which we have 72.5% interest, and two operated by Unit Petroleum in which the Company owns 2.81% working interest and 3.77% net revenue interest. In 2020, the Company successfully recompleted one additional operated well in the Segno field with a 72.5% interest.

At December 31, 2020, in total, the Company had 3,221 Mboe of proved undeveloped reserves attributable to 13 wells operated by others, 10 of which were drilled but not completed by

year-end

2020, and three that were not drilled until 2021. The three new horizontals along with the six uncompleted wells at

year-end

were brought online in late September and early October of 2021. These successful new wells are on our Kashmir tract in Upton County, Texas operated by Apache Corporation. These nine PUD wells at

year-end

2020 accounted for 3,127 Mboe of the total undeveloped reserves where the Company has an average 47.5% interest and invested approximately $30 million dollars in these wells. The four other PUD wells, drilled but not completed at

year-end

2020, are located in Grady County, Oklahoma and accounted for 95 Mboe of the total undeveloped reserves.

At December 31, 2021, the Company had 159 Mboe of proved developed

shut-in

reserves attributable to three horizontal wells drilled and completed in Canadian County, Oklahoma in December of 2021, but not yet online. Three of the four wells were successfully completed and online in January, 2022, while one well had completion issues and has been temporarily abandoned. Regarding the four drilled but uncompleted PUD wells in Grady County, Oklahoma noted in the paragraph above, reserves previously attributed to these wells were not included in the 2021

year-end

reserve report as the operator has no near-term plans for their completion.

In the first half of 2022, in our West Texas horizontal drilling program, ~~which began~~we participated with 10.3% interest in ~~2015, currently includes a~~the drilling of four horizontal wells with SEM Operating Company and have received proposals for an additional 24 horizontal wells, 15 of those to begin in the fourth quarter of this year. In total, the Company is likely to invest approximately $75 million in these 28 wells. In Oklahoma, thus far in 2022, the Company is participating for 9.38% interest with Ovintiv

Mid-Continent

in the drilling of 28four wells on our Bohlman tract in Canadian County, Oklahoma. These four wells and the four SEM wells in West Texas are anticipated to be online in August of this year. In the first quarter of 2023, we intent to participate with Apache in the drilling of two

3-mile-long

horizontals in Upton County, Texas and with BTA Oil Producers in the drilling of nine 2.5 mile-long horizontals in Reagan County, Texas. 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 ~~were drilled, completed~~have been demonstrated to provide consistent results capable of repetition. The technologies and ~~placed~~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.

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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, 2021, 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
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
2021	$	275,227	$	171,906	$	—	$	—	$	275,227	$	171,906	$	36,100	$	135,806

The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. We use this measure when assessing the potential return on investment related to oil and gas properties. The PV10 of future income taxes represents the sole reconciling item between this

non-GAAP

PV10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.

“Proved developed” oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. “Proved undeveloped” oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Our reserves include amounts attributable to

non-controlling

interests in the Partnerships. These interests represent less than 10% of our reserves.

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

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

Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $3.598 per MMBtu in 2021 as compared to $1.985 per MMBtu in 2020, and $2.581 per MMBtu in 2019. Oil prices, based on the NYMEX first of the month average price, were $66.56 per barrel in 2021 as compared to $39.57 per barrel in 2020, and $55.69 per barrel in 2019. Since January 1, 2021, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.

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.

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Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. In 2022, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our capital budget for the year 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 the third quarter ~~2017. This program positioned~~of 2021, nine

two-mile

horizontal wells in Upton County, Texas, operated by Apache Corporation, were completed and ~~Martin~~brought into production. In the fourth quarter of 2021, three

two-mile

horizontal wells operated by Ovintiv

Mid-Continent

in Canadian County, ~~offsets~~Oklahoma were completed and brought online in January 2022. The Company has an average of 47.5% interest in the nine wells completed with Apache and 11.25% interest in the three wells completed with Ovintiv.

Through the second quarter of 2022, the Company has participated with SEM Operating Company LLC in the drilling of four 7,900’ horizontal wells in Irion County, Texas with 10.3% interest, and participated with Ovintiv

Mid-Continent

Inc in the drilling of four 10,000’-long horizontal wells in Canadian County, Oklahoma with 9.38% interest. All eight of these wells are in the process of being completed and are expected to be producing in August of this year. An additional 15 wells are planned to begin development in the fourth quarter of 2022; five with ConocoPhillips, and ten with Hibernia Energy III. In the first quarter of 2023, we are planning the drilling of two ~~large Pioneer Natural Resources developments, Giddings Ranch~~horizontals in Upton County, Texas, with Apache Corporation and ~~Sales Ranch~~nine horizontals with BTA Oil Producers in ~~Martin.~~

Reagan County, Texas.

Since the start of our West Texas horizontal drilling program in 2015, we have participated in 81 wells and invested approximately $130 million in horizontal drilling in the Permian Basin. This includes the four wells currently in progress with SEM Operating Company in Irion County, Texas.

In Upton County, Texas, we are developing a contiguous ~~3,900~~3,260 acre block with our joint venture partner, Apache ~~Corporation, where~~Corporation. In this block the Company ~~holds approximately 48%~~has 2,600 leasehold acres with interest between 14% and 56% depending on the particular lease and depth being developed. In 2018, eight successful wells were drilled horizontally by Apache Corporation in ~~2,606 gross acres. Through~~ the ~~end~~Wolfcamp “B” of this block with the Company participating for 49% interest and this is believed to be full development of the ~~third quarter 2017, 16 wells~~Wolfcamp “B” reservoir. Together with Apache, we are planning development of the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs of this block. These shallower reservoirs have been ~~drilled, completed and placed~~

proven-up

on ~~production. During the fourth quarter of 2017, an~~our offset 1,300 acre Kashmir tract. It is expected that as many as 54 additional 12 wells (Company ownership between 31% and 38%) were drilled and brought online. There are also 6 additional wells with 1% or less ownership that are currently being drilled, completed, or are awaiting hydraulic fracture. Apache drilling plans indicate 5 additional wellshorizontals will be ~~spud~~developed on this 3,260 acres in the near future. This development is estimated to cost approximately $370.6 million, with the Company’s share being approximately $170.8 million. Two

3-mile-long

horizontals have been slated for the first quarter of ~~2018~~2023. In addition to the 54 prospective wells to be drilled for these three reservoirs, a fourth target reservoir, the Middle Spraberry, is also prospective for future development. The potential of the Middle Spraberry on the 3,260 acre block is for 18 horizontal wells to be drilled and completed at a gross cost of ~~$40~~approximately $126.3 million ~~of which our~~with the Company’s share isbeing approximately $17 million. Apache has begun pad drilling of the acreage and future development is anticipated to result in approximately 80 additional horizontal wells being drilled at a cost of about $616 million. We own various interests ranging from 14% to 49% in the lands to be developed in this project and expect our share of these capital expenditures to be approximately $171$61.8 million. The ~~total~~actual number of wells that ~~will be~~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 has also been developing an offsetting 1,300 acre block in Upton County, Texas, with Apache Corporation as operator. In the second quarter of 2019 three horizontal wells were completed and brought on ~~drilling schedule~~production from reservoirs above the Middle Wolfcamp: one in the Wolfcamp “A”, one in the Jo Mill, and ~~commodity prices.~~

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 additional horizontals followed and were completed in the third quarter of 2021. Our average 47.5% share of the cost of these nine horizontal wells was approximately $26.7 million in total. In ~~Martin County,~~addition to the Wolfcamp “A”, Jo Mill and Lower Spraberry, that are now considered fully developed on the tract, 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 ~~960~~965 acre block with ~~RSP Permian~~ConocoPhillips in Martin County, Texas. In 2016 and ~~the~~2017, four horizontal wells were drilled, completed, and put on production. The Company owns ~~from~~ 35% to 38% ~~interest. Through~~interest in this joint venture acreage where we have potential to drill as many as 36 additional wells.

As mentioned above, in West Texas, the ~~end~~Company is participating for 10.3% interest with SEM Operating Company in four 7,900’-long horizontal wells in Irion County, Texas. We anticipate an investment of $2.55 million in these wells and for them to begin production in August. Also planned for this year is the drilling of ten

2-mile-long

horizontals in Hibernia Energy, III, LLC, in Reagan County, Texas and the drilling of five 2.5 mile long horizontal wells with ConocoPhillips in Martin County. The Company intends to participate for approximately 25% interest in the ten wells with Hibernia and for 27% interest in the five wells with Connoco Phillips. Our expected investment in the drilling and completion of these wells is $32 million.

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In Oklahoma, we are focused on development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 5,800 net leasehold acres in the Scoop/Stack Play. In 2019, we participated for an average of 4.6% interest with Newfield Exploration in twelve successful wells in Canadian County on our Slash and Wallace tracts. In 2021, we participated for 11.25% interest with Ovintiv

Mid-Continent

Inc. in four wells on our Peters tract, in Canadian County. Three of these wells were successfully completed in December 2021 and online in January 2022, while one well had completion issues and has been temporarily abandoned. At today’s product prices, payout of the ~~third quarter 2017, 4~~Company’s $2.3 million investment in these four wells occurred in four months.

In April 2022, in Oklahoma, the Company and Ovintiv

Mid-Continent

began drilling four horizontal wells on our Bohlman tract in the same area as the successful Peters wells. All four of the Bohlman wells have been drilled, completed, and placed on production. Further development plans for this acreage have not been received from RSP at this time. In addition to the development with RSP, the Company has also participated with Crownquest Operating in 15 wells in which Company ownership is less than 1%. Eight of the wells have been drilled and put on production and the remaining 7 are ~~currently being drilled, completed, or are awaiting hydraulic fracture.~~

~~Once all wells are on production, our current West Texas horizontal drilling program will consist of 58 wells.~~

~~In Eddy County, New Mexico, the Company term assigned 80 net mineral acres for $400,000, retaining an overriding royalty on future horizontal development.~~

Our Oklahoma horizontal development program, which began in 2012, has, through the third quarter of 2017, participated in 26 horizontal wells for approximately $26 million. Over this same time period the Company chose to retain an overriding royalty interest in 26 other horizontal wells. Through the third quarter of 2017, we participated in 2 horizontal wells that have been placed on production:flowing back. The Company ~~participated~~is participating with ~~19.7%~~9.38% interest with an approximate investment $2.2 million

We believe our 5,800 net leasehold acres in Oklahoma have the resource potential to support the drilling of aas many as 50 new horizontal ~~well~~wells based on an estimate of four wells per multi-section drilling unit: two in ~~Canadian County operated by Devon Energy that spud~~the Mississippian and two in ~~November~~the Woodford Shale. Should we choose to participate in future development, our share of 2016 and was placed on production in early April 2017. The Company also participated with 11.5% interest in a horizontal well drilled by Marathon Oil Company in Kingfisher County that was spud in February of 2017 and put on production in early June 2017. The Company is currently participating in 2 wells drilled in Grady County, with approximately 10% interest in a well operated by Linn Operating, Inc. drilled in June 2017 but not yet completed and 1% in a well operated by Citizen Energy II LLC. which were drilled in May 2017 but are not yet completed. The total cost for these 2 wells will be about $14,700,000 and the ~~Company’s share will~~capital expenditures would be approximately ~~$826,000. The Company is also participating in a horizontal well in Garvin County operated by Rimrock Resource Operating in which~~$34.6 million at an average 10% ownership level; the Company has approximately 6.25% interest with an expected net cost of $621,000, this well was drilled in July 2017 and treated in September 2017 but not yet producing. In addition, we have elected to retain an overridingwill otherwise sell its rights for cash, or cash plus a royalty interest in 2 horizontal wells drilled. The first well drilled by White Star Petroleum in Garfield County, retained 3.1% ORRI, drilled in November 2016 and put on production in February 2017 and second well drilled by Chaparral Energy Corp. in Garfield County, retained 0.325% overriding royalty interest, drilled in May 2017 and put on production in July 2017.

or working interest.

RESULTS OF OPERATIONS

~~2017~~

2022 and ~~2016~~2021 Compared

We reported a net ~~loss~~income of $22.1 million, or $11.18 per share and $11 million, or $5.57 per share for the six and three months ended ~~September~~June 30, ~~2017 of $2.0 million, or $1.22 per share and a net income for the nine months ended September 30, 2017 of $20.6 million, or $9.29 per share,~~2022, respectively, as compared to net ~~income~~losses of ~~$4.9~~$3.9 million, or ~~$2.15~~$1.93 per share and ~~$5.6~~$2.4 million, or ~~$2.44~~$1.20 per share for the ~~three~~six and ~~nine~~three months ended ~~September~~June 30, ~~2016,~~2021, respectively. Current year net income reflects ~~an increase~~increases in ~~oil~~ production ~~combined with increased~~and commodity ~~prices~~price increases over the ~~nine~~three and six months ended ~~September~~June 30, ~~2017 combined with~~2021, fluctuations in gains related to the sale of ~~acreage during~~assets and changes related to the ~~nine months ended September 2017.~~valuation of derivative instruments. The significant components of income and expense are discussed below.

Oil, gas and ~~gas~~NGLs sales

increased ~~$1.0~~$19.6 million, or ~~9.1%~~127.3% from ~~$11.6~~$15.4 million for the three months ended ~~September~~June 30, ~~2016~~2021 to ~~$12.6~~$34.9 million for the three months ended ~~September~~June 30, ~~2017~~2022, and ~~increased $11.6~~$40.8 million, or ~~42.5%~~145.5% from ~~$27.4~~$28.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2021 to ~~$39.0~~$68.8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017. Crude oil and natural gas sales vary due to changes in volumes~~2022.

Table of ~~production sold and realized commodity prices.~~

Our realized prices at the well head increased an average of $3.20 per barrel, or 7.6% and $8.86 per barrel, or 23.5%, on crude oil during the three and nine months ended September 30, 2017, respectively from the same periods in 2016 while our average well head price for natural gas increased $0.26 per mcf, or 9.1% and $0.87 per mcf, or 35.2% during the three and nine months ended September 30, 2017, respectively from the same periods in 2016.

Our crude oil production decreased by 9,000 barrels or 4.5% from 199,000 barrels for the third quarter 2016 to 190,000 barrels for the third quarter 2017 and increased by 80,000 barrels, or 15.77% from 511,000 barrels for the nine months ended September 30, 2016 to 591,000 barrels for the nine months ended September 30, 2017. Our natural gas production increased by 170,000 mcf, or 15.1% from 1,124,000 mcf for the third quarter 2016 to 1,294,000 mcf for the third quarter 2017 and increased by 158,000 mcf, or 4.8% from 3,308,000 mcf for the nine months ended September 30, 2016 to 3,466,000 mcf for the nine months ended September 30, 2017. The changes in crude oil and natural gas production volumes reflect the natural decline of the previously existing properties, offset by production from new wells added in late 2016 and the first half of 2017. Production from our horizontal wells in West Texas was shut in during the ladder half of the third quarter of 2017 to facilitate the completion operations on our offset leases of fourteen new horizontal wells which came on line during the fourth quarter. We also experienced some shut-ins of our Gulf Coast production due to hurricane Harvey during the third quarter.

Contents

The following ~~table~~tables summarizes the primary components of production volumes and average sales prices realized for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 and ~~2016~~2021 (excluding realized gains and losses from derivatives).

   Three Months Ended September 30, Nine Months Ended September 30,
   2017    2016    Increase /
(Decrease) 2017    2016    Increase /
(Decrease)
Barrels of Oil Produced
   190,000    199,000    (9,000 ) 591,000    511,000    80,000
Average Price Received
   $ 45.09    $ 41.89    $ 3.20 $ 46.50    $ 37.64    $ 8.86









Oil Revenue (In 000’s)
   $ 8,568    $ 8,337    $ 231 $ 27,479    $ 19,233    $ 8,246
Mcf of Gas Produced
   1,294,000    1,124,000    170,000 3,466,000    3,308,000    158,000
Average Price Received
   $ 3.12    $ 2.86    $ 0.26 $ 3.34    $ 2.47    $ 0.87









Gas Revenue (In 000’s)
   $ 4,037    $ 3,220    $ 817 $ 11,567    $ 8,162    $ 3,405










Total Oil & Gas Revenue (In 000’s)
   $ 12,605    $ 11,557    $ 1,048 $ 39,046    $ 27,395    $ 11,651

~~Realized gain (loss) on derivative instruments, net~~ ~~include net gains of $81 thousand~~


			Six months ended June 30,
	2022		2021		Increase / (Decrease)		Increase / (Decrease)
Barrels of Oil Produced		508,000		328,000		180,000		54.9	%
Average Price Received	$	102.64	$	60.77	$	41.87		68.9	%

Oil Revenue (In 000’s)	$	52,143	$	19,934	$	32,209		161.6	%

Mcf of Gas Sold		1,577,000		1,445,000		132,000		9.1	%
Average Price Received	$	5.35	$	2.73	$	2.62		96	%

Gas Revenue (In 000’s)	$	8,403	$	3,950	$	4,453		112.7	%

Barrels of Natural Gas Liquids Sold		210,000		195,000		15,000		7.7	%
Average Price Received	$	39.40	$	21.28	$	18.12		85.2	%

Natural Gas Liquids Revenue (In 000’s)	$	8,273	$	4,149	$	4,124		99.4	%

Total Oil & Gas Revenue (In 000’s)	$	68,819	$	28,033	$	40,786		145.5	%


			Three months ended June 30,
	2022		2021		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Produced		235,000		165,000		70,000			42.4	%
Average Price Received	$	109.95	$	64.63	$	45.32			70.1	%

Oil Revenue (In 000’s)	$	25,838	$	10,664	$	15,174			142.3	%

Mcf of Gas Sold		800,000		780,000		20,000			2.6	%
Average Price Received	$	5.86	$	2.94	$	2.92			99.3	%

Gas Revenue (In 000’s)	$	4,657	$	2,292	$	2,365			103.2	%

Barrels of Natural Gas Liquids Sold		106,000		109,000		(3,000	)		(2.8	)%
Average Price Received	$	41.72	$	22.06	$	19.66			89.1	%

Natural Gas Liquids Revenue (In 000’s)	$	4,422	$	2,404	$	2,018			83.9	%

Total Oil & Gas Revenue (In 000’s)	$	34,917	$	15,360	$	19,557			127.3	%

Oil, Natural Gas and $75 thousand on the settlements of crude oil and natural gas derivatives, respectively for the third quarter 2017. Realized gain (loss) on derivative instruments include net gains of $81 thousand and net losses of $130 thousand on the settlements of crude oil and natural gas derivatives, respectively for the nine months ended September 30, 2017. No such gains or losses were realized in 2016.

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. ~~During~~The following table summarizes the ~~three and nine months ended September 30, 2017, we recognized net unrealized losses~~results of $143 thousand and net unrealized gains of $1.80 million, respectively associated with natural gas fixed swap contracts and net unrealized losses of $1.12 million and net unrealized gains of $1.38 million, respectively associated with crude oil fixed swaps due to market fluctuations in natural gas and crude oil futures market prices between December 31, 2016 and September 30, 2017. No such gains were recognized in 2016.

~~There were no swaps in place related to the three and nine months ended September 30, 2016. Oil and gas prices received~~our derivative instruments for the three and ~~nine~~six months ended ~~September~~June 2022 and 2021:


	Three Months Ended June 30,						Six Months Ended June 30,
	2022			2021			2022			2021
				($ in thousand)
Oil derivatives – realized losses	$	(4,522	)	$	(484	)	$	(7,721	)	$	(636	)
Oil derivatives – unrealized gains (losses)		1,951			(3,987	)		(3,240	)		(4,883	)

Total losses on oil derivatives	$	(2,571	)	$	(4,471	)	$	(10,961	)	$	(5,519	)

Natural gas derivatives – realized losses	$	(1,366	)	$	(217	)	$	(1,986	)	$	(277	)
Natural gas derivatives – unrealized gains (losses)		982			(1,070	)		(966	)		(1,085	)

Total losses on natural gas derivatives	$	(384	)	$	(1,287	)	$	(2,952	)	$	(1,362	)

Total losses on oil and natural gas derivatives	$	(2,955	)	$	(5,758	)	$	(13,913	)	$	(6,881	)

Table of Contents

Prices received for the six months ended June 30, ~~2017~~2022 and 2021, respectively, including the impact of derivatives were:

   Three Months Ended
September 30, 2017    Nine Months Ended
September 30, 2017
Oil Price
   $ 45.52    $ 46.63
Gas Price
   $ 3.18    $ 3.30

2022

2021

Oil Price
   $ 87.44    $ 58.84
Gas Price
   $ 4.09    $ 2.54
NGLS Price
   $ 39.40    $ 21.28

Field service income

increased ~~$0.4~~$1.3 million or ~~11.2%~~54.2% from $2.4 million for the second quarter 2021 to $3.7 million for the ~~third~~second quarter ~~2016 to $4.1~~2022 and increased $3.2 million, or 84.2% from $3.8 million for the ~~third quarter 2017 and $0.5 million, or 4.7% from $11.6~~six months ended June 30, 2021 to $7.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016 to $12.2 million for~~2022. These changes reflect the ~~nine months ended September 30, 2017.~~increase in utilization and rates resulting from the oil and gas price increases during these periods. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations, and working rates have increased between the periods in our most active districts. The increase in revenues from these services has been supplemented by increases in our salt water disposal revenues.

operations.

Lease operating expense

increased ~~$0.5~~$4.8 million or ~~7.6%~~109.1% from ~~$6.3~~$4.4 million for the ~~third~~second quarter 2016 to $6.7 million for the third quarter 2017 and decreased $0.7 million, or 3.2% from $21.8 million for the nine months ended September 30, 2016 to $21.0 million for the nine months ended September 30, 2017. This decrease is primarily due to reductions in costs in our marginal fields including personnel cut backs and decreased vendor services offset by increased production taxes related to increased oil and natural gas prices during 2017 as compared to the same periods of 2016.

~~Field service expense~~ increased $0.4 million, or 17.4% from $2.7 million for the third quarter 2016 to $3.1 million for the third quarter 2017 and decreased $0.4 million, or 4.5% from $9.58 million for the nine months ended September 30, 20162021 to $9.2 million for the ~~nine~~second quarter 2022 and increased $9.0 million or 101.1% from $8.9 million for the six months ended ~~September~~June 30, ~~2017.~~2021 to $17.9 million for the six months ended June 30, 2022. This increase is primarily due to higher production taxes related to higher commodity prices during 2022 combined with workover expenses and lease operating expense related to higher lifting cost properties returned to production.

Field service expense

increased $1.7 million or 94.4% from $1.8 million for the second quarter 2021 to $3.5 million for the second quarter 2022 and increased $3.2 million, or 97.0% from $3.3 million for the six months ended June 30, 2021 to $6.5 million for the six months ended June 30, 2022. Field service expenses primarily consist of wages and vehicle operating expenses which have ~~trended upward~~fluctuated during the ~~nine~~three and six months ended ~~September~~June 30, ~~2017~~2022 compared with the same periods of 2021. These changes reflect the increase in utilization and rates resulting from the ~~same period of 2016 as a direct result of~~oil and gas price increases ~~in hourly wage rates and hours, and utilization of the operating equipment in West Texas.~~

during these periods.

Depreciation, depletion, amortization and accretion on discounted liabilities

increased ~~$0.5~~$0.4 million, or ~~6.9%~~6.1% from ~~$7.3~~$6.6 million for the ~~third~~second quarter ~~2016~~2021 to ~~$7.8~~$7.0 million for the ~~third~~second quarter ~~2017~~2022 and $1.1 million, or 8.4% from $13.1 million for the six months ended June 30, 2021 to $14.2 million for the six months ended June 30, 2022. These increases reflect the change in the property basis combined with production increases in 2022.

General and administrative expense

increased $4.9 million, or ~~26.1%~~116.7% from ~~$18.9~~$4.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2021 to ~~$23.8~~$9.1 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017 reflecting the increased production during 2017 as compared to the same periods of 2016~~2022, and ~~the increase capital cost base of recently drilled and completed wells.~~

~~General and administrative expense~~ increased $0.2 million, or ~~2.9%~~9.1% from ~~$6.7~~$2.2 million for the ~~nine~~three months ended ~~September~~June 30, ~~2016~~2021 to ~~$6.9 million for the nine months ended September 30, 2017, and $0.1 million, or 4.9% from~~ $2.4 million for the three months ended ~~September~~June 30, ~~2016~~2022. This increase in 2022 is primarily due to ~~$2.5~~increased employee compensation and benefits.

Interest expense

decreased from $500 thousand for the second quarter 2021 to $150 thousand for the second quarter 2022 and from $1.0 million for the ~~three~~six months ended ~~September~~June 30, ~~2017. The largest component of these personnel costs are salaries and employee related taxes and insurance with quarterly variances due~~2021 to ~~the reimbursement of administrative expenses associated with property activities during the period.~~

~~Gain on sale and exchange of assets~~ ~~of $42.1 million and $26.9 million~~$499 thousand for the ~~nine~~six months ended ~~September~~June 30, ~~2017 and September 30, 2016, respectively consists of sales of non-essential oil and gas interests and field service equipment.~~

~~Interest expense~~ decreased from $1.10 million for the third quarter 2016 to $0.6 million for the third quarter 2017 and from $2.8 million for the nine months ended September 30, 2016 to $1.7 million for the nine months ended September 30, 2017.2022. This decrease reflects the ~~reduction~~increase in rates and lower current borrowings under our revolving credit agreement.

Income tax ~~provision~~~~of $12.4 million was recorded~~ benefit

for the ~~nine months ended September~~June 30, ~~2017 versus a tax provision of $3 million for the nine months ended September 30, 2016. Our provision for income taxes can vary from the federal statutory tax rate of 34% primarily~~2022 and 2021 periods varied due to ~~state taxes and percentage depletion deductions. We are entitled to percentage depletion on certain of our wells, which is calculated without reference to~~ the ~~basis of the property. To the extent that such depletion exceeds a property’s basis, it creates a permanent difference, which would have the effect of lowering our effective rate.~~

change in net income or loss for those periods.

LIQUIDITY AND CAPITAL RESOURCES

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2022, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2022 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.

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

Net cash provided by ~~our~~ operating activities and proceeds from the sale of properties for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 was ~~$21.4~~$42.3 million, compared to ~~$5.0~~$11.5 million ~~for~~in the ~~nine months ended September 30, 2016.~~ prior year.

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.~~

control7.

Table of Contents

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

~~We currently maintain~~

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


	2022		2023		2022		2023
Swap Agreements
Natural Gas (MMBTU)		591,000		254,000	$	2.95	$	3.60
Oil (barrels)		168,900		70,700	$	61.66	$	69.50

In the first quarter of 2022, the Company participated in the drilling of four wells with SEM Operating Company in Irion County, Texas for 10.3% interest and in April of this year began participating with Ovintiv

Mid-Continent

in four wells in Canadian County, Oklahoma with 9.38% interest. These eight wells have been completed and are expected to be on production in August of this year. In addition, the Company has received drilling proposals for an additional 24 horizontal wells to be drilled in West Texas with 15 of these slated to begin drilling this year. In total the Company is likely to invest approximately $77 million in these 32 wells. 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~~facility.

The Company maintains a Credit Agreement providing for a reserves-based line of credit totaling $300 million, with a current borrowing base of ~~$67~~$75 million. As of ~~September 30, 2017, The~~August 15, 2022, the Company has ~~$49.8 million in~~no outstanding ~~borrowings.~~borrowings under this line. The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a ~~redetermined~~

re-determined

estimate of proved oil and gas reserves. The next borrowing base review is scheduled for ~~November 2017.~~December 2022. 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 ~~credit~~ agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the ~~redetermined~~

re-determined

borrowing base.

~~Our credit agreement required us to hedge~~

In the first quarter of 2022, the Company sold 1,809 net leasehold acres in Regan and Midland Counties, Texas through two transactions receiving gross proceeds of $14.0 million and retaining certain over-riding royalty interests.

In the second quarter of 2022, the Company sold 241 net acres in Canadian County, Oklahoma for proceeds of $845,000 and a ~~portion~~retained over-riding royalty interest.

The majority of our ~~production forecasted for as PDP reserves in~~capital spending is discretionary, and the ultimate level of expenditures will be dependent on our ~~borrowing base review engineering report. Accordingly~~assessment of the ~~Company has in place the following swap agreements for~~ oil and ~~natural gas.~~

      Monthly Hedge Volumes    Price
   Year    BBLs    MMBTU    BBLs    MMBTU
October through December
   2017    14,300    235,000    $ 50.10    $ 3.11
January through June
   2018    11,900    200,000    $ 52.02    $ 2.97
July through December
   2018    23,900    200,000    $ 51.91    $ 2.97
January through March
   2019    12,500    130,000    $ 50.75    $ 3.12
April through June
   2019    35,000    60,000    $ 48.80    $ 2.66
July through September
   2019    35,000    60,000    $ 50.73    $ 2.77
October through December
   2019    35,000    —      $ 50.39    $ —

~~Maintaining a strong balance sheet~~gas business environment, the number and ~~ample liquidity are key components~~quality of ~~our~~oil and gas prospects available, the market for oilfield services, and oil and gas business strategy. For 2017, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2017 capital budget is reflective of current commodity prices andopportunities in general.

The Company has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity we may adjust our capital program throughout the year, divest~~non-strategic~~ assets, or enter into strategic joint ventures. We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit facility should our borrowing base become limited due to the deterioration of commodity prices.

~~We have in place both~~ a stock repurchase program ~~and a limited partnership interest~~in place, spending under this program during the first six months of 2022 was $3.2 million. The Company expects continued spending under the stock repurchase program ~~under which we expect to continue spending during 2017. For the nine month period ended September 30, 2017, we have spent $5,060,000 million under these programs.~~

in 2022.

Table of Contents

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 toRules

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 ~~controls~~control over financial reporting that occurred during the ~~nine~~first six months ~~ended September 30, 2017~~of 2022 that have materially affected, or are reasonably likely to materially affect, the Company’s internal ~~controls~~control over financial reporting.

Table of Contents

PART II—OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS

None.

Item 1A.

RISK FACTORS

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

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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

~~During the nine months ended September 30, 2017, the Company purchased the following shares of common stock as treasury shares.~~

2017 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
   101    $ 54.05    236,946
February
   140    $ 57.25    236,806
March
   251    $ 49.55    236,555
April
   85,033    $ 49.98    151,522
May
   2,242    $ 41.12    149,280
June
   5,057    $ 46.80    144,223
July
   1,274    $ 48.31    142,949
August
   49    $ 47.39    142,900
September
   7,060    $ 47.02    135,840





Total/Average
   101,207    $ 49.41


2022 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		2,981	$	76.21		144,740
February		5,948	$	73.26		138,792
March		2,259	$	75.36		136,533
April		3,426	$	74.82		133,107
May		5,963	$	82.37		127,144
June		18,855	$	85.18		108,289

Total/Average		39,432	$	80.82

(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 ~~3,500,000~~3,700,000 shares have been authorized, to date, under this program. Through ~~September~~June 30, ~~2017,~~2022, a total of ~~3,364,160~~3,593,811 shares have been repurchased under this program for ~~$60,130,382~~$78,266,619 at an average price of ~~$17.87~~$ 21.78 per share. Additional purchases of shares may occur as market conditions warrant. We expect future purchases will be funded with internally generated cash flow or from working capital.

Item 3.

DEFAULTS UPON SENIOR SECURITIES

None

Item 4.

RESERVED

Item 5.

OTHER INFORMATION

None

Table of Contents

Item 6.

EXHIBITS

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


Exhibit No.

3.1		~~Restated~~ Certificate of Incorporation of PrimeEnergy Resources Corporation, ~~(effective July 1, 2009) (Incorporated by reference to~~as amended and restated of December 21, 2018, (filed as Exhibit 3.1 toof PrimeEnergy Resources Corporation Form~~10-Q~~ ~~for the quarter ended June 30, 2009)~~8-K on December 27, 2018, and incorporated herein by reference).

3.2		Bylaws of PrimeEnergy Resources Corporation as amended and restated as of ~~May 20, 2015~~April 24, 2020 (filed as Exhibit 3.2 of PrimeEnergy Resources Corporation Form8-K on ~~May 22, 2015~~April 27, 2020 and incorporated herein by reference).

10.18		Composite copy ofNon-Statutory Option Agreements (Incorporated by reference to Exhibit 10.18 of PrimeEnergy Resources Corporation Form10-K for the year ended December 31, 2004).

~~10.22.5.10~~10.22.6		FOURTH AMENDED AND RESTATED CREDIT AGREEMENT dated as of July 5, 2022, is among PRIMEENERGY RESOURCES CORPORATION, a Delaware corporation (the “Borrower”), each of the Lenders from time to time party hereto and CITIBANK, N.A. (in its individual capacity, “Citibank”), as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”).

14		~~Third Amended~~PrimeEnergy Resources Corporation Code of Business Conduct and ~~Restated Credit Agreement dated~~Ethics, as of February 15, 2017 among PrimeEnergy 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 Bookrunneramended December 16, 2011 (Incorporated by reference to Exhibit ~~10.22.5.10 to~~14 of PrimeEnergy Resources Corporation Form10-K for the year ended December 31, ~~2016).~~

~~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 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 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 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 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 Corporation Form10-Q~~ ~~for the quarter ended March 31, 2017).~~

~~10.22.5.15~~		Amended, Restated and Consolidated Mortgage of Oil and Gas Property, Security Agreement, Assignment of Production and Financing Statement Dated as of May 5, 2017 (Incorporated by reference to Exhibit 10.22.5.15 to PrimeEnergy Corporation Form~~10-Q~~ ~~for the quarter ended March 31, 2017).~~

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

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

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

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

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

~~Exhibit~~
~~No.~~
  ~~10.24.2~~ Business Purpose Promissory Note dated July 29, 2014, made by Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company to JP Morgan Chase Bank N.A. (Incorporated by reference to Exhibit 10.24.2 to PrimeEnergy Corporation Form~~10-Q~~ ~~for the quarter ended September 30, 2014).~~
  ~~10.24.3~~ ~~Guaranty dated July 29, 2014, made by PrimeEnergy Corporation in favor of JP Morgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.24.3 to PrimeEnergy Corporation Form10-Q~~ ~~for the quarter ended September 30, 2014).~~
  ~~10.25~~ ~~Purchase and Sale Agreement dated as of January 25, 2017, among PrimeEnergy Corporation, PrimeEnergy Management Corporation, PrimeEnergy Operating Company, PrimeEnergy Asset and Income Fund, L.P.A-2,~~ ~~PrimeEnergy Asset and Income Fund, L.P.A-3,~~ ~~PrimeEnergy Asset and Income Fund, L.P.AA-2,~~ ~~and PrimeEnergy Asset and Income Fund, L.P.AA-4,~~ ~~as Sellers and Guidon Operating LLC, as Purchaser (Incorporated by reference to Exhibit 10.25 to PrimeEnergy Corporation Form10-K~~ ~~for the year ended December 31, 2016)~~2011).
  31.1    Certification of Chief Executive Officer pursuant to Rule13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).
  31.2    Certification of Chief Financial Officer pursuant to Rule13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).
  32.1    Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
  32.2    Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
101.INS    Inline XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith)
101.SCH    Inline XBRL Taxonomy Extension Schema Document (filed herewith)
101.CAL    Inline XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith)
101.DEF    Inline XBRL Taxonomy Extension Definition Linkbase Document (filed herewith)
101.LAB    Inline XBRL Taxonomy Extension Label Linkbase Document (filed herewith)
101.PRE    Inline XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith)
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

Table of Contents

SIGNATURES

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


						PrimeEnergy Resources Corporation
						(Registrant)

~~November 17, 2017~~August 18, 2022						/s/ Charles E. Drimal, Jr.
(Date)						Charles E. Drimal, Jr.
						President
						Principal Executive Officer

~~November 17, 2017~~						/s/ Beverly A. Cummings
~~(Date)~~August 18, 2022						Beverly A. Cummings
						Executive Vice President
						Principal Financial Officer


	September 30, 2017			December 31, 2016
ASSETS
Current Assets
Cash and cash equivalents	$	9,920		$	6,568
Restricted cash and cash equivalents		4,193			3,543
Accounts receivable, net		10,322			7,400
Other current assets		1,086			572

Total Current Assets		25,521			18,083
Property and Equipment, at cost
Oil and gas properties (successful efforts method), net		200,405			187,490
Field and office equipment, net		7,507			8,878

Total Property and Equipment, Net		207,912			196,368
Other Assets		183			203

Total Assets	$	233,616		$	214,654

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	13,302		$	11,965
Accrued liabilities		16,955			8,184
Current portion of long-term debt		2,905			2,949
Current portion of asset retirement obligations		2,006			1,563
Derivative liability short-term		292			2,547
Due to related parties		31			—

Total Current Liabilities		35,491			27,208
Long-Term Bank Debt		50,840			66,316
Asset Retirement Obligations		15,711			15,943
Derivative Liability Long-Term		329			1,092
Deferred Income Taxes		47,925			37,500
Other Long-Term Obligations		616			715

Total Liabilities		150,912			148,774
Commitments and Contingencies
Equity
Common stock, $.10 par value; Authorized: 4,000,000 shares, issued: 3,836,397 shares		383			383
Paid-in capital		8,440			8,313
Retained earnings		116,970			96,322
Treasury stock, at cost; 1,654,101 shares and 1,552,894 shares		(51,473	)		(46,473	)

Total Stockholders’ Equity – PrimeEnergy		74,320			58,545
Non-controlling interest		8,384			7,335

Total Equity		82,704			65,880

Total Liabilities and Equity	$	233,616		$	214,654


	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues
Oil and gas sales	$	12,604		$	11,557		$	39,045		$	27,395
Realized gain (loss) on derivative instruments, net		156			—			(49	)		—
Field service income		4,109			3,694			12,176			11,628
Administrative overhead fees		1,530			1,600			4,758			4,990
Unrealized (loss) gain on derivative instruments, net		(1,262	)		(354	)		3,092			(354	)
Other income		47			2			169			59

Total Revenues		17,184			16,499			59,191			43,718
Costs and Expenses
Lease operating expense		6,762			6,285			21,058			21,758
Field service expense		3,126			2,662			9,152			9,582
Depreciation, depletion, amortization and accretion on discounted liabilities		7,812			7,308			23,821			18,889
General and administrative expense		2,523			2,405			6,878			6,685

Total Costs and Expenses		20,223			18,660			60,909			56,914
Gain on Sale and Exchange of Assets		359			10,546			42,078			26,869

(Loss) Income from Operations		(2,680	)		8,385			40,360			13,673
Less: Interest expense		594			1,002			1,659			2,809

(Loss) Income Before Provision (Benefit) for Income Taxes		(3,274	)		7,383			38,701			10,864
(Benefit) Provision for Income Taxes		(1,384	)		2,667			12,407			3,036

Net (Loss) Income		(1,890	)		4,716			26,294			7,828
Less: Net Income (Loss) Attributable toNon-Controlling Interests		122			(208	)		5,646			2,239

(Loss) Income Attributable to PrimeEnergy	$	(2,012	)	$	4,924		$	20,648		$	5,589

Basic (Loss) Income Per Common Share	$	(1.22	)	$	2.15		$	9.29		$	2.44

Diluted (Loss) Income Per Common Share	$	(1.22	)	$	1.62		$	6.94		$	1.83


	Common Stock				Additional Paid in		Retained		Treasury			Total Stockholders’ Equity –			Non- Controlling			Total
	Shares		Amount		Capital		Earnings		Stock			PrimeEnergy			Interest			Equity
Balance at December 31, 2016		3,836,397	$	383	$	8,313	$	96,322	$	(46,473	)	$	58,545		$	7,335		$	65,880
Repurchase 101,207 shares of common stock		—		—		—		—		(5,000	)		(5,000	)		—			(5,000	)
Net income		—		—		—		20,648		—			20,648			5,646			26,294
Repurchase ofnon-controlling interests		—		—		127		—		—			127			(187	)		(60	)
Distribution ofnon-controlling interests		—		—		—		—		—			—			(4,410	)		(4,410	)

Balance at September 30, 2017		3,836,397	$	383	$	8,440	$	116,970	$	(51,473	)	$	74,320		$	8,384		$	82,704


(Thousands of dollars)	September 30, 2017			December 31, 2016
Accounts Receivable:
Joint interest billing	$	2,886		$	2,345
Trade receivables		1,354			1,070
Oil and gas sales		6,087			4,078
Other		207			204

		10,534			7,697
Less: Allowance for doubtful accounts		(212	)		(297	)

Total	$	10,322		$	7,400

Accounts Payable:
Trade	$	5,273		$	3,967
Royalty and other owners		7,174			6,501
Prepaid drilling deposits		67			83
Other		788			1,414

Total	$	13,302		$	11,965

Accrued Liabilities:
Compensation and related expenses	$	2,887		$	2,295
Property costs		12,133			3,317
Income Tax		1,366			1,988
Other		569			584

Total	$	16,955		$	8,184


(Thousands of dollars)	Operating Leases
2017		141
2018		525

Total minimum payments	$	666


(Thousands of dollars)	Operating Leases

2022	$	349
2023	$	251
2024	$	106
2025		27

Total undiscounted lease payments	$	733
Less: Amount associated with discounting		(66	)

Net operating lease liabilities	$	667


(Thousands of dollars)
Asset retirement obligation – December 31, 2016	$	17,505
Liabilities incurred		45
Liabilities settled		(409	)
Accretion expense		576

Asset retirement obligation – September 30, 2017	$	17,717


September 30, 2017	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at September 30, 2017
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	131		$	131

Total assets	$	—	$	—	$	131		$	131

Liabilities
Commodity derivative contracts	$	—	$	—	$	(621	)	$	(621	)

Total liabilities	$	—	$	—	$	(621	)	$	(621	)


December 31, 2016	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, 2016
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	57		$	57

Total assets	$	—	$	—	$	57		$	57

Liabilities
Commodity derivative contract	$	—	$	—	$	(3,639	)	$	(3,639	)

Total liabilities	$	—	$	—	$	(3,639	)	$	(3,639	)


(Thousands of dollars)
Net Liabilities – December 31, 2016	$	(3,582	)
Total realized and unrealized (gains) losses:
Included in earnings (a)		3043
Purchases, sales, issuances and settlements		49

Net Liabilities – September 30, 2017	$	(490	)


	Nine Months Ended September 30,
	2017								2016
	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	$	20,648			2,223,399	$	9.29		$	5,589		2,294,444	$	2.44
Effect of dilutive securities:
Options					750,731					—		751,357

Diluted	$	20,648			2,974,130	$	6.94		$	5,589		3,045,801	$	1.83


	Three Months Ended September 30,
	2017								2016
	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	$	(2,012	)		1,642,933	$	(1.22	)	$	4,924		2,293,964	$	2.15
Effect of dilutive securities:
Options (a)		—			—							753,594

Diluted	$	(2,012	)		1,642,933	$	(1.22	)	$	4,924		3,047,558	$	1.62


	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017
Oil Price	$	45.52	$	46.63
Gas Price	$	3.18	$	3.30


			Monthly Hedge Volumes				Price
	Year		BBLs		MMBTU		BBLs		MMBTU
October through December		2017		14,300		235,000	$	50.10	$	3.11
January through June		2018		11,900		200,000	$	52.02	$	2.97
July through December		2018		23,900		200,000	$	51.91	$	2.97
January through March		2019		12,500		130,000	$	50.75	$	3.12
April through June		2019		35,000		60,000	$	48.80	$	2.66
July through September		2019		35,000		60,000	$	50.73	$	2.77
October through December		2019		35,000		—	$	50.39	$	—


2017 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		101	$	54.05		236,946
February		140	$	57.25		236,806
March		251	$	49.55		236,555
April		85,033	$	49.98		151,522
May		2,242	$	41.12		149,280
June		5,057	$	46.80		144,223
July		1,274	$	48.31		142,949
August		49	$	47.39		142,900
September		7,060	$	47.02		135,840

Total/Average		101,207	$	49.41


~~Exhibit~~ ~~No.~~

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

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

~~10.25~~		~~Purchase and Sale Agreement dated as of January 25, 2017, among PrimeEnergy Corporation, PrimeEnergy Management Corporation, PrimeEnergy Operating Company, PrimeEnergy Asset and Income Fund, L.P.A-2,~~ ~~PrimeEnergy Asset and Income Fund, L.P.A-3,~~ ~~PrimeEnergy Asset and Income Fund, L.P.AA-2,~~ ~~and PrimeEnergy Asset and Income Fund, L.P.AA-4,~~ ~~as Sellers and Guidon Operating LLC, as Purchaser (Incorporated by reference to Exhibit 10.25 to PrimeEnergy Corporation Form10-K~~ ~~for the year ended December 31, 2016)~~2011).

31.1		Certification of Chief Executive Officer pursuant to Rule13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).

31.2		Certification of Chief Financial Officer pursuant to Rule13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

101.INS		Inline XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith)

101.SCH		Inline XBRL Taxonomy Extension Schema Document (filed herewith)

101.CAL		Inline XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith)

101.DEF		Inline XBRL Taxonomy Extension Definition Linkbase Document (filed herewith)

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

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

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