What changed in this filing

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Item 1. Financial Statements

2021-05-18 compared with 2020-11-25 · 475 added, 645 removed, 340 unchanged (77% of the section changed)

3 unchanged sentences

(Thousands of dollars)

September 30,

Current Assets

9 unchanged sentences

Total Property and Equipment, Net

Other assets.

LIABILITIES AND EQUITY

2 unchanged sentences

Accrued liabilities

Due to related parties

Current portion of long-term debt

4 unchanged sentences

Asset Retirement Obligations

Derivative Liability Long-Term

Deferred Income Taxes

3 unchanged sentences

Common stock, $.10 par value;

2020 and 2019:

Authorized and Issued:

2,810,000 shares;

1,994,177 shares;

2,810,000 shares, Outstanding:

1,994,177 shares

3 unchanged sentences

815,823 shares

811,022 shares

Total Stockholders Equity PrimeEnergy Resources

5 unchanged sentences

O PERATIONS Unaudited

Three and nine months ended September 30, 2020 and 2019

Three Months Ended March 31, 2021 and 2020

(Thousands of dollars, except per share amounts)

Three Months Ended

September 30,

Nine Months Ended

September 30,

Natural gas sales

Natural gas liquids sales

Realized gain (loss) on derivative instruments, net

Realized (loss) gain on derivative instruments, net

Field service income

Administrative overhead fees

Unrealized gain (loss) on derivative instruments, net

Unrealized (loss) gain on derivative instruments, net

Total Revenues

6 unchanged sentences

Gain on Sale and Exchange of Assets

Income (Loss) from Operations

Other Income (Expense)

Interest Income

(Loss) Income from Operations

Other (Expense)

Interest expense

Income (Loss) Before Income Taxes

Income Taxes Expense (Benefit)

Net Income (Loss)

Net Income (Loss) Attributable to Non-Controlling

Net Income Attributable to PrimeEnergy

Basic Income Per Common Share

Diluted Income Per Common Share

(Loss) Before (Benefit from) Income Taxes

(Benefit from) Income Taxes

Net (Loss) Attributable to Non-Controlling

Net (Loss) Attributable to PrimeEnergy Resources

Basic (Loss) Per Common Share

Diluted (Loss) Per Common Share

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

2 unchanged sentences

E QUITY Unaudited

Nine months Ended September 30, 2020 and 2019

Three Months Ended March 31, 2021 and 2020

(Thousands of dollars)

1 unchanged sentence

Balance at December 31, 2020

Purchase 4,801 shares of common stock

Net Income (Loss)

Balance at September 30, 2020

Balance at March 31, 2021

Balance at December 31, 2019

Purchase 4,801 shares of common stock

Purchase of non-controlling interest

Balance at September 30, 2019

Balance at March 31, 2020

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

2 unchanged sentences

F LOWS Unaudited

Nine months ended September 30, 2020 and 2019

Three Months Ended March 31, 2021 and 2020

(Thousands of dollars)

Cash Flows from Operating Activities:

Net (Loss) Income including non-controlling

Adjustments to reconcile net income to net cash provided by operating activities:

Adjustments to reconcile net (loss) to net cash provided by operating activities:

Depreciation, depletion, amortization and accretion on discounted liabilities

Gain on sale of properties

Unrealized loss on derivative instruments, net

Provision for deferred income taxes

Changes in operating assets and liabilities:

Gain on sale and exchange of assets

Unrealized (gain) loss on derivative instruments, net

Deferred income taxes

Changes in assets and liabilities:

Accounts receivable

Due to related parties

Prepaids and other assets

Accounts payable

2 unchanged sentences

Cash Flows from Investing Activities:

Capital expenditures

Capital expenditures, including exploration expense

Proceeds from sale of properties and equipment

2 unchanged sentences

Purchase of stock for treasury

Purchase of non-controlling interests

Proceeds from long-term bank debt and other long-term obligations

1 unchanged sentence

Net Cash (Used in) Financing Activities

Cash and Cash Equivalents Period Increase (Decrease)

Net Increase in Cash and Cash Equivalents

Cash and Cash Equivalents at the Beginning of the Period

6 unchanged sentences

N OTES TO C ONDENSED C ONSOLIDATED F INANCIAL

September 30, 2020

March 31, 2021

(1) Basis of Presentation:

2 unchanged sentences

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 Companys Form 10-K for the year ended December 31, 2020.

In the opinion of management, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring

adjustments, necessary for a fair presentation of the Companys condensed consolidated balance sheets as of September 30, 2020 and December 31, 2019, the condensed consolidated results of operations, cash flows and equity for the nine months

ended September 30, 2020 and 2019.

As of September 30, 2020, PrimeEnergys significant accounting policies are consistent with those

discussed in Note 1Description of Operations and Significant Accounting Policies of its consolidated financial statements contained in PrimeEnergys Annual Report on Form 10-K for the fiscal year

ended December 31, 2019.

In the opinion of management, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal

recurring adjustments, necessary for a fair presentation of the Companys condensed consolidated balance sheets as of March 31, 2021 and December 31, 2020, the condensed consolidated results of operations, cash flows and equity for

the three months ended March 31, 2021 and 2020.

As of March 31, 2021, PrimeEnergys significant accounting policies are

consistent with those discussed in Note 1Description of Operations and Significant Accounting Policies of its consolidated financial statements contained in PrimeEnergys Annual Report on Form 10-K

for the fiscal year ended December 31, 2020.

Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation.

The results for interim periods are not necessarily indicative of annual results.

purposes of disclosure in the condensed consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.

( 2) Acquisitions and Dispositions:

Historically the Company has repurchased the interests of the partners and trust unit holders in the oil and gas limited partnerships (the

Partnerships) and the asset and business income trusts (the Trusts) managed by the Company as general partner and as managing trustee,

respectively.

During the nine months ended September 30, 2019 the Company purchased such interest totaling $306,000.

The Company had no such repurchases during the nine months ended September, 30 2020.

In the third quarter of 2020, the Company sold approximately 1,950 acres of undeveloped deep rights in central Reagan County, Texas, receiving

cash compensation of $10.7 million and in a separate transaction sold the Companys operated properties in West Virginia for future payments of $200,000 and a retained overriding royalty interest in future drilling on approximately 31,000

undeveloped acres.

The results for interim periods are not necessarily indicative

of annual results.

For purposes of disclosure in the condensed consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.

(2) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

September 30,

(Thousands of dollars)

3 unchanged sentences

Oil and gas sales

Tax refund receivable

Allowance for doubtful accounts

6 unchanged sentences

(3) Property and Equipment:

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

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

(Thousands of dollars)

September 30,

Proved oil and gas properties, at cost

6 unchanged sentences

(4) Long-Term Debt:

February 15, 2017, the Company and its lenders entered into a Third Amended and Restated Credit Agreement (the 2017 Credit Agreement) with a maturity date of February 15, 2021.

The Second Amended and Restated Credit Agreement and

subsequent amendments were amended and restated by the 2017 Credit Agreement.

Pursuant to the terms and conditions of the 2017 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $300 million

subject to a borrowing base that is determined semi-annually by the lenders based upon the Companys financial statements and the estimated value of the Companys 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 Credit Agreement) with a maturity date of February 15, 2021.

Under the 2017 Credit Agreement, the Company has a revolving line of

credit and letter of credit facility of up to $300 million subject to a borrowing base that is determined semi-annually by the lenders based upon the Companys financial statements and the estimated value of the Companys 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 Companys oil and gas properties.

The 2017 Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio,

total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio and interest coverage ratio, as defined, and restrictions are placed on the payment of dividends, the amount

of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships.

On December 22, 2017, the Company and its lenders entered into a First Amendment to the Third Amended and Restated Credit Agreement.

credit agreement includes the addition of a new lender and retains all other aspects of the original credit agreement.

As of the effective date of this amendment the Companys borrowing base was increased to $85 million.

On July 17, 2018, the Company and its lenders entered into a Second Amendment to the Third Amended and Restated Credit Agreement.

agreement includes modifications for the borrowing base utilization margins and rates by type of borrowing, revises minimum quantifications for individual borrowings, reduces the overall percentage required for commodity hedge agreements, modifies

the requirements placed on the Companys ability to purchase equity interests and retains all other aspects of the original credit agreement.

As of the effective date of this amendment the Companys borrowing base was increased to

On January 8, 2019, the Company and its lenders entered into a Third Amendment to the Third Amended and Restated Credit

The credit agreement includes additions for a Beneficial Ownership Certification on the effective date of the amendment.

The agreement includes further clarifications for potential LIBOR loan market rate issues, swap agreement

modifications and retains all other aspects of the original credit agreement.

As of the effective date of this amendment the Companys borrowing base was increased to $100 million.

Pursuant to borrowing base redeterminations on June 26,

2019 and December 18, 2019, the borrowing base was set at $90, million and $72, million respectively.

On May 8 th 2020 , the Company and its lenders entered into a Fourth Amendment to the Third Amended and Restated Credit Agreement.

On September 4, 2020, the Company and its lenders entered into a Fifth Amendment to the Third Amended and Restated Credit Agreement.

of the effective date of this amendment the Companys borrowing base was decreased to $50 million.

The amendment includes an automatic reduction of $666,666.67 to the borrowing base on October 1, 2020, November 1, 2020 and

December 1, 2020.

The amendment also revised the applicable borrowing base utilization percentages for Eurodollar and ABR loans with a range of 2.5% to 3.5% and 1.5% to 2.5%, respectively.

The agreement also adjusted percentages of title and

mortgage guarantees supported by the oil and gas properties presented to the administrative agent at each borrowing redetermination as supported by the required reserve report.

At September 30, 2020, the Company had a total of $40 million of borrowings outstanding under its revolving credit facility at a

weighted-average interest rate of 3.99 % and $10 million was available for future borrowings.

The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 3.94% for the nine

months ended September 30, 2020 as compared to 5.44% for nine months ended September 30, 2019.

The Companys borrowings under this credit facility approximates fair value because the interest rates are variable and reflective of

market rates.

The 2017 Credit Agreement includes terms and covenants that

require the Company to maintain a minimum current ratio and total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio, as defined, and restrictions are placed on the

payment of dividends, the amount of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships.

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

the agreement.

On February 11, 2021, the Company and its lenders entered into a Sixth Amendment to the 2017 Credit Agreement.

this amendment the Companys borrowing base is $40 million.

Borrowings under the 2017 Credit Agreement will bear interest at a base rate plus an applicable margin ranging from 2.00% to 3.00% or at the Companys option, at LIBOR plus

an applicable margin ranging from 3.00% to 4.00%.

The 2017 Credit Agreement will mature on February 11, 2023.

The Companys borrowings under this credit facility approximates fair value because the interest rates are variable and

reflective of market rates.

On March 31, 2021, the Company had a total of $35.95 million of borrowings outstanding under its

revolving credit facility at a weighted-average interest rate of 5.31% and $4.05 million was available for future borrowings.

The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest

was 5.27% for the quarter ended March 31, 2021 as compared to 4.81% for quarter ended March 31, 2020.

Paycheck Protection Program Loans

During May 2020, Prime Operating Company and Eastern Oil Well Services Corporation, subsidiaries of the Company received loan proceeds in the

amount of $1.28 million and $0.47 million , respectively, under the Paycheck Protection Program (the PPP) of the CARES Act, which was enacted March 27, 2020.

The PPP Loans are evidenced by a promissory note in favor of the

Lender, which bears interest at the rate of 1.00% per annum.

No payments of principal or interest are due under the note until the date on which the amount of loan forgiveness (if any) under the CARES Act, which can be up to 10 months after the end

of the related notes covered period (which is defined as 24 weeks after the date of the loan) (the Deferral Period).

During May 2020, Prime Operating Company and Eastern Oil Well Services Corporation, subsidiaries of the Company received loan

proceeds in the amount of $1.28 million and $0.47 million, respectively, under the Paycheck Protection Program (the PPP) of the CARES Act, which was enacted March 27, 2020.

The PPP Loans are evidenced by a promissory note

in favor of the Lender, which bears interest at the rate of 1.00% per annum.

No payments of principal or interest are due under the note until the date on which the amount of loan forgiveness (if any) under the CARES Act, which can be up to 10

months after the end of the related notes covered period (which is defined as 24 weeks after the date of the loan) (the Deferral Period).

The note may be prepaid at any time prior to maturity with no prepayment penalties.

Funds from the PPP Loans may be used

only for payroll and related costs, costs used to continue group health care benefits, mortgage payments, rent, utilities, and interest on other debt obligations that were incurred prior to February 15, 2020 (the Qualifying Expenses).

Under the terms of the PPP Loans, certain amounts thereunder may be forgiven if they are used for

Qualifying Expenses as described in and in compliance with the CARES Act.

While the Company intends to use the PPP Loan proceeds exclusively for Qualifying Expenses, it is unclear and uncertain

whether the conditions for forgiveness of the PPP Loans will be met under the current guidelines of the CARES Act.

Accordingly, we cannot make any assurance that the Company will be eligible for forgiveness of the PPP Loans, in whole or in part.

the extent, if any, that any or all of the PPP loans are not forgiven, beginning one month following expiration of the Deferral Period, and continuing monthly until 24 months from the date of each applicable Note (the Maturity Date), the

Company is obligated to make monthly payments of principal and interest to the Lender with respect to any unforgiven portion of the Note, in such equal amounts required to fully amortize the principal amount outstanding on such Note as of the last

day of the applicable Deferral Period by the applicable Maturity Date.

The Company accounts for these loans as financial liabilities.

Long-Term Obligations and Commitments:

Funds from the

PPP Loans may be used only for payroll and related costs, costs used to continue group health care benefits, mortgage payments, rent, utilities, and interest on other debt obligations that were incurred prior to February 15, 2020 (the

Qualifying Expenses).

Under the terms of the PPP Loans, certain amounts thereunder may be forgiven if they are used for Qualifying Expenses as described in and in compliance with the CARES Act.

The Company utilized the PPP Loan proceeds

exclusively for Qualifying Expenses during the 24-week coverage period and will submit its application for forgiveness in accordance with the terms of the CARES Act and related guidance.

In the event the PPP

Loan or any portion thereof is forgiven, the amount forgiven is applied to the outstanding principal.

To the extent, if any, that any or all of the PPP loans are not forgiven, beginning one

month following expiration of the Deferral Period, and continuing monthly until 24 months from the date of each applicable Note (the Maturity Date), the Company is obligated to make monthly payments of principal and interest to the

Lender with respect to any unforgiven portion of the Note, in such equal amounts required to fully amortize the principal amount outstanding on such Note as of the last day of the applicable Deferral Period by the applicable Maturity Date.

Company accounts for these loans on the balance sheet as financial liabilities reported within the following lines:

Current portion of long-term debt in the amount of $780 thousand and included as part of the long-term bank debt in the amount

of $975 thousand.

(5) Other Long-Term Obligations and Commitments:

Operating Leases:

The Company leases office facilities under operating leases and recognizes lease expense on a

straight-line basis over the lease term.

Leases assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term.

A new finance lease for

office equipment is included in property and equipment, other current liabilities and other long-term liabilities this quarter.

As most of the Companys 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 Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term.

assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term.

A new finance lease for office equipment is included in property and equipment, other current liabilities and other

long-term liabilities this quarter.

As most of the Companys 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 Companys 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 nine months ended September 30, 2020 were

$434 thousand.

Cash payments included in the operating lease cost for nine months ended September 30, 2020 were $462 thousand.

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 Companys sole

discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required.

Leases with an initial term of 12 months or less are not recorded on the balance sheet.

Operating lease costs for the three months ended March 31, 2021 were $140 thousand.

Cash payments included in the operating lease

cost for three months ended March 31, 2021 were $151 thousand.

The weighted-average remaining operating lease terms is 17.5 months.

The amortization and interest expense

for financing lease amounted to $1,778 and the cash payment for the lease was $1,913 and the lease term remaining was for 7 months.

payment schedule for the Companys operating and financing lease obligations as of September 30, 2020 is as follows:

The amortization and interest expense for financing lease amounted to $1,828 and the cash payment for the

lease was $1,913 and the lease term remaining was for 13 months.

The Company amended certain leases for office space in Texas providing

for payments of $599,000 in 2021, $157,000 in 2022 and $17,000 in 2023.

Rent expense for office space for the quarters ended

March 31, 2021 and 2020 was $162,000 and $163,000, respectively.

The payment schedule for the Companys operating and financing

lease obligations as of March 31, 2021 is as follows:

(Thousands of dollars)

2 unchanged sentences

Net operating lease liabilities

The Company amended certain leases for office space in Texas and Oklahoma providing for payments of

$461 thousand and $89 thousand in 2020 and 2021, respectively.

Rent expense for office space for the nine months ended

September 30, 2020 and 2019 was $496,000 and $484,000, respectively.

Asset Retirement Obligation:

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

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

(Thousands of dollars)

Asset retirement obligation at December 31, 2020

Liabilities incurred

Liabilities settled

Liabilities divested

Accretion expense

Asset retirement obligation at September 30, 2020

The Companys 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

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 Companys wells, the costs to ultimately retire the wells may vary significantly from previous estimates.

Asset retirement obligation at March 31, 2021

The Companys 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.

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 Companys wells, the costs to ultimately retire the wells may vary significantly from previous estimates.

(6) Contingent Liabilities:

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

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 Companys 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

Companys results of operations.

From time to time, the Company is party to certain legal actions arising in the ordinary course of

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.

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.

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 Companys 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 Companys results of operations.

From time to time, the Company is party to certain legal actions arising in the ordinary course of business.

While the outcome of these events

cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.

(7) Stock Options and Other Compensation:

1 unchanged sentence

the purchase of shares of common stock.

At June 30, 2020 and 2019, remaining options held by two key executive officers on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25.

According to their terms, the options

have no expiration date.

At March 31, 2021 and 2020, remaining options held by two key executive officers on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25.

According to their terms, the

options have no expiration date.

(8) Related Party Transactions:

The Company, as managing general partner or managing trustee, makes an annual offer to repurchase the interests of the partners and trust unit

holders in certain of the Partnerships or Trusts.

The Company purchased interests totaling $306,000 for the nine months ended June 30, 2019.

The Company had no such repurchases during the nine months ended September 30, 2020.

Payables owed to related parties primarily represent receipts collected by the Company as agent for the joint venture partners, which may

5 unchanged sentences

The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value.

The fair values of the natural gas, crude oil price swaps and natural gas liquid swaps are

designated as Level 3.

The following fair value hierarchy table presents information about the Companys assets and liabilities measured at fair value on a recurring basis at September 30, 2020 and December 31, 2019:

September 30, 2020

The fair values of the Companys 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 Companys assets and liabilities measured at fair value on a recurring basis at March 31, 2021 and December 31,

March 31, 2021

Quoted Prices in

11 unchanged sentences

Active Markets

For Identical

Assets (Level 1)

3 unchanged sentences

Commodity derivative contracts

March 31, 2021

Quoted Prices in

Active Markets

For Identical

Assets (Level 1)

Inputs (Level 2)

Inputs (Level 3)

(Thousands of dollars)

Commodity derivative contract

1 unchanged sentence

The derivative contracts were measured based on quotes from the Companys counterparties.

have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas , crude oil, natural gas liquids, volatility factors and

interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable.

These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties

for reasonableness.

The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility

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.

The Company does not have access to the specific assumptions used in its

counterparties valuation models.

Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

The following table sets

forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the period ended September 30, 2020.

(Thousands of dollars)

Net Liability December 31, 2019

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in

the fair value hierarchy for the quarter ended March 31, 2021.

(Thousands of

Net Liabilities December 31, 2020

Total realized and unrealized (gains) losses:

1 unchanged sentence

Purchases, sales, issuances and settlements

Net Liability September 30, 2020

Net Liabilities March 31, 2021

Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item

6 unchanged sentences

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 the Companys floating interest rates on existing

The value of interest rate swaps if applicable, would be recorded in accumulated other comprehensive loss, net of tax.

There are no current interest rate swaps for the periods ending September 30, 2020 and December 31, 2019.

The following table sets forth the effect of derivative instruments on the consolidated

balance sheets at September 30, 2020 and December 31, 2019:

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at March 31, 2021 and

December 31, 2020:

(Thousands of dollars)

Balance Sheet Location

September 30,

Asset Derivatives:

2 unchanged sentences

Derivative asset short-term

Crude oil commodity contracts

Derivative asset short-term

Natural gas commodity contracts

Derivative asset long-term

Derivative asset long-term and

Liability Derivatives:

4 unchanged sentences

Derivative liability short-term

Crude oil commodity contracts

Derivative liability long-term

Natural gas commodity contracts

1 unchanged sentence

Total derivative instruments

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the nine

months ended September 30, 2020 and 2019:

The following table sets forth the effect of derivative instruments on the consolidated

statements of operations for the quarters ended March 31, 2021 and 2020:

Location of gain/loss recognized in income

4 unchanged sentences

Natural gas commodity contracts

Unrealized gain on derivative instruments, net

Unrealized (loss) gain on derivative instruments, net

Crude oil commodity contracts

Unrealized gain (loss) on derivative instruments, net

Natural gas liquids contracts

Unrealized loss on derivative instruments, net

Unrealized (loss) gain on derivative instruments, net

Natural gas commodity contracts

Realized gain (loss) on derivative instruments, net

Realized (loss) gain on derivative instruments, net

Crude oil commodity contracts

Realized gain (loss) on derivative instruments, net

Natural gas liquids contracts

Realized gain on derivative instruments, net

Realized (loss) gain on derivative instruments, net

(10) Earnings Per Share:

4 unchanged sentences

financial statements:

Nine Months Ended September 30,

Effect of dilutive securities:

Three Months Ended September 30,

Quarter Ended March 31,

Effect of dilutive securities:

MANAGEMENTS 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.

The effect of the 767,000 outstanding stock options is antidilutive for the quarter ended March 31,

2021 and 2020, due to net loss for this period.

MANAGEMENTS 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.

We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold

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consolidated statement of operations as changes occur in the NYMEX price indices.

On January 30, 2020, the World Health Organization

(WHO) announced a global health emergency due to the COVID-19 outbreak, which originated in Wuhan, China, and the risks to the international community as the virus spreads globally beyond its point

In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally.

In addition, in March 2020, members of OPEC failed to agree on production

levels which has caused an increased supply and has led to a substantial decrease in oil prices and an increasingly volatile market.

The oil price war ended with a deal to cut global petroleum output but did not go far enough to offset the impact of

COVID-19 on demand.

There has been an increase in supply which has pushed prices down further since March.

If the depressed pricing continues for an extended period it will lead to i) further reductions in the

borrowing base under our credit facility which would require us to make additional borrowing base deficiency payments, ii) reductions in reserves, and iii) additional impairment of proved and unproved oil and gas properties.

We also expect

disclosures of supplemental oil and gas information to be impacted by price declines.

In response to recent commodity prices our efforts

to reduce costs include reducing operating costs and electing to shut-in marginal wells.

The Company reviewed field operations to minimize costs and identify wells for short term

The Company has also implemented a reduction in workforce to further reduce general and administrative costs.

The full impact of the COVID-19 outbreak and the

decline in oil prices continues to evolve as of the date of this report.

As such, it is uncertain as to the full magnitude that these events will have on the Companys financial condition, liquidity, and future results of operations.

Management is actively monitoring the global situation on its financial condition, liquidity, operations, suppliers, industry, and workforce.

Given the daily evolution of the COVID-19 outbreak and the global responses to curb its spread, the Company is not able to estimate the effects of the COVID-19 outbreak

on its results of operations, financial condition, or liquidity for fiscal year 2020.

These matters may have a continued material adverse impact on economic and market conditions and trigger a period of global economic slowdown, which may impair the

Companys asset values, including reserve estimates.

Further, consumer demand has decreased since the spread of the outbreak and new travel restrictions placed by governments in an effort to curtail the spread of the coronavirus.

Company cannot estimate the length or gravity of the impacts of these events at this time, if the pandemic and/or decreased oil prices continue, they may have a material adverse effect on the Companys results of future operations, financial

position, and liquidity in fiscal year 2020.

Our financial results depend on many factors, particularly the price of natural gas and

crude oil and our ability to market our production on economically attractive terms.

Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions,

pipeline capacity constraints, inventory storage levels, basis differentials and other factors.

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.

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consequently, we cannot accurately predict or control

may receive for our oil, natural gas and NGLs.

The price of oil and natural gas has fallen significantly since the beginning of 2020, due in

part to failed Organization of Petroleum Exporting Countries (OPEC) negotiations as well as concerns about the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil

The resulting precipitous decline in oil and gas pricing experienced during March 2020, through the date of this report, if prolonged.

or a further deterioration of the market price for oil and natural gas, will negatively impact our cash

We are the operator of the majority of our developed and undeveloped acreage which is nearly

all held by production.

In the Permian Basin of West Texas and eastern New Mexico the Company maintains an acreage position of approximately 19,680 gross (12,322 net) acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of

Texas where our current horizontal drilling activity is focused.

We believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional horizontal drilling that could support the drilling of as many as 250

additional horizontal wells.

the price we may receive for our oil, natural gas and NGLs.

Index prices for oil, natural gas and NGLs 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.

operator of the majority of our developed and undeveloped acreage which is nearly all held by production.

In the Permian Basin of West Texas and eastern New Mexico the Company maintains an acreage position of approximately 19,680 gross (12,460 net)

acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused.

We believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for

additional horizontal drilling that could support the drilling of as many as 250 additional horizontal wells.

In Oklahoma we maintain an acreage position of approximately 56,090 gross (10,355 net) acres.

Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties.

approximately 3,460 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 52 new horizontal wells based on an estimate of four to ten wells per section, depending on the reservoir

Should we choose to participate with a working interest in future development, our share of these future capital expenditures would be approximately $40 million at an average 10% ownership level.

Future development plans are established based on various factors, including the expectation of available cash flows from operations and

availability of funds under our revolving credit facility.

Our Oklahoma horizontal development is

focused primarily in Canadian, Kingfisher, Grady, and Garvin counties.

We believe approximately 3,460 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 52 new horizontal wells

based on an estimate of four to ten wells per section, depending on the reservoir target area.

Should we choose to participate with a working interest in future development, our share of these future capital expenditures would be approximately

$12 million at an average 10% ownership level.

Future development plans are established based on various factors, including the

expectation of available cash flows from operations and availability of funds under our revolving credit facility.

District Information

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

Note, the Appalachian District properties,

described in the table below, were sold August 1, 2020.

Proved Reserves as of December 31, 2020 (MBoe)

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Gulf Coast Region

Our development, exploration and production activities in the Gulf Coast region are primarily concentrated in southeast Texas.

This region is

managed from our office in Houston, Texas.

Principal producing intervals are in the Wilcox, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to 12,500 feet.

We had 233 producing wells (143 net) in the Gulf Coast region as of

December 31, 2019, of which 125 wells are operated by us.

Average net daily production in 2019 was 348 Boe.

Our development,

exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in southeast Texas.

This region is managed from our office in Houston, Texas.

Principal producing intervals are in the Wilcox, San Miguel, Olmos,

and Yegua formations at depths ranging from 3,000 to 12,500 feet.

We had 239 producing wells (124 net) in the Gulf Coast region as of December 31, 2020, of which 158 wells are operated by us.

Average net daily production in our Gulf Coast

Region in 2020 was 297 Boe.

At December 31, 2020, we had 517 MBoe of proved reserves in the Gulf Coast region, which represented 5% of our total proved reserves.

maintain an acreage position of over 12,700 gross (5,120 net) acres in this region, primarily in Dimmit and Polk counties.

We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs,

nineteen water transport trucks, two saltwater disposal wells and several trucks and excavating equipment.

Services including well service support, site preparation and construction services for drilling and workover operations are provided to

third-party operators as well as utilized in our own operated wells and locations.

As of September 30, 2020, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other

related activities of material importance.

We maintain an acreage position of over 12,700 gross (5,120 net) acres in this

region, primarily in Dimmit and Polk counties.

We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, nineteen water transport trucks, two saltwater disposal wells and several

trucks and excavating equipment.

Services including well service support, site preparation and construction services for drilling and workover operations are provided to third-party operators as well as utilized in our own operated wells and

As of March 31, 2021, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

Mid-Continent Region

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Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet.

Average net daily production in 2019 was 840 Boe.

At December 31, 2019, we had 2,094 MBoe of

proved reserves in the Mid-Continent area, or 14.7% of our total proved reserves.

We maintain an acreage position of approximately 56,358 gross (10,580 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties.

Average net daily production in our Mid-Continent Region

in 2020 was 788 Boe.

At December 31, 2020, we had 1670 MBoe of proved reserves in the Mid-Continent area, or 16% of our total proved reserves.

We maintain an acreage position of approximately 56,000 gross

(10,355 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties.

We operate a field service group in this region from a field office in Elmore City, utilizing one workover rig and one saltwater hauling truck.

Our Mid-Continent region is actively participating with third-party operators in the horizontal

development of lands that include Company owned interest in several counties in the Stack and Scoop plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian, and Woodford formations.

As of September 30, 2020, in the Mid-Continent region, the Company was is participating in the drilling and/or completion of four wells, with overriding royalty only in eight additional wells, all included as Proved Undeveloped in the 2019 year-end reserve report.

Our Mid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company owned interest in several counties in the Stack and Scoop plays of

Oklahoma where drilling is primarily targeting reservoirs of the Mississippian, and Woodford formations.

As of March 31, 2021, in the Mid-Continent region, the Company was participating in the completion

of four wells included as Proved Undeveloped in the 2020 year-end reserve report.

West Texas Region

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The oil and gas are produced primarily from five intervals;

the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the

Atoka, at depths ranging from 6,700 feet to 11,300 feet.

the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700

feet to 11,300 feet.

This region is managed from our office in Midland, Texas.

As of December 31, 2019, we had 522 wells (257 net) in the West Texas area, of which 298 wells are operated by us.

Principal producing

intervals are in the Spraberry, Wolfcamp, and San Andres formations at depths ranging from 4,200 to 12,500 feet.

Average net daily production in 2019 was 3,703 Boe.

At December 31, 2019, we had 11,108 MBoe of proved reserves in the West Texas area,

or 78% of our total proved reserves.

We maintain an acreage position of approximately 19,910 gross (12,560 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties and believe this acreage has

significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals.

We operate a field service group in this region utilizing nine workover rigs, four hot oiler trucks, one kill truck and two roustabout trucks.

At December 31, 2019, the

Company had committed to participate in the drilling of ten Proved Undeveloped horizontal drilling locations.

Seven of the ten wells were drilled by April 15, 2020.

One well was put on production in July of this year and six other wells are expected

to be producing by May 2021.

Reserve Information:

Our interests in proved developed and undeveloped oil and gas properties, including the interests held by the Partnerships, have been evaluated

by Ryder Scott Company, L.P.

As of December 31, 2020, we had 556 wells (263 net) in the West Texas area,

of which 325 wells are operated by us.

Principal producing intervals are in the Spraberry, Wolfcamp, and San Andres formations at depths ranging from 4,200 to 12,500 feet.

Average net daily

production in Our West Texas Region in 2020 was 3,178 Boe.

At December 31, 2020, we had 8,242 MBoe of proved reserves in the West Texas area, or 79% of our total proved reserves.

We maintain an acreage position of approximately 19,679 gross

(12,461 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals.

operate a field service group in this region utilizing nine workover rigs, four hot oiler trucks, one kill truck and two roustabout trucks.

Services including well service support, site preparation and construction services for drilling and workover

operations are provided to third-party operators as well as utilized in our own operated wells and locations.

At December 31, 2020,

the Company was committed to participate with Apache Corporation in the drilling of three Proved Undeveloped horizontal locations in Upton County, Texas and the completion of these along with six other wells drilled in 2020 on the same tract.

three new horizontals have been drilled and cased as of April 1, 2021.

Completion operations for all nine are scheduled for June 2021.

Our interests in proved developed and undeveloped oil and gas properties, including the interests held by the

Partnerships, have been evaluated by Ryder Scott Company, L.P.

for each of the three years ended December 31, 2020.

The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1,

the Ryder Scott Company, L.P.

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 Registrants Reserves Estimates.

In matters related to the preparation of our reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance

responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end reserves by our independent third-party engineers, Ryder

Scott Company, L.P.

The members of our district and central groups consist of degreed engineers and geologists with between approximately twenty and thirty-five years of industry experience, and between eight and twenty-five years of experience

managing our reserves.

Our Engineering Data manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over twenty-five years of experience, holds a Bachelor degree in Geology and an MBA in finance

and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist.

See Part II, Item 8 Financial Statements and Supplementary Data, for additional discussions regarding proved reserves and their

related cash flows.

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.

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one barrel of natural gas liquids equals one barrel of oil.

At December 31, 2017 our reserve report included 779 MBoe of proved undeveloped reserves attributable to 22 horizontal wells that were all

completed in 2018, therefore, 100% of these reserves were converted to proved developed in the 2018 year-end reserves report.

In 2018, the Company drilled and completed seventeen horizontal wells in West Texas and eleven horizontal wells in Oklahoma.

In addition, the

Company added reserves through overriding royalty interest in 16 wells, primarily in Oklahoma and Texas.

At year-end 2018, thirteen of the seventeen wells completed in 2018 were designated as Shut-In:

eight in our West Texas horizontal development program, which were brought on production in February, 2019, and five in our Oklahoma Scoop-Stack development program, which were brought on production in

At December 31, 2018, our reserve report included 43 MBoe of proved undeveloped reserves attributable to eight horizontal

wells that had been drilled but had not yet been completed:

three of these were completed in 2019, converting 24 Mboe of undeveloped reserves to proved developed, and five remained uncompleted as of December 31, 2019, which account for 18 Mboe of

The Company has 9% ownership in one of these five wells and less than 1% in four wells.

In 2019, in West Texas, in addition

to the eight wells classified as Shut-in at year-end 2018 that were brought on production in February, we participated in the drilling and completion of three wells on

our Kashmir tract:

two wells with an average 49% interest, and a third well for 5.3% interest.

One of each of these wells was completed in the Wolfcamp A, Jo Mill, and Lower Spraberry.

All three wells were brought on production in May of

In our Oklahoma, Scoop-Stack play, in 2019, we participated in the drilling and completion of six wells on our WM Wallace tract for

7.67% interest, and nine wells, included on Slash, Osborn, and Leon tracts, with an average 1.34% interest.

In addition, three wells drilled in Oklahoma in 2018, designated as proved undeveloped at year-end

2018, were completed in 2019 converting 24 Mboe of reserves to proved developed.

Also in Oklahoma, six wells designated as Shut-in on December 31, 2018, were brought into production in 2019:

five located on

our Ruthie tract, and one on our Braum tract.

In the Gulf Coast region, we added production through the recompletion of three vertical wells in Polk County, Texas:

one operated by the Company in which we have 72.5% interest, and two operated by Unit

Petroleum in which the Company owns 2.81% working interest and 3.77% net revenue interest.

At December 31, 2019, the Company had 3,607

Mboe of undeveloped reserves attributable to 22 wells operated by others that were anticipated to be drilled and completed primarily in 2020:

ten of these are located in our West Texas horizontal development program and account for 3,526 Mboe of the

total, and 12 wells are located in our Oklahoma Scoop-Stack horizontal program and account for 81 Mboe of the total.

Of the 12 locations in Oklahoma, six were drilled and are on production, four have been drilled but not yet completed and two are

not yet drilled.

Nine of the ten wells in West Texas are located on our 1,300 acre Kashmir tract in Upton County.

By April 15, of this year six of these had been drilled and are awaiting completion, which is now expected to occur the end of February

or beginning of March 2021.

Our average 47.76% share of the cost of these six horizontal wells will be approximately $19.4 million.

Drilling of the remaining three wells is expected to occur the end of February or beginning of March 2021.

In the first half of 2020, the Company participated in a horizontal well for 8.36% interest operated by Pioneer Natural Resources completed

and brought into production in July 2020.

Our total net expenditure for this well will be approximately $630,000.

Additional drilling and future development plans will be established based on an expectation of available cash flows from operations

and availability of funds under our revolving credit facility.

We employ technologies to establish proved reserves that have been demonstrated to provide

consistent results capable of repetition.

The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data, and well test

At December 31, 2020, the Company had 3,221 Mboe of proved undeveloped reserves attributable to 13 wells operated by others, three of

which are new wells, spud in 2020 but not drilled until the first quarter of 2021 and 10 of which were drilled as of year-end.

The three new horizontals along with six uncompleted wells are located in Upton

County, Texas and are in the process of being completed and we expect them to be placed on production by the end of the second quarter of 2021.

Apache Corporation is the operator of these wells.

These nine PUD wells account for 3,127 Mboe of the

total undeveloped reserves.

The nine wells mentioned above are located on our 1,300 acre Kashmir tract in Upton County, operated by Apache Corporation.

Our average 47.5% share of the total cost of these nine horizontal wells will be approximately

The four remaining PUD wells, drilled but not completed, are located in Grady County, Oklahoma and account for 95 Mboe of the total undeveloped reserves.

Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and

availability of funds under our revolving credit facility.

We employ technologies to establish proved reserves that have been

demonstrated to provide consistent results capable of repetition.

The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production

data, and well test data.

The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves.

Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using

performance data from analogous wells in the area.

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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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.

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

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.

generally accepted accounting principles, changes in market prices subsequent to December 31 are

not considered.

While it may be reasonably anticipated that the prices received for the sale of our production may be higher or lower

than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by

the SEC, omitted from consideration in making this evaluation for the SEC case.

Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.

Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $1.985 per MMBtu in 2020 as

compared to $2.58 per MMBtu in 2019, and $3.10 per MMBtu in 2018.

Oil prices, based on the NYMEX first of the month average price, were $39.57 per barrel in 2020 as compared to $55.69 per barrel in 2019, and $65.56 per barrel in 2018.

RECENT ACTIVITIES

Since the start of our

West Texas horizontal drilling program in 2015 and through the third quarter of 2020 the Company has participated in 74 horizontal wells in the Permian Basin, seven of which were drilled in the first half of 2020.

Through July 2020, the Company has

invested approximately $112 MM in our West Texas horizontal drilling program.

Of the 74 total horizontal wells participated in, we have an average of 24% working interest.

In 2019, 11 wells were brought on production:

the Company has 49% interest in

eight of these wells, all one-mile in length, located on our CC-33 tract, and an average 48% interest in two horizontals and 5.3% interest in one additional horizontal,

that are each two-miles in length, located on the Kashmir tract.

The Company invested approximately $31.5 million in these 11 wells brought on production in 2019.

Through the second quarter of 2020, the

Company participated in seven new horizontal wells, all located in Upton County, Texas.

Six of these are operated by Apache Corporation and one is operated by Pioneer Natural Resources.

The Pioneer well was completed in late June and came on

production in early July 2020.

The six Apache operated wells are anticipated to be completed the end of February or beginning of March 2021.

In Upton County, West Texas, we are developing a contiguous 3,260-acre block with our joint venture

partner, Apache Corporation.

In this block the Company has 2,600 leasehold acres with interest between 14% and 56%, depending on the particular lease and depth being developed.

In 2018, in this block, eight wells drilled horizontally in the Wolfcamp

B, were participated in for 49% interest.

This is believed to be full development of the Wolfcamp B reservoir for this lease block.

Apache will likely now set its sights on development of the Upper Wolfcamp, Jo Mill, and

Lower Spraberry reservoirs for this block, following the recent successful testing in 2019 of these reservoirs on our offset 1,300-acre lease block.

Given the favorable results achieved by the initial three

wells on the offset block, it is expected that as many as 54 additional horizontals will be slated for development on the 3,260-acre block in the near future.

The cost of such development would be

approximately $370.6 million with the Companys share being approximately $170.8 million.

In addition, there is a fourth target reservoir, the Middle Spraberry, that is also prospective for development.

The potential of the Middle

Spraberry, on the 3,280-acre block, is for 18 horizontal wells to be drilled, with the Company likely participating for approximately $61.8 million.

The actual number of wells that are eventually drilled

as well as the cost and the timing of drilling will vary based upon many factors, including commodity market conditions.

In addition to the 3,260 acreage block under development, the Company is also developing an

offsetting 1,300-acre block in Upton County, Texas with Apache Corporation as operator.

In the second quarter of 2019 three horizontal wells were completed and brought on production from reservoirs above the

Middle Wolfcamp:

one in the Wolfcamp A, one in the Jo Mill, and one in the Lower Spraberry, confirming the economic viability of these reservoirs on our acreage.

Prime holds between 5% and 48% working interest in various depths of this

acreage, and of the $26.7 million development cost for these three wells, our share was approximately $9.2 million.

As a result of the success of these three wells, six horizontals were drilled in the first half of 2020 on this acreage

We have an average 47.76% share of these wells.

In addition to the six development locations in the Wolfcamp A, Jo Mill and Lower Sprayberry of our 1,300-acre block, there are four locations

in the Middle Spraberry that are likely to be considered for future development at an estimated gross cost of approximately $30.2 million, with the Companys share being approximately $14.2 million.

Also in the first half of 2020, the

Company participated in a horizontal well for 8.36% interest operated by Pioneer Natural Resources that was completed and brought into production in July, 2020.

Our total net expenditure for this well has been approximately $630,000.

Also in the Permian Basin of West Texas, we are developing a 965-acre block with Concho Resources in

Martin County, Texas.

In 2016 and 2017, four horizontal wells were drilled and completed and put on production.

The Company owns 35% to 38% interest in this joint venture acreage where Concho Resources is the operator.

No near-term additional

drilling plans have been received from Concho Resources, however, offset operators have been actively drilling and their results are encouraging for the future development of multiple landing zones within this acreage block.

In Central Reagan County, of West Texas, during the third quarter of 2020, the Company has sold deep rights covering approximately 1,950 acres

for a purchase price of $10.3 million to-date, with a final total compensation expected to be $10.7 million.

Since the start of our Oklahoma Scoop-Stack horizontal development program, which began in 2013, the Company has participated in 41 horizontal

wells for approximately $23.5 million through 2019 with an average of approximately 7% interest.

There have been no new wells participated in through the third quarter of 2020.

During this same period the Company chose to retain an overriding

royalty interest in an additional 69 horizontal wells.

In 2019, the Company participated for an average 5.78% interest in 20 horizontal wells in Canadian, Grady, and Kingfisher counties for a net cost of approximately $8.8 million.

were completed in 2019, and of these 20 wells, twelve are operated by Encana/Newfield.

In addition, the Company is also participating in four wells in Grady County, Oklahoma spud in 2018 that have not yet been completed.

During 2019, in Oklahoma,

the Company retained an overriding royalty interest in eighteen wells, nine of which were completed in 2019, and nine of which have yet to be completed.

Through the third quarter of 2020, the Company has retained an interest in four wells located in

Canadian County, Oklahoma, completed in February of this year.

Our horizontal activity in Oklahoma is focused in Canadian, Grady,

Kingfisher, Garfield, Major, and Garvin counties where we have approximately 3,401 net acres.

We believe this acreage has significant additional resource potential that could support the drilling of as many as 49 new horizontals based on an estimate

of six wells per section:

three in the Mississippian and three in the Woodford Shale.

Should we choose to participate in future development, our share of the capital expenditures would be approximately $34 million at an average 10% ownership

the Company will otherwise sell its rights for cash, or cash plus a royalty or working interest.

In 2019, in the Gulf Coast region

of Texas, the Company participated with Unit Petroleum in the successful recompletion of two wells in the Wilcox Formation of the Jazz field in Polk County, Texas.

The Company has a 2.8125% working interest and a 3.768% net revenue interest in these

wells and participated for approximately $45,000.

Also in 2019, the Company successfully recompleted a shallow straight hole well in the Segno field of Polk County, Texas with a 72.5% working interest.

In early August 2020, the Company closed on the sale of its West Virginia District operated assets.

The sale includes 456 producing wells,

along with approximately 35,000 leasehold acres, one salt water disposal well, and operating equipment.

The Company has retained an overriding royalty interest, up to 12.5%, in any future drilling of these properties.

The Companys

activities include development and exploratory drilling.

Our strategy is to develop the Companys 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 todays technology, horizontal development of our reserves provides superior economic

results as compared to vertical development, by delivering higher production rates through greater contact and stimulation of a larger volume of reservoir rock while minimizing the surface footprint required to develop those same reserves.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy.

For 2021, we will continue our focus on

preserving financial flexibility and ample liquidity as we manage the risks facing our industry.

Our 2021 capital budget is reflective of current commodity prices and has been established based on an expectation of available cash flows, with any

cash flow deficiencies expected to be funded by borrowings under our revolving credit facility.

As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures.

In accordance with SEC rules governing

the scheduling of development of proved undeveloped (PUD) reserves, our year-end reserve report includes only those three wells that were slated to be drilled in 2021 along with 10 PUD locations that at year-end 2020 had been drilled but not yet completed.

The three new wells drilled in the first quarter of 2021 and the six wells drilled in 2020 on the same Upton County, Texas tract are slated to be completed and

on production by the end of the second quarter of 2021.

The Company has an average of 47.5% interest in these nine wells.

The remaining four PUD horizontal wells, drilled but not completed at year-end, are

located in Grady County, Oklahoma.

Of these, the Company has 10% interest in one well and less than one percent interest in each of three wells.

Since the start of our West Texas horizontal drilling program in 2015 and through the first quarter of 2021 the Company has participated in 77

horizontal wells in the Permian Basin, one of which was drilled and brought into production in 2020.

As of year-end, the Company has invested approximately $108 MM in this drilling program, including over

$4 million in six wells drilled in 2020 that will be completed in 2021.

In addition, the Company has invested another $3.2 million in three new horizontals drilled in the first quarter of 2021.

All nine of these wells are designated as

proved undeveloped in the year-end reserve report and are to be completed and on-line by the end of the second quarter of 2021.

Of the total 77 horizontal wells in this

program, the Company has an average of 30.75% interest in 62 wells, and less than one percent interest in 15 wells.

In Upton County,

West Texas, we are developing a contiguous 3,260 acre block with our joint venture partner, Apache Corporation.

In this block the Company has leasehold acres with interest between 14% and 56%, depending on the particular lease and depth being

In 2018, in this block, eight wells drilled horizontally in the Wolfcamp B, were participated in for 49% interest and brought on production in February, 2019.

This is believed to be full development of the Wolfcamp

B reservoir for this lease block.

Future development is expected in the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs for this block, following the 2019 successful development of these reservoirs on our offset 1,280 acre lease

block of the Kashmir Tract.

Given the favorable results achieved by the initial three wells on the 1,280 block it is expected that as many as 54 additional horizontals will be developed on this 3,260 acre block in the near future.

development would be approximately $370.6 million with the Companys share being approximately $170.8 million.

In addition to the 54 wells likely to be drilled for these three reservoirs, there is a fourth target reservoir, the Middle

Spraberry, that is also prospective for future development.

The potential of the Middle Spraberry on the 3,260

acre block is for 18 horizontal wells to be drilled and completed at a gross cost of approximately $126.3 million with the Companys share being approximately $61.8 million.

actual number of wells that are eventually drilled as well as the cost and the timing of drilling will vary based upon many factors, including commodity market conditions.

In addition to the 3,260 acre block being developed, as described above, the Company is also developing an offsetting 1,280 acre block in

Upton County, Texas, with Apache Corporation as operator.

In the second quarter of 2019 three horizontal wells were completed and brought on production from reservoirs above the Middle Wolfcamp:

one in the Wolfcamp A, one in the Jo Mill,

and one in the Lower Spraberry, confirming the economic viability of these reservoirs on our acreage.

Prime holds 47.5% working interest in these reservoirs.

As a result of the success of the initial three wells, nine new horizontals were spud in

the first quarter of 2020 with six being fully drilled by May, 2020.

The three remaining wells were drilled in the first quarter of 2021.

All nine of these wells are slated for completion and to be on production by the end of the second quarter of

Our average 47.5% share of the cost of these nine horizontal wells will be approximately $26.7 million in total.

In addition to the nine new development locations in the Wolfcamp A, Jo Mill and Lower

Sprayberry, four locations in the Middle Spraberry will be considered for future development at an estimated gross cost of approximately $30.2 million with the Companys share being approximately $14.2 million.

Also in the Permian Basin of West Texas, we are developing a 965 acre block with Connoco Phillips in Martin County, Texas.

In 2016 and 2017,

four horizontal wells were drilled and completed and put on production.

The Company owns 35% to 38% interest in this joint venture acreage where Connoco Phillips is the operator.

No near-term additional drilling plans have been received from Connoco

Phillips, however, offset operators have been actively drilling and their results are encouraging for the future development of multiple landing zones within this acreage block.

DoublePoint Energy, acquired by Pioneer Natural Resources, entered into a joint development agreement for the horizontal development of lands

located in Reagan County, Texas in February of 2021 with PrimeEnergy .

The agreement covers approximately 3,680 gross acres of blocked up leasehold to allow for 1.5 and 2 mile horizontal laterals.

We believe this agreement represents significant

future value for PrimeEnergy.

On May 10, 2021, the Company agreed to participate in the drilling of four wells in Canadian County,

Oklahoma with Ovintiv Mid-Continent Inc.

Drilling of these horizontal wells is expected to occur in the third quarter of 2021 and target the proven oil reservoirs of the Mississippian and Woodford Formations

at roughly 8,900 in depth with laterals of approximately 10,000 in length.

The Company has an 11.25% interest and will invest approximately $1.98 million in the drilling and completion of these wells.

RESULTS OF OPERATIONS

2020 and 2019 Compared

net income of $6.5 million, or $3.26 per share and $65 thousand or $0.03 per share for the three and nine months ended September 30, 2020, respectively, as compared to net income of $2.5 million, or $1.25 per share and

$5.2 million, or $2.61 per share for the three and nine months ended September 30, 2019, respectively.

Current year net income reflects decreases in production combined with commodity price decreases over the three and nine months ended

September 30, 2019, increases in gains related to the sale of acreage and changes related to the valuation of derivative instruments.

We reported a net

loss of $1.46 million, $0.73 per share, for the three months ended March 2021 compared with net loss of $170 thousand, $0.09 per share, for the same period of 2020.

The current year net loss reflects changes in oil, gas and NGLs sales

related to decreased production combined with higher commodity prices offset by an unrealized loss on derivatives.

The significant components of income and expense are discussed below.

Oil, gas and NGLs sales decreased $11.2 million, or 55.9% from $20.1 million for the three months ended September 30,

2019 to $8.9 million for the three months ended September 30, 2020 and $41.0 million, or 60.9% from $67.3 million for the nine months ended September 30, 2019 to $26.3 million for the nine months ended September 30, 2020.

The following table summarizes the primary components of production volumes and average sales prices

realized for the nine months ended September 30, 2020 and 2019 (excluding realized gains and losses from derivatives).

Nine months ended September 30,

Barrels of Oil Produced

Average Price Received

Oil Revenue (In 000s)

Mcf of Gas Sold

Average Price Received

Gas Revenue (In 000s)

Barrels of Natural Gas Liquids Sold

Average Price Received

Natural Gas Liquids Revenue (In 000s)

Total Oil & Gas Revenue (In 000s)

Three months ended September 30,

Oil, gas and NGLs sales remained flat at $12.67 million and $12.80 million for the three months ended March 31,

2021 and 2020 respectively.

Sales vary due to changes in volumes of production sold and realized commodity prices.

There were substantial price increases in prices during the first quarter of 2021 compared to the same period in 2020.

prices increased an average of $11.10 per barrel, or 24% on crude oil, increased an average of $1.59 per mcf, or 177% on natural gas and increased an average of $10.50 per barrel, or 107% on NGLs, during the three months ended March 31, 2021

from the same period in 2020.

Our crude oil production decreased by 71,000 barrels, or 30.34% from 234,000 barrels for the first quarter

2020 to 163,000 barrels for the first quarter 2021.

Our natural gas production decreased by 273,000 mcf, or 29.1% from 938,000 mcf for the first quarter 2020 to 665,000 mcf for the first quarter 2021.

Our natural gas liquids production decreased by

41,000 barrels, or 32.3% from 127,000 barrels for the first quarter 2020 to 86,000 barrels for the first quarter 2021.

The decrease in production volumes reflect the natural decline of our properties combined with the

shut-in of properties due to the freezing weather in Texas and Oklahoma during February 2021.

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

Three Months Ended March 31,

Barrels of Oil Produced

8 unchanged sentences

Total Oil & Gas Revenue (In 000s)

Oil, Natural Gas and NGL Derivatives We do not apply hedge accounting to any of our commodity

based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are

recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations.

As oil and natural gas prices remain volatile,

mark-to-market accounting treatment creates volatility in our revenues.

Field service income decreased $2.3 million or 47.2% from $4.9 million for the third quarter 2019 to $2.6 million

for the third quarter 2020 and $5.1 million, or 35.6% from $14.4 million for the nine months ended September 30, 2019 to $9.2 million for the nine months ended September 30, 2020.

This decrease is a combined result of decreased

utilization and rates charged to customers as oil and gas prices declined during 2020.

Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations.

Lease operating expense decreased $4.4 million or 53.6% from $8.2 million for the third quarter 2019 to

$3.8 million for the third quarter 2020, and decreased $8.1 million or 33.0% from $24.4 million for the nine months ended September 30, 2019 to $16.4 million for the nine months ended September 30, 2020.

This decrease is

primarily due to the shut-in of high lifting cost properties during 2020 combined with lower production taxes related to lower commodity prices.

Field service expense decreased $2.0 million or 50.3% from $4.0 million for the third quarter 2019 to

$2.0 million for the third quarter 2020 and decreased $4.2 million, or 35.9% from $11.6 million for the nine months ended September 30, 2019 to $7.4 million for the nine months ended September 30, 2020.

Field service expenses

primarily consist of salaries and vehicle operating expenses which have decreased during the three and nine months ended September 30, 2020 over the same periods of 2019 related to decreased utilization of the equipment as oil and gas prices

declined during 2020.

Depreciation, depletion, amortization and accretion on discounted liabilities increased

$0.1 million, or 1.9% from $9.3 million for the third quarter 2019 to $9.4 million for the third quarter 2020 and decreased $3.3 million, or 9.9% from $27.8 million for the nine months ended September 30, 2019 to

$24.5 million for the nine months ended September 30, 2020, reflecting the reduced production rates in the nine months of 2020.

General and administrative expense decreased $0.3 million, or 9.9% from $2.9 million for the three months ended

September 30, 2019 to $2.6 million for the three months ended September 30, 2020, and increased $0.3 million, or 2.0% from $12.6 million for the nine months ended September 30, 2019 to $12.9 million for the nine months ended

September 30, 2020.

This overall increase in 2020 is primarily due to increases in employee wages and benefits during the first quarter offset by staff reductions reflected in the third quarter decrease.

Gain on sale and exchange of assets of $15.0 million for the nine months

ended September 30, 2020 consists of principally of sales of deep rights in undeveloped acreage in West Texas and marginal wells in West Virginia.

Interest expense decreased from $0.9 million for the third quarter 2019 to $0.5 million for the third quarter 2020 and

from $2.9 million for the nine months ended September 30, 2019 to $1.6 million for the nine months ended September 30, 2020.

This decrease reflects the decrease in rates and current borrowings under our revolving credit agreement.

Income tax expense or benefit for the September 30, 2020 and 2019 periods varied due to the change in net income or loss

for those periods.

The tax benefit recorded for the nine months ended September 30, 2020 includes the benefits related to tax changes under the CARES Act.

Realized net gains and losses on derivative instruments include net losses of $0.06 million and

$0.15 million on the settlements of natural gas and crude oil derivatives, respectively, for the first quarter 2021, and net gains of $0.19 million and $1.01 million on the settlements of natural gas and crude oil derivatives,

respectively, for the first quarter 2020.

We do not apply hedge accounting to any of our commodity-based derivatives, thus changes in the

fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses

in the accompanying condensed consolidated statements of operations.

As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates

volatility in our revenues.

Changes in market values in the first quarter of 2021 resulted in net unrealized losses of

$0.896 million and $0.015 million associated with crude oil and natural gas contracts, respectively.

Changes in market values in the first quarter of 2020 resulted in net unrealized gains of $6.25 million and $0.31 million

associated with crude oil and natural gas contracts, respectively.

Field service income decreased $2.0 million or 47.4% for the first quarter 2021 to

$2.3 million from $4.3 million for the first quarter 2020.

This decrease is a combined result of decreased utilization and rates charged to customers during the current quarter compared to the same quarter in 2020.

Workover rig services,

hot oil treatments, salt water hauling and disposal represent the bulk of our field service operations.

Lease operating

expense decreased $1.06 million or 16.7% from $6.34 million for the first quarter 2020 to $5.28 million for the first quarter 2021.

This decrease is primarily due to the disposition of marginal properties throughout the second

half of 2020.

Field service expense decreased $1.6 million or 45% to $1.95 million for the first quarter 2021

from $3.55 million for the first quarter 2020.

Field service expenses primarily consist of salaries and vehicle operating expenses which have decreased during the three months ended March 31, 2021 over the same period of 2020 related to

decreased utilization of the equipment during the current quarter compared to the same quarter in 2020.

Depreciation, depletion,

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

quarter of 2021.

General and administrative expense decreased $5.1 million or 66% from $7.7 million for the three

months ended March 31, 2020 to $2.6 million for the three months ended March 31, 2021.

This decrease in 2021 is primarily due to decreases in employee wages and benefits related to staff cut backs implemented late in the first quarter

Interest expense decreased $0.14 million or 20.6% from $0.66 million

for the first quarter 2020 to $0.52 million for the first quarter 2021.

This decrease reflects the decrease in current borrowings under our revolving credit agreement.

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

LIQUIDITY AND CAPITAL RESOURCES

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

Net cash provided by operating activities for the nine months ended September 30, 2020 was $17.9 million.

Excluding the effects of

significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts.

Our oil and gas production will vary based on

actual well performance but may be curtailed due to factors beyond our control.

Our realized oil and gas prices vary due to world

political events, supply and demand of products, product storage levels, and weather patterns.

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

and sales of acreage.

Net cash provided by operating activities for the quarter ended March 31, 2021, was $4.7 million,

compared to $7.4 million in the first quarter of 2020.

Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or

changes in working capital accounts.

Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.

Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather

We sell the majority of our production at spot market prices.

Accordingly, product price volatility will affect our cash flow from operations.

price volatility, we sometimes lock in prices for some portion of our production through the use of derivatives.

If our exploratory

drilling results in significant new discoveries, we will have to expend additional capital to finance the completion, development, and potential additional opportunities generated by our success.

We believe that, because of the additional reserves

resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through bank financing.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy.

For 2020, we will continue our focus on

preserving financial flexibility and ample liquidity as we manage the risks facing our industry.

Our 2020 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow

deficiencies expected to be funded by borrowings under our revolving credit facility.

As we have done historically to preserve or enhance liquidity we may adjust our capital program throughout the year, divest assets, or enter into strategic joint

We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit facility should our borrowing base become limited due to the deterioration of commodity prices.

The Company maintains a Credit Agreement with a maturity date of February 15, 2021, providing for a credit facility totaling

$300 million, with a borrowing base of $48 million.

As of November 25, 2020, the Company has $40.0 million in outstanding borrowings and $8.0 million in availability under this facility.

The bank reviews the borrowing base

semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a re-determined estimate of proved oil and gas reserves.

Our oil and gas properties are pledged as collateral for the line of credit and we

are subject to certain financial and operational covenants defined in the agreement.

To mitigate price volatility, we sometimes lock in prices for some portion of our production

through the use of derivatives.

If our exploratory drilling results in significant new discoveries, we will have to expend additional

capital to finance the completion, development, and potential additional opportunities generated by our success.

We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent

years, we will be able to access sufficient additional capital through bank financing.

Maintaining a strong balance sheet and ample

liquidity are key components of our business strategy.

For 2021, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry.

Our 2021 capital budget is reflective of commodity prices

and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility.

As we have done historically to preserve or enhance liquidity, we may

adjust our capital program throughout the year, divest assets, or enter into strategic joint ventures.

We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit

facility should our borrowing base become limited due to the deterioration of commodity prices.

The Company maintains a Credit Agreement

with a maturity date of February 15, 2023, providing for a credit facility totaling $300 million, with a borrowing base of $40 million.

As of May 15, 2021, the Company has $35.95 million in outstanding borrowings and

$4.05 million in availability under this facility.

The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a

re-determined estimate of proved oil and gas reserves.

The next borrowing base review is scheduled for July 2021.

Our oil and gas properties are pledged as collateral for the line of credit and we are subject

to certain financial and operational covenants defined in the agreement.

We are currently in compliance with these covenants and expect to be in compliance over the next twelve months.

If we do not comply with these covenants on a

continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable.

Our credit agreement required us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review

If we do not comply with these covenants on a continuing basis,

the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable.

Our borrowing base may decrease as a result of lower natural gas or oil prices, operating

difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement.

In the event of a decrease in our borrowing base due to declines in commodity

prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined borrowing base.

Our credit agreement requires us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review

engineering reports.

Accordingly the Company has in place the following swap and put agreements for oil and natural gas.

Accordingly, as of March 31, 2021, the Company has in place the following swap and put agreements for oil and natural gas.

Swap Agreements

2 unchanged sentences

Put Agreements

Natural Gas (MMBTU)

Oil (barrels)

On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the

CARES Act).

The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit

refunds, modifications to the net interest deduction limitations, increased limitations on qualified charitable contributions, and technical corrections to tax depreciation methods for qualified improvement property.

We have experienced significant disruptions to our business and operations.

In particular, COVID-19

restrictions have limited access to our corporate offices and required our corporate personnel, including our legal and accounting staff.

Paycheck Protection Program Loans

During May 2020, Prime Operating Company and Eastern Oil Well Services Corporation, subsidiaries of the Company received loan proceeds in the

amount of $1.28 million and $0.47 million , respectively, under the Paycheck Protection Program (the PPP) of the CARES Act.

The PPP Loans are evidenced by a promissory note in favor of the Lender, which bears interest at the

rate of 1.00% per annum.

No payments of principal or interest are due under the note until the date on which the amount of loan forgiveness (if any) under the CARES Act, which can be up to 10 months after the end of the related notes covered period

(which is defined as 24 weeks after the date of the loan) (the Deferral Period).

The note may be prepaid at any time prior to maturity with no prepayment penalties.

Funds from the PPP Loans may be used only for payroll and related costs,

costs used to continue group health care benefits, mortgage payments, rent, utilities, and interest on other debt obligations that were incurred prior to February 15, 2020 (the Qualifying Expenses).

Under the terms of the PPP Loans,

certain amounts thereunder may be forgiven if they are used for Qualifying Expenses as described in and in compliance with the CARES Act.

While the Company intends to use the PPP Loan proceeds exclusively for Qualifying Expenses, it is unclear and

uncertain whether the conditions for forgiveness of the PPP Loans will be met under the current guidelines of the CARES Act.

Accordingly, we cannot make any assurance that the Company will be eligible for forgiveness of the PPP Loans, in whole or in

To the extent, if any, that any or all of the PPP loans are not forgiven, beginning one month following expiration of the Deferral Period, and continuing monthly until 24 months from the date of each applicable Note (the Maturity

Date), the Company is obligated to make monthly payments of principal and interest to the Lender with respect to any unforgiven portion of the Note, in such equal amounts required to fully amortize the principal amount outstanding on such Note

as of the last day of the applicable Deferral Period by the applicable Maturity Date.

The Companys activities include development

and exploratory drilling.

Our strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential.

In 2016, based upon the results

of horizontal wells and historical vertical well performance, we decided to reduce the number of vertical wells in our drilling program and focus primarily on horizontal well drilling.

We believe horizontal development of our resource base provides

superior returns relative to vertical development, due to the ability of horizontals to come in contact with and drain from a greater volume of reservoir rock over more acreage, with less infrastructure, and thus at a lower cost of development per

Since the start of our West Texas horizontal drilling program in 2015 and through the third

quarter of 2020 the Company has participated in 74 horizontal wells in the Permian Basin, seven of which were drilled in the first half of 2020.

Through July 2020, the Company has invested approximately $112 MM in our West Texas horizontal drilling

Of the 74 total horizontal wells participated in, we have an average of 24% working interest.

In 2019, 11 wells were brought on production:

the Company has 49% interest in eight of these wells, all

one-mile in length, located on our CC-33 tract, and an average 48% interest in two horizontals and 5.3% interest in one additional horizontal, that are each two-miles in length, located on the Kashmir tract.

The Company invested approximately $31.5 million in these 11 wells brought on production in 2019.

Through the second quarter of 2020, the Company participated

in seven new horizontal wells, all located in Upton County, Texas.

Six of these are operated by Apache Corporation and one is operated by Pioneer Natural Resources.

The Pioneer well was completed in late June and came on production in early July

The six Apache operated wells are anticipated to be completed the end of February or beginning of March 2021.

In Upton County, West

Texas, we are developing a contiguous 3,260-acre block with our joint venture partner, Apache Corporation.

In this block the Company has 2,600 leasehold acres with interest between 14% and 56%, depending on

the particular lease and depth being developed.

In 2018, in this block, eight wells drilled horizontally in the Wolfcamp B, were participated in for 49% interest.

This is believed to be full development of the Wolfcamp B

reservoir for this lease block.

Apache will likely now set its sights on development of the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs for this block, following the recent successful testing in 2019 of these reservoirs on our offset 1,300-acre lease block.

Given the favorable results achieved by the initial three wells on the offset block, it is expected that as many as 54 additional horizontals will be slated for development on the 3,260-acre block in the near future.

The cost of such development would be approximately $370.6 million with the Companys share being approximately $170.8 million.

In addition, there is a fourth

target reservoir, the Middle Spraberry, that is also prospective for development.

The potential of the Middle Spraberry, on the 3,280-acre block, is for 18 horizontal wells to be drilled, with the Company

likely participating for approximately $61.8 million.

The actual number of wells that are eventually drilled as well as the cost and the timing of drilling will vary based upon many factors, including commodity market conditions.

In addition to the 3,260 acreage block under development, the Company is also developing an offsetting

1,300-acre block in Upton County, Texas with Apache Corporation as operator.

In the second quarter of 2019 three horizontal wells were completed and brought on production from reservoirs above the Middle

one in the Wolfcamp A, one in the Jo Mill, and one in the Lower Spraberry, confirming the economic viability of these reservoirs on our acreage.

Prime holds between 5% and 48% working interest in various depths of this acreage,

and of the $26.7 million development cost for these three wells, our share was approximately $9.2 million.

As a result of the success of these three wells, six horizontals were drilled in the first half of 2020 on this acreage block.

have an average 47.76% share of these wells.

In addition to the six development locations in the Wolfcamp A, Jo Mill and Lower Sprayberry of our 1,300-acre block, there are four locations in the

Middle Spraberry that are likely to be considered for future development at an estimated gross cost of approximately $30.2 million, with the Companys share being approximately $14.2 million.

Also in the first half of 2020, the

Company participated in a horizontal well for 8.36% interest operated by Pioneer Natural Resources that was completed and brought into production in July, 2020.

Our total net expenditure for this well has been approximately $630,000.

Also in the Permian Basin of West Texas, we are developing a 965-acre block with Concho Resources in

Martin County, Texas.

In 2016 and 2017, four horizontal wells were drilled and completed and put on production.

The Company owns 35% to 38% interest in this joint venture acreage where Concho Resources is the operator.

No near-term additional

In Central Reagan County, of West Texas, during the third quarter of 2020, the Company has sold deep rights covering approximately 1,950 acres

for a purchase price of $10.3 million to-date, with a final total compensation expected to be $10.7 million.

Since the start of our Oklahoma Scoop-Stack horizontal development program, which began in 2013, the Company has participated in 41 horizontal

wells for approximately $23.5 million through 2019 with an average of approximately 7% interest.

There have been no new wells participated in through the third quarter of 2020.

During this same period the Company chose to retain an overriding

royalty interest in an additional 69 horizontal wells.

In 2019, the Company participated for an average 5.78% interest in 20 horizontal wells in Canadian, Grady, and Kingfisher counties for a net cost of approximately $8.8 million.

were completed in 2019, and of these 20 wells, twelve are operated by Encana/Newfield.

In addition, the Company is also participating in four wells in Grady County, Oklahoma spud in 2018 that have not yet been completed.

During 2019, in Oklahoma,

the Company retained an overriding royalty interest in eighteen wells, nine of which were completed in 2019, and nine of which have yet to be completed.

Through the third quarter of 2020, the Company has retained an interest in four wells located in

Canadian County, Oklahoma, completed in February of this year.

Our horizontal activity in Oklahoma is focused in Canadian, Grady,

Kingfisher, Garfield, Major, and Garvin counties where we have approximately 3,401 net acres.

We believe this acreage has significant additional resource potential that could support the drilling of as many as 49 new horizontals based on an estimate

of six wells per section:

The Companys activities include development and exploratory drilling.

Our strategy is

to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential.

In 2016, based upon the results of horizontal wells and historical

vertical well performance, we decided to reduce the number of vertical wells in our drilling program and focus primarily on horizontal well drilling.

We believe horizontal development of our resource base provides superior returns relative to

vertical development, due to the ability of horizontals to come in contact with and drain from a greater volume of reservoir rock over more acreage, with less infrastructure, and thus at a lower cost of development per acre.

In 2019, we participated in the drilling of three horizontal wells in Upton County, Texas, adding significantly to our proved reserves, as

these probable undeveloped locations were the initial test wells in the Wolfcamp A the Jo Mill and the Lower Spraberry of this acreage.

These tests proved-up these reservoirs for the 1,280 acre

block in which they were drilled and led to the drilling of nine additional wells in 2020 and the first quarter of 2021.

In early 2020,

six of the nine horizontals mentioned above were drilled, and in the first quarter of 2021 the remaining three were drilled.

All nine wells are slated for completion and to be on production by the end of the second quarter of 2021.

average 47.5% interest in these wells and our anticipated total investment is expected to be approximately $27 million.

successful development of these reservoirs has also proved-up locations to be drilled on our nearby 3,260-acre block in which the Company holds between 14% and 56%

It is anticipated that development of as many as 54 additional horizontal wells on this 3,260-acre block will occur over the coming years.

The cost of such development will be approximately

$370 million with the Companys share being approximately $170 million.

The actual number of wells that will be drilled, the cost, and the timing of drilling will vary based upon many factors, including commodity market conditions.

Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and

availability of funds under our revolving credit facility.

The Company maintains an acreage position of 19,680 gross (12,460 net) acres

in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties and we believe this acreage has significant resource potential in as many as 10 reservoirs, including benches of the Spraberry, Jo Mill, and Wolfcamp that

support the potential drilling of as many as 180 additional horizontal wells.

In Oklahoma, the Companys horizontal activity is

primarily focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 3,460 net leasehold acres.

We believe this acreage has significant additional resource potential that could support the drilling of as

many as 52 new horizontal wells based on an estimate of six wells per section:

three in the Mississippian and three in the Woodford Shale.

Should we choose to participate in future development, our share of the capital expenditures would be approximately $34 million at an average 10% ownership

Should we choose to participate in future development, our share of the capital expenditures would be

approximately $12 million at an average 10% ownership level;

the Company will otherwise sell its rights for cash, or cash plus a royalty or working interest.

In early August 2020, the Company

closed on the sale of its West Virginia District operated assets.

The sale includes 456 producing wells, along with approximately 35,000 leasehold acres, one salt water disposal well, and operating equipment.

The Company has retained an overriding

royalty interest, up to 12.5%, in any future drilling of these properties.

The majority of our capital spending is discretionary, and the

ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in

The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil

and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.

The Company has in place both a stock repurchase program and a limited partnership interest repurchase program.

Spending under

these programs in 2020 and 2019 was $0.71 million and $5.9 million, respectively.

In the current price environment, the Company will suspend their stock repurchase program.

Spending under these programs

in 2020 was $1,452 million.

The Company expects continued spending under these programs in 2021.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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Item 1. Financial Statements