What changed in this filing

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Item 7. Management’s Discussion and Analysis

2023-04-17 compared with 2022-04-21 · 80 added, 88 removed, 96 unchanged (64% of the section changed)

4 unchanged sentences

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

We presently own producing and non-producing

properties located primarily in Texas, and Oklahoma.

We presently own producing and non-producing properties located primarily in Texas, and Oklahoma.

In addition, we own a substantial amount of well servicing equipment.

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This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements.

Since all our derivative contracts are accounted for under mark-to-market

accounting, we expect continued volatility in gains and losses on mark-to-market

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

Since all our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.

Market Conditions and Commodity Prices:

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Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively.

Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production

Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method.

The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties.

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Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

Asset Retirement Obligation (ARO ) :

The Company has significant obligations to remove tangible equipment and restore land at the end of oil and gas production operations.

The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells.

Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments.

Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.

ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable.

The liability is offset by a corresponding increase in the underlying asset.

liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties.

The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments.

Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value

Liquidity and Capital Resources:

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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 11, 2023, providing for a credit facility totaling $300 million, with a borrowing base of $50 million.

As of March 31, 2022, the Company has $9 million in outstanding borrowings and $41 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 Company maintains a Credit Agreement with a maturity date of June 1, 2026, providing for a credit facility totaling $300 million, with a borrowing base of $60 million.

As of March 31, 2023, the Company has no outstanding borrowings and $60 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 May 2023.

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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 required us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports.

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Oil (barrels)

The successful development of these reservoirs has proven-up

drilling locations on our nearby 2,600-acre

leasehold block in which the Company holds between 14% and 56% interest.

It is anticipated that development of as many as 54 additional horizontal wells on this 2,600-acre

block will occur over the coming years.

The cost of such development will be approximately $370 million with the Company’s share being approximately $170 million.

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

The Company is currently participating with SEM Operating Company, LLC in four horizontal wells in Irion County, Texas with 10.3% interest for an estimated investment of $2.35 million.

These wells are expected to be online in the second quarter of 2022.

Additional Permian Basin development drilling plans in 2022 include the drilling of nine 2.5-mile

horizontal wells with BTA Oil Producers in Reagan County, Texas.

The Company will have an average of 43.67 % interest in these wells with an expected capital outlay of $40.5 million through completion.

These wells are scheduled to be drilled in June and completed in 2022.

Also in 2022, in the Permian Basin of West Texas, the Company plans to drill four horizontal wells with ConocoPhilips in Martin County with an average of 38% interest.

The total capital expenditure for these wells is expected to be $15 million.

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 17,148 gross (10,640 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 2021, in the Scoop/Stack Play of Oklahoma, the Company participated for 11.25% interest in the drilling of four wells and the completion of three of these wells in December that were placed on production in early January of 2022.

The Company had an expenditure of approximately $2.2 million.

In the first quarter of 2022, the Company received and approved proposals from Ovintiv Mid-Continent,

for the drilling of four horizontal wells in Canadian County, Oklahoma.

Drilling will begin in April and completion of these wells are expected in June of this year.

The Company will participate for 9.38% and expects total drilling and completion costs to be approximately $1.8 million.

The Company’s activities include development and exploratory drilling.

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

Horizontal development of our resource base provides superior returns relative to vertical development due to the ability of each horizontal wellbore to come in contact with a greater volume of reservoir rock across a greater distance, more efficiently draining the reserves with less infrastructure and thus at a lower cost per acre.

In 2022 the Company participated with SEM Operating Company, LLC in four horizontal wells in Irion County, Texas with 10.3% interest for approximately $2.35 million and with Ovintiv Mid-Continent, Inc.

in four horizontal wells in Canadian County with an average of 9% interest for $1.77 million.

All eight wells were put into production in August of 2022.

In the fourth quarter of 2022, we began participation in the drilling of 20 horizontal wells located in West Texas operated by three different operators.

In Martin County, we are participating with ConocoPhillips in five 2.5-mile-long horizontal wells in which the Company has 20.83% interest with a planned capital expense of $12.1 million.

In Reagan County we are participating with Hibernia Energy III in 10 two-mile horizontals with 25% interest and an expected investment of $25.6 million.

Also in Reagan County, we are participating with Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest, carrying an expected net capital outlay of $23.4 million.

All twenty of these West Texas wells are currently drilling or have been completed.

All are expected to be on line in the second quarter of 2023.

In January of 2023, the Company joined Ovintiv USA, Inc.

in the spudding of three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96% interest and an expected investment of $645,000.

Production is expected to begin in May, 2023.

In addition, in March of 2023, Apache Corporation has spud two 3-mile-long horizontals in Upton County, Texas in which the Company has 49.4% interest with an expected total capital investment of $16,1 million.

We anticipate completion of these two 15,000’ long horizontals in Upton County in May and production to occur in June of 2023.

In total, the Company expects to invest $78 million dollars in these 25 horizontal wells.

We prepaid drilling costs of $32 million in December of 2022 and the remaining $46 million estimated drilling and completion expenditures will occur in 2023.

All 25 wells are expected to be completed and on-line in the second quarter of 2023.

We anticipate that success from the 22 horizontals in West Texas described above will lead to additional near-term horizontal drilling covering five leasehold blocks in three counties of West Texas:

29 additional 10,000’ long horizontals in Reagan County with Hibernia, Double Eagle and BTA Oil Producers, ten additional 12,500’ long horizontals in Martin County with ConocoPhillips, and six additional 15,000’ long horizontals in Upton County with Apache.

These anticipated additional 42 drilling proposals will target various proven pay intervals of the Wolfcamp and Spraberry formations and will require an estimated $200 million in net capital investment.

In addition, we have more than 200 drilling locations that could potentially be developed.

In West Texas the Company maintains an acreage position of 16,940 gross (9,969 net) acres, primarily in Reagan, Upton, Martin, and Midland counties where our horizontal activity is focused.

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 200 additional horizontal wells.

In Oklahoma, the Company’s horizontal activity is primarily focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 4,113 net leasehold acres in the Scoop/Stack Play.

We believe this acreage has significant additional resource potential that could support the drilling of as many as 54 new horizontal wells based on an estimate of six wells per section:

two in the Mississippian and two in the Woodford Shale.

Should we choose to participate in future development, our share of the capital expenditures would be approximately $36 million at an average 10% ownership level;

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

To supplement cash flow and finance our drilling program during 2021, the Company sold leasehold rights through one transaction in Texas, receiving gross proceeds of approximately $1.45 million in exchange for 116 net leasehold acres.

In the first quarter of 2022, The Company sold 1,809 net leasehold acres in Regan and Midland Counties, Texas through two transactions receiving gross proceeds of $14.1 million and retaining certain over-riding royalty interests.

These sales have allowed the Company to reduce its bank debt to $9 million, as of March 31, 2022, with the right to borrow up to $50 million under its current revolving line of credit.

Of this acreage we believe 2,355 net acres holds significant additional resource potential that could support the drilling of as many as 46 new horizontal wells based on an estimate of four wells per multi-section drilling unit, two in the Mississippian and two in the Woodford Shale.

In the near term, we anticipate nine new drilling proposals to be received with an estimated net expense of $5.2 million covering 338 net leasehold acres.

Proposals may be received on the remaining 2,017 acres, however, rather than participate we may choose to sell the acreage or farm-out receiving cash and retaining an over-riding royalty interest.

During 2022, to supplement cash flow and finance our future drilling programs, the Company entered into an agreement with Double Eagle to create a 2,560-acre AMI for the joint development of horizontal wells;

as part of this agreement, the Company sold a portion of its interest in this acreage for proceeds of $16.1 million.

In addition, in 2022, we sold 240 net acres in Reagan County to BTA Oil Producers for proceeds of $1.8 million, and we sold 353 net acres in Canadian County, Oklahoma to Paloma Partners, IV, Inc.

for $1.3 million.

Through three other transactions, we divested a minor tract in Lea County, NM for a nominal cash consideration and assigned nine wellbores in West Texas to a third-party operator in exchange for a reduction in our future plugging liability.

In this same year, the Company acquired 3.2 net mineral acres in Upton County, Texas for $16,000.

These sales along with our cash flow have allowed the Company to eliminate its bank debt as of March 31, 2023, with the right to borrow up to $60 million under its current revolving line of credit.

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 a stock repurchase program in place, spending under this program in 2021 and 2020 was $145 thousand and $710 thousand, respectively.

The Company has a stock repurchase program in place, spending under this program in 2022 and 2021 was $7.4 million and $145 thousand, respectively.

The Company expects continued spending under the stock repurchase program in 2023.

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2022 and 2021 Compared

We reported a net income of $2.1 million for 2021, or $1.05 per share, compared to a net loss of $2.3 million, or $1.16 per share for 2020.

The current year net income reflects commodity price increases partially offset by losses related to the valuation of derivative instruments.

We reported a net income of $48.7 million for 2022, or $24.91 per share, compared to $2.1 million, or $1.05 per share for 2021.

The current year net income reflects production and commodity price increases, partially offset by losses related to derivative instruments.

The significant components of income and expense are discussed below.

Oil, NGL and gas sales

increased $36.1 million, or 97.6% to $73.1 million for the year ended December 31, 2021 from $37.0 million for the year ended December 31, 2020.

Oil, NGL and gas sales increased $51.1 million, or 69.7% to $124.1 million for the year ended December 31, 2022 from $73.1 million for the year ended December 31, 2021.

Crude oil, NGL and natural gas sales vary due to changes in volumes of production sold and realized commodity prices.

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Our crude oil production increased by 201,000 barrels, or 27.24% to 939,000 barrels for the year ended December 31, 2022 from 738,000 barrels for the year ended December 31, 2021.

Our NGL production decreased by 21,000 or 4.85% to 416,000 for the year ended December 31, 2021 from 437,000 barrels for the year ended December 31, 2020.

Our natural gas production decreased by 145 MMcf, or 4.29% to 3,236 MMcf for the year ended December 31, 2021 from 3,381 MMcf for the year ended December 31, 2020.

The changes in crude oil, NGL and natural gas production volumes are a result of the natural decline of existing properties slightly offset by new wells placed in production.

Our NGL production increased by 1,000 or 0.24% to 417,000 for the year ended December 31, 2022 from 416,000 barrels for the year ended

December 31, 2021.

Our natural gas production increased by 89 MMcf, or 2.75% to 3,325 MMcf for the year ended December 31, 2022 from 3,236 MMcf for the year ended December 31, 2021.

The changes in crude oil, NGL and natural gas production volumes are a result of new wells placed in production offset by the natural decline of existing properties.

The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2022 and 2021 (excluding realized gains and losses from derivatives).

Twelve months ended

Barrels of Oil Produced

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Total Oil & Gas Revenue (In 000’s)

Oil, Natural Gas and NGL Derivatives

We do not apply hedge accounting to any of our commodity based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market

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

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

accounting treatment creates volatility in our revenues.

The following table summarizes the results of our derivative instruments for the twelve months ended December 2021 and 2020:

Twelve months ended

Oil derivatives – realized (losses) gains

Oil, Natural Gas and NGL Derivatives We do not apply hedge accounting to any of our commodity based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations.

As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues.

The following table summarizes the results of our derivative instruments for the years ended December 2022 and 2021:

Oil derivatives – realized gains (losses)

Oil derivatives – unrealized (losses) gains

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Natural gas derivatives – realized (losses) gains

Natural gas derivatives – unrealized (losses)

Natural gas derivatives – unrealized gains (losses)

Total (losses) gains on natural gas derivatives

Total (losses) gains on oil and natural gas

Prices received for the twelve months ended December 31, 2021 and 2020, respectively, including the impact of derivatives were:

Field service income

increased $0.7 million, or 6.3% to $11.8 million for the year ended December 31, 2021 from $11.1 million for the year ended December 31, 2020.

This increase is a combined result of increased utilization and rates charged to customers as oil and gas prices improved during 2021.

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

Lease operating expenses

increased $4.8 million, or 20.9% to $27.8 million for the year ended December 31, 2021 from $23.0 million for the year ended December 31, 2020.

This increase is primarily due to returning higher lifting cost properties to production during 2021 as commodity prices improved, combined with higher production taxes related to higher commodity prices.

Field service expense

increased $2.6 million, or 28.9% to $11.6 million for the year ended December 31, 2021 from $9.0 million for the year ended December 31, 2020.

Prices received for the years ended December 31, 2022 and 2021, respectively, including the impact of derivatives were:

Field service expense increased $1.9 million, or 20.7% to $11.1 million for the year ended December 31, 2022 from $9.2 million for the year ended December 31, 2021.

Field service expenses primarily consist of wages and vehicle operating expenses which have increased during 2022 related to increased utilization of our equipment services.

Depreciation, depletion, amortization and accretion on discounted liabilities

decreased $1.9 million, or 6.7% to $26.3 million for the year ended December 31, 2021 from $28.2 million for the year ended December 31, 2020.

The DD&A expense is primarily attributable to our properties in West Texas and Oklahoma, reflecting the declining cost basis of those properties.

General and administrative expense

decreased $4.6 million, or 30.7% to $10.4 million for the year ended December 31, 2021 from $15.0 million for the year ended December 31, 2020.

This decrease in 2021 reflects cost reductions put in place during 2020 responding to sharply lower commodity prices, primarily reductions in staff and compensation.

Gain on sale and exchange of assets

of $1.5 million for the year ended December 31, 2021 and $15.8 million for the year ended December 31, 2020 consists principally of sales of deep rights in undeveloped acreage in West Texas and, in 2020, also included the sale of marginal wells in West Virginia.

expense increased $0.1 million, or 5.3% to $2.0 million for the year ended December 31, 2021 from $1.9 million for the year ended December 31, 2020.

The average interest rate paid on outstanding bank borrowings under its revolving credit facility during 2021 and 2020 were

5.29% and 3.95%, respectively.

As of December 31, 2021 and 2020, the total outstanding borrowings under its revolving credit facility were $36.0 million and $37.0 million, respectively.

expense of $2.5 million and tax benefit of $0.5 million were recorded for the years ended December 31, 2021 and 2020, respectively.

The change in our income tax provision was primarily due to the increase in pre-tax

income for the year ended December 31, 2021.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $1.8 million, or 6.8% to $28.1 million for the year ended December 31, 2022 from $26.3 million for the year ended December 31, 2021.

The DD&A expense is primarily attributable to our properties in West Texas and Oklahoma, reflecting the addition of new properties offset by the declining cost basis of existing properties.

General and administrative expense increased $11.1 million, or 122.0% to $20.2 million for the year ended December 31, 2022 from $9.1 million for the year ended December 31, 2021.

This increase in 2022 is primarily due to increased employee count, compensation and benefits

Gain on sale and exchange of assets of $31.8 million for the year ended December 31, 2022 and $1.5 million for the year ended December 31, 2021 consists principally of sales of deep rights in undeveloped acreage in West Texas.

Interest expense decreased $1.1 million, or 55.0% to $0.9 million for the year ended December 31, 2022 from $2.0 million for the year ended December 31, 2021.

This decrease reflects the reduced borrowings under our revolving credit agreement offset by an increase in rates.

Tax expense of $10.3 million and $2.5 million were recorded for the years ended December 31, 2022 and 2021, respectively.

The change in our income tax provision was primarily due to the increase in pre-tax income for the year ended December 31, 2022.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The consolidated financial statements and supplementary information included in this Report are described in the Index to Consolidated Financial Statements at Page F-1

of this Report.

The consolidated financial statements and supplementary information included in this Report are described in the Index to Consolidated Financial Statements at Page F-1 of this Report.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis