What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2023-03-09 compared with 2022-03-16 · 187 added, 140 removed, 170 unchanged (66% of the section changed)

1 unchanged sentence

The following discussion and analysis should be read in conjunction with our accompanying financial statements and the notes to those financial statements included elsewhere in this Annual Report.

The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs and our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors” and elsewhere in this Annual Report.

Ring is a growth oriented independent exploration and production company based in The Woodlands, Texas and is engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in Texas and New Mexico.

Our primary drilling operations target the oil and liquids rich producing formations in the Northwest Shelf, the Central Basin Platform, and the Delaware Basin all of which are part of the Permian Basin in Texas and New Mexico.

Business Description and Plan of Operation

3 unchanged sentences

2022 Developments and Highlights

As the weak commodity price environment began to recover and the contraction in oil demand seen from the COVID-19 pandemic began to ease, Ring initiated its Phase I four well program in the Northwest Shelf Asset by drilling two wells in December 2020 and two wells in January 2021.

All four wells were completed and placed on production during first quarter 2021.

During that quarter, the Company also performed nine conversions from electrical submersible pumps to rod pumps (such conversions, “CTRs”) with seven performed in the Northwest Shelf and two in the Central Basin Platform.

New wells were added throughout the year by drilling in phases, to ensure the Company would continue operating within cash flow.

In the second quarter of 2021, the Company completed its Phase II drilling program and placed on production three new horizontal San Andres wells in the Northwest Shelf, along with four additional CTRs in the Northwest Shelf and one CTR in the Central Basin Platform.

in the third quarter of 2021, the Phase III drilling program resulted in two horizontal San Andres wells in Northwest Shelf and two horizontal San Andres wells in the Central Basin Platform.

During third quarter 2021, the Company also performed seven CTRs in the Northwest Shelf and three CTRs in the Central Basin Platform.

In the fourth quarter of 2021, the Company drilled one new well and performed one CTR in the Northwest Shelf and drilled one new well in the Central Basin Platform.

Lastly, during 2021 the Company participated with offset operators in two wells in the Northwest Shelf Asset as a non-operated working interest owner.

Our oil and natural gas producing properties are located in the Permian Basin of Texas and New Mexico.

Oil sales represented approximately 92.5% and 96.5% of our total revenue for the twelve months ended December 30, 2021 and 2020, respectively.

The 4% variance in oil sales revenue was due to higher realized gas and NGL prices in 2021.

As of December 31, 2021, we had in place derivative contracts covering 3,129 barrels of oil per day for the calendar year 2022.

All of the 3,129 barrels of oil in 2022 are in the form of swaps of WTI Crude Oil prices.

The oil swap prices for 2022 range from $44.22 to $50.05, with a weighted average swap price of $46.60.

Our 2021 derivative hedges resulted in total unrealized fair value loss of approximately $25.1 million for the year ended December 31, 2021 and realized loss on derivatives of approximately $52.8 million for the year ended December 31, 2021.

All of our hedges are financial hedges and do not have physical delivery requirements.

In December 2021, the semi-annual redetermination of our lending group reaffirmed our borrowing base of $350 million, as well as continued the prior hedging requirement of 3,100 barrels per day of crude oil sales for the calendar year 2022.

During the fourth quarter, the Company paid down approximately $5 million in debt leaving approximately $290 million outstanding on our credit facility as of December 31, 2021.

Stronghold Acquisition

On July 1, 2022, Ring, as buyer, and Stronghold Energy II Operating, LLC, a Delaware limited liability company (“Stronghold OpCo”) and Stronghold Energy II Royalties, LP, a Delaware limited partnership (“Stronghold RoyaltyCo”, together with Stronghold OpCo, collectively, “Stronghold”), as seller, entered into a purchase and sale agreement (the “Purchase Agreement”).

Pursuant to the Purchase Agreement, Ring acquired (the “Stronghold Acquisition”) interests in oil and gas leases and related property of Stronghold consisting of approximately 37,000 net acres located in the Central Basin Platform of the Texas Permian Basin.

On August 31, 2022, Ring completed the Stronghold Acquisition.

The fair value of consideration paid to Stronghold was approximately $394.0 million, of which $165.9 million, net of customary purchase price adjustments, was paid in cash at closing, $15.0 million was paid in cash after the six-month anniversary of the closing date of the Stronghold Acquisition.

Shortly after closing, approximately $4.5 million was paid for inventory and vehicles and approximately $1.8 million was paid for August oil derivative settlements for certain novated hedges.

The cash portion of the consideration was funded primarily from borrowings under a new fully committed revolving credit facility (the “Credit Facility”) underwritten by Truist Securities, Citizens Bank, N.A., KeyBanc Capital Markets Inc., and Mizuho Bank, Ltd.

The borrowing base of the $1.0 billion Credit Facility was increased from $350.0 million to $600.0 million at the closing of the Stronghold Acquisition.

The remaining consideration consisted of 21,339,986 shares of Ring common stock and 153,176 shares of newly created Series A Convertible Preferred Stock, par value $0.001 (“Preferred Stock”) which was converted into 42,548,892 shares of common stock on October 27, 2022.

Please see "Note 12 - STOCKHOLDERS' EQUITY" for further discussion.

In addition, Ring assumed $24.8 million of derivative liabilities,$1.7 million of items in suspense and $14.5 million in asset retirement obligations.

Drilling, Completion, and Recompletion

In the first quarter of 2022, we contracted a rig for our horizontal drilling program and began operations on January 31st.

We drilled and completed three 1-mile horizontal wells and one 1.5-mile horizontal well in the Central Basin Platform.

We then moved the rig to the Northwest Shelf and drilled two 1-mile horizontal wells.

All wells drilled in the first quarter had a working interest of 100%.

In the second quarter of 2022, we drilled a total of nine wells, completed seven wells, and began the completion process on four wells, all in the Northwest Shelf.

The first wells completed were the two 1-mile horizontal wells, which were drilled in the first quarter.

Next, we drilled and completed two 1-mile horizontal wells with a working interest of

100%, two 1.5-mile horizontal wells with a working interest of approximately 98.7% and one 1-mile horizontal well with a working interest of approximately 75.4%.

We also drilled and began the completion process on an additional four 1-mile horizontal wells.

Two of the wells have a working interest of 100%, one has a working interest of approximately 87.9%, and the fourth has a working interest of 75%.

In the third quarter of 2022, we completed and placed on production the four aforementioned 1-mile horizontal wells in the Northwest Shelf, which were drilled in the second quarter.

Next, we drilled and completed two 1.5-mile horizontal wells and one 1-mile horizontal well in the Central Basin Platform and two 1-mile horizontal wells in the Northwest Shelf, each with a working interest of 100%.

During the last month of the quarter, we drilled and began the completion process on three 1-mile horizontal wells in the Northwest Shelf, two with a working interest of 99.7% and one with a working interest of 100%.

In total, during the third quarter of 2022, we drilled eight, completed nine, and began the completion process on three horizontal wells.

With the addition of the Stronghold Acquisition assets in the Central Basin Platform, we also performed three vertical well re-completions.

In the fourth quarter of 2022, we completed and placed on production the three aforementioned 1-mile horizontal wells in the Northwest Shelf.

Next, we drilled and completed two 1-mile horizontal wells with a working interest of 100%, also in the Northwest Shelf.

To complete the 2022 horizontal drilling program, we drilled and completed two 1.5-mile horizontal wells in the Central Basin Platform.

In addition to the horizontal wells, we performed nine more vertical well re-completions and drilled and completed five new vertical wells on the Stronghold Acquisition assets located in Crane County, Texas, of the Central Basin Platform, all with a working interest of 100%.

In summary, for 2022, we drilled and completed 27 horizontal wells and 5 vertical wells, along with 12 vertical well re-completions on the Stronghold Acquisition assets.

The table below sets forth our drilling and completion activities for 2022 by quarter through December 31, 2022.

Quarter Area Wells Drilled Wells Completed Recompletions

1Q 2022 Central Basin Platform (Horizontal) 4 4 —

Central Basin Platform (Vertical) — — —

Northwest Shelf 2 — —

2Q 2022 Central Basin Platform (Horizontal) — — —

Central Basin Platform (Vertical) — — —

Northwest Shelf 9 7 —

3Q 2022 Central Basin Platform (Horizontal) 3 3 —

Central Basin Platform (Vertical) — — 3

Northwest Shelf 5 6 —

4Q 2022 Central Basin Platform (Horizontal) 2 2 —

Central Basin Platform (Vertical) 5 5 9

Northwest Shelf 2 5 —

Market Conditions and Commodity Prices

2 unchanged sentences

As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes or revenues.

The pandemic induced reduction in oil prices experienced in 2020 and the improvement of oil and natural gas prices experienced in 2021 continues to demonstrate commodity price volatility and we believe oil and natural gas prices may continue to be volatile for the foreseeable future.

The improvement of oil and natural gas prices experienced in 2022 continues to demonstrate commodity price volatility and we believe oil and natural gas prices will continue to be volatile for the foreseeable future.

The ability to find and develop sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success.

3 unchanged sentences

Net production:

Oil (Bbls) 3,459,840 2,686,940 2,801,528

Natural gas (Mcf) 4,088,642 2,535,188 2,494,502

Natural gas liquids (Bbls) 371,329 — —

Oil $ 321,062,672 $ 181,533,093 $ 109,113,557

Natural gas 18,693,631 14,772,873 3,911,581

Natural gas liquids 7,493,234 — —

Average sales price:

1 unchanged sentence

Natural gas (per Mcf) 4.57 5.83 1.57

Natural gas liquids (Bbl) 20.18 — —

Production costs and expenses:

3 unchanged sentences

Production taxes 17,125,982 9,123,420 5,228,090

Other costs and operating expenses:

Depreciation, depletion and amortization expense $ 55,740,767 $ 37,167,967 $ 43,010,660

Ceiling test impairment — — 277,501,943

Gain (loss) on derivative contracts

Asset retirement obligation accretion 983,432 744,045 906,616

3 unchanged sentences

Stock-based compensation expense 7,162,231 2,418,323 5,364,162

Other income (expense):

Interest (expense) $ (23,167,729) $ (14,490,474) $ (17,617,614)

Gain (loss) on derivative contracts (21,532,659) (77,853,141) 21,366,068

Deposit forfeiture income — — 5,500,000

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

Oil sales increased approximately $139.5 million from $181.5 million in 2021 to $321.1 million in 2022.

The oil sales increase was the result of an increase in the average realized per barrel oil price from $67.56 in 2021 to

$92.80 in 2022 and an increase in sales volume from 2,686,940 barrels of oil in 2021 to 3,459,840 barrels of oil in 2022.

The increased average realized per barrel oil price was a result of the significantly higher oil price during the first eight months of 2022.

The increased sales volumes were a direct result of assets acquired in the Stronghold Acquisition, which resulted in higher volumes for the last four months of 2022, as well as organic growth from capital expenditures that were $78.0 million greater in 2022 than in 2021.

Natural gas sales.

Natural gas sales increased approximately $3.9 million from $14.8 million in 2021 to $18.7 million in 2022.

The natural gas sales volume increased from 2,535,188 Mcf in 2021 to 4,088,642 Mcf in 2022 and the average realized per Mcf gas price decreased from $5.83 in 2021 to $4.57 in 2022.

The sales volume increase was due to the aforementioned increase in capital expenditures as well as the Stronghold Acquisition, which closed August 31, 2022.

The price decrease was driven by the Company's change in reporting presentation from two-stream (oil and natural gas) to three-stream (oil, natural gas and natural gas liquids) beginning July 1, 2022.

Natural gas liquids sales.

Natural gas liquids sales increased approximately $7.5 million from $0.0 million in 2021 to $7.5 million in 2022.

NGL sales volumes in were 371,329 barrels of NGLs compared to zero barrels in 2021, due to the Company’s change in reporting presentation for its natural gas products, which are presented on a three-stream basis beginning July 1, 2022.

The average realized price per barrel of NGLs was $20.18 in 2022.

Lease operating expenses.

Our total lease operating expenses (“LOE”) increased from $30,312,399 in 2021 to $47,695,351 in 2022 and increased on a Boe basis from $9.75 in 2021 to $10.57 in 2022.

These per Boe amounts are calculated by dividing our total lease operating expenses by our total volume sold, in Boe.

LOE increased primarily due to a 45% increase in production of 1,403,502 Boe year-over-year, as well as increased costs for goods and services due to increased Permian activity.

Gathering, transportation and processing costs.

Our total gathering, transportation and processing costs (“GTP”) decreased from $4,333,232 in 2021 to $1,830,024 in 2022 and decreased on a Boe basis from $1.39 in 2021 to $0.41 in 2022.

GTP costs decreased due to costs classified as a reduction to oil and natural gas sales revenues, due to a natural gas processing entity beginning to take control of transportation at the wellhead beginning May 1, 2022.

Ad valorem taxes.

Our total ad valorem taxes increased from $2,276,463 in 2021 to $4,670,617 in 2022 and increased on a Boe basis from $0.73 in 2021 to $1.04 in 2022.

Ad valorem taxes increased primarily due to the increase in taxed commodity prices from the prior year, as well as $783,159 for the properties acquired in the Stronghold Acquisition.

Oil and natural gas production taxes .

Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.65% during 2021 and increased to 4.93% in 2022.

Overall, the percentage was consistent year over year, with a slight increase due to proportionately higher gas revenues which are taxed at a higher rate.

Production taxes vary from state to state.

Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states (currently only Texas and New Mexico), and on the possibility that any state may raise its production tax rates.

Depreciation, depletion and amortization .

Our depreciation, depletion and amortization expense increased from $37,167,967 in 2021 to $55,740,767 in 2022 due to an increase in our total estimated costs of property as well as an increase of 1,403,502 in Boe produced.

Our average depreciation, depletion and amortization per Boe increased from $11.95 per Boe during 2021 to $12.35 per Boe during 2022.

These per Boe amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total Boe volumes sold.

Asset retirement obligation accretion.

Our asset retirement obligation (“ARO”) accretion increased from $744,045 in 2021 to $983,432 in 2022.

This was a result of the 32 additional wells added from 2022 drilling activities as well as ARO accretion associated with the properties acquired in the Stronghold Acquisition, offset by wells plugged and abandoned during the year.

Operating lease expense.

Our operating lease expense decreased from $523,487 in 2021 to $363,908 in 2022 due to the month to month leases for office equipment and compressors used in operations on which the Company had previously elected to apply ASU 2016-02.

The office equipment and compressors are not subject to ASU 2016-02 based on the agreement and nature of use.

The costs have been recorded as short-term lease costs and amounts included in lease operating expenses beginning in the second quarter of 2021.

General and administrative expenses (including share-based compensation) .

General and administrative expenses increased from $16,068,105 in 2021 to $27,095,323 in 2022.

The increase was primarily related to a $4,743,908 increase in share-based compensation, as well as increases in salaries and bonuses, all attributed to a nearly doubled headcount from 2021 to 2022 to support our growth.

Other cost increases include software maintenance, rent, insurance, and environmental sustainability.

The 2022 expenses also included non-recurring acquisition-related costs of $2.1 million.

Interest expense .

Interest expense increased from $14,490,474 in 2021 to $23,167,729 in 2022.

The increase was the result of a combination of higher interest rates during the second half of 2022, with a weighted average interest rate of 5.8% in 2022 and 4.4% in 2021, and having higher amounts outstanding on our credit facility throughout 2022, with a weighted average daily debt of approximately $308.7 million in 2021 compared to approximately $344.0 million in 2022, particularly due to the additional debt incurred for the Stronghold Acquisition.

Gain (loss) on derivative contracts.

During 2022, the Company incurred a loss on derivative contracts of $21,532,659.

During 2021, the Company recorded a loss on derivative contracts of $77,853,141.

For the derivative contract settlements, the Company recorded a realized loss of $52,768,154 during 2021 and a realized loss of $62,525,954 during 2022, The increase of $9,757,800 in the realized loss was a result of the rise of crude oil prices during 2022, which was above the fixed prices of the contracts.

For the marked-to-market contracts, the Company recorded an unrealized gain of $40,993,295 during 2022 and an unrealized loss of $25,084,987 during 2021.

This change in unrealized derivatives was due to the roll off of unfavorable contracts during 2022, as well as the Company's purchase of more favorable contracts during 2022.

Benefit from (Provision for) income taxes .

The benefit from (provision for) income taxes changed from a provision of $90,342 for 2021 to a provision of $8,408,724 for 2022.

The current year federal tax expense was the result of certain existing deferred tax assets that will not be offset by existing deferred tax liabilities as a result of the 80% limitation on the utilization of net operating losses incurred after 2017.

Net income (loss) .

The Company had a net income of $3,322,892 in 2021 compared to net income of $138,635,025 in 2022.

The increase in net income was due primarily to the increase in oil, natural gas, and natural gas liquids revenues, as well as the reduction in derivative contract losses, offset by increases in lease operating expenses, depletion, general and administrative expenses, and interest expense.

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

Oil and natural gas sales .

3 unchanged sentences

These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels.

Despite the few months of shut in or curtailed production due to oil price destabilizing from the COVID-19 pandemic, volumes in 2020 significantly benefited from the large amount of capital activity seen in the previous year.

Likewise, the lack of capital activity in 2020 resulted in a negative impact to 2021 volumes due to natural well decline.

Activity in 2021 helped offset declines, but not enough to overcome the full impact from the reduced capital activity in 2020.

The natural gas sales volume increased from 2,494,502 Mcf in 2020 to 2,535,188 Mcf in 2021 and the average realized per Mcf gas price increased from $1.57 in 2020 to $5.83 in 2021.

Likewise, the lower capital expenditures in 2020 resulted in a negative impact to 2021 volumes due to natural well declines.

Capital expenditures in 2021 helped offset declines, but not enough to overcome the full impact from the reduced capital expenditures in 2020.

The natural gas sales volume increased slightly from 2,494,502 Mcf in 2020 to 2,535,188 Mcf in 2021 and the average realized per Mcf gas price increased from $1.57 in 2020 to $5.83 in 2021.

The price increase was driven by a steady increase in NGL prices and a 92% increase in the underlying Henry Hub gas price, which included the impact of Winter Storm Uri in 2021.

4 unchanged sentences

These per Boe amounts are calculated by dividing our total lease operating expenses by our total volume sold, in Boe.

LOE increased due to the higher amount of activity in 2021 compared to the lack of activity resulting from the oil price destabilization from the COVID-19 pandemic in 2020.

LOE increased due to the higher amount of activity in 2021 compared to the lack of activity resulting from the oil price destabilization due to the COVID-19 pandemic in 2020.

Gathering, transportation and processing costs.

20 unchanged sentences

Our asset retirement obligation (“ARO”) accretion decreased from $906,616 in 2020 to $744,045 in 2021.

This was a result of the reduction of ARO liabilities from the sale of assets in the first quarter of 2021 and plugging activities throughout the year.

This was a result of the reduction of ARO liabilities from the sale of certain assets in the first quarter of 2021 and plugging activities conducted throughout the year.

Operating lease expense.

Our operating lease expense decreased from $1,196,372 in 2020 to $523,487 in 2021 due to the month to month leases for office equipment and compressors used in its operations on which the Company had previously elected to apply ASU 2016-02.

Our operating lease expense decreased from $1,196,372 in 2020 to $523,487 in 2021 due to the month to month leases for office equipment and compressors used in our operations on which we had previously elected to apply ASU 2016-02.

The office equipment and compressors are not subject to ASU 2016-02 based on the agreement and nature of use.

The costs are recorded as short-term lease costs and amounts included in Oil and gas production costs.

The costs are recorded as short-term lease costs and amounts included in Lease operating expenses.

The Company terminated its Oklahoma lease as of March 31, 2021 and negotiated a reduction to its Midland office lease.

1 unchanged sentence

General and administrative expenses decreased from $16,874,050 in 2020 to $16,068,105 in 2021.

The decrease was primarily related to a $2,945,839 reduction in share-based compensation, offset by increases from salaries, accounting expenses, and non-recurring costs associated with investor relations.

The decrease was primarily related to a $2,945,839 reduction in share-based compensation, offset by increases in salaries, accounting expenses, and non-recurring costs associated with investor relations.

Interest expense .

13 unchanged sentences

Net income (loss) .

The Company had a net loss of ($253,411,828) in 2020 as compared to net income of $3,322,892 in 2021.

The change in net income (loss) is primarily the result of the ceiling test write-down in 2020.

Year Ended December 31, 2020 Compared to Year Ended December 31, 2019

Oil and natural gas sales.

Oil and natural gas sales revenue decreased from 2019 levels by approximately $82.7 million to $113.0 million in 2020.

Oil sales decreased approximately $82.8 million while natural gas sales increased approximately $0.1 million.

The oil sales decrease was the result of both a decrease in sales volume from 3,536,126 barrels of oil in 2019 to 2,801,528 barrels of oil in 2020 and a decrease in the average realized per barrel oil price from $54.27 in 2019 to $38.95 in 2020.

These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels.

The reduction in oil volume was the result of shutting in production and reducing our capital development program due to oil commodity prices, which led to fewer wells drilled.

The natural gas sales volume increased slightly from 2,476,472 Mcf in 2019 to 2,494,502 Mcf in 2020 and the average realized per Mcf gas price increased from $1.54 in 2019 to $1.57 in 2020.

These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf.

The slight increase was due to higher gas production volumes associated with reservoir de-pressurization at the Northwest Shelf properties.

Lease operating expenses.

Our lease operating expenses (LOE) decreased from $42,213,006 in 2019 to $29,753,413 in 2020 and decreased on a BOE basis from $10.69 in 2019 to $9.25 in 2020.

These per BOE amounts are calculated by dividing our total lease operating expenses by our total volume sold, in BOE.

LOE decreased due to the extreme focus our operating team began early during the pandemic-induced downturn.

We reduced overhead, expense repairs, and converted 29 electrical submersible pumps to rod pumps, which have an overall lower operating cost.

In addition, artificial lift optimization has continued to reduce overall well failure rates, resulting in further reductions to operating costs.

Gathering, transportation and processing costs.

Our gathering, transportation and processing costs increased from $2,874,155 in 2019 to $4,090,238 in 2020.

This is due to the acquisition of the Northwest Shelf in April 2019, which accounted for the lower GTP costs during the year ended December 31, 2019.

Ad valorem taxes.

Our total ad valorem taxes decreased from $3,409,064 in 2019 to $3,125,222 in 2020 and increased on a BOE basis from $0.86 in 2019 to $0.97 in 2020.

Ad valorem taxes decreased in total due to lower revenues and well counts year-over-year.

Oil and natural gas production taxes .

Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.69% during 2019 and decreased to 4.63% in 2020.

Production taxes vary from state to state.

Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states, and on the possibility that any state may raise its production tax.

Depreciation, depletion and amortization.

Our depreciation, depletion and amortization expense decreased from $56,204,269 in 2019 to $43,010,660 in 2020.

The decrease was the result of decreased sales volumes and a reduction in our average depreciation, depletion and amortization rate from $14.23 per BOE during 2019 to $13.37 per BOE during 2020.

These per BOE amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in BOE.

Ceiling Test Write-Down.

The Company recorded a non-cash write-down of the carrying value of its proved oil and natural gas properties of $277,501,943 for the year ended December 31, 2020 as a result of ceiling test limitations, which is reflected as ceiling test impairments in the accompanying Statements of Operations.

The Company did not have any write-downs for the period ended December 31, 2019.

The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve-month period as of December 31, 2019, adjusted for market differentials, per SEC guidelines.

The write-down reduced earnings in the period and is expected to result in a lower depreciation, depletion and amortization rate in future periods.

The primary reason for the write-down is a reduction in the oil price used for calculating the reserves from $52.19 in 2019 to $36.04 in 2020.

Asset retirement obligation accretion.

Our asset retirement obligation (ARO) accretion decreased from $943,707 in 2019 to $906,616 in 2020.

This was a result of the settlement of the ARO during 2020.

Operating lease expense.

Our operating lease expense increased from $925,217 in 2019 to $1,196,372 in 2020 due to operating leases entered into during 2019 which had only a partial year impact, as well as additional operating leases entered into during 2020.

General and administrative expenses (including share-based compensation).

General and administrative expenses decreased from $19,866,706 in 2019 to $16,874,050 in 2020.

The decrease was primarily related to acquisition related expenses incurred in 2019.

Interest income.

Interest income decreased from $13,511 in 2019 to $8 in 2020.

The decrease was the result of lower average cash on hand during 2020.

Interest expense.

Interest expense increased from $13,865,556 in 2019 to $17,617,614 in 2020.

The increase was the result of having larger amounts outstanding on our credit facility during 2020.

Gain(loss) on derivative contracts.

During 2019, the Company recorded a loss on derivative contracts of $3,000,078.

During 2020, the Company recorded a gain on derivative contracts of $21,366,068.

The change was the result of the reduction in the oil price during 2020, compared to the prices within the derivative contracts held.

Deposit forfeiture income .

During 2020, the Company received $5,500,000 in non-refundable deposits from the intended buyer regarding the attempted divestiture of the Company’s Delaware assets.

With the cancellation of that agreement, the non-refundable deposits were recognized as income on our Statements of Operations.

No similar income item occurred during 2019.

Benefit from (Provision for) income taxes.

The benefit from (provision for) income taxes changed from a provision of $13,787,654 for 2019 to a benefit of $6,001,176 for 2020.

The change was primarily the result of losses due to the ceiling test write-down in 2020 offset by a valuation allowance against the deferred tax asset.

Net income (loss).

The Company had net income of $29,496,551 in 2019 compared to a net loss of ($253,411,828) in 2020.

The change in net income (loss) is primarily the result of the ceiling test write-down in 2020.

The Company had a net loss of ($253,411,828) in 2020 compared to net income of $3,322,892 in 2021.

The change in net income (loss) was primarily the result of the ceiling test write-down in 2020.

Liquidity and Capital Resources

3 unchanged sentences

These cash flows were primarily used to fund our capital expenditures.

We believe the combination of the sources of capital discussed will continue to be adequate to meet our short and long-term liquidity needs.

Credit Facility.

On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank (now Truist), as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), which was amended on June 26, 2015, July 24, 2015, May 18, 2016, and June 14, 2018.

In April 2019, the Company amended and restated its Credit Agreement with the Administrative Agent (as amended and restated, the “Credit Facility”).

The amendment and restatement of the Credit Facility, among other things, increased the maximum borrowing amount to $1 billion, extended the maturity date through April 2024 and made other modifications to the terms of the Credit Facility.

This Credit Facility was amended on December 23, 2020 and June 17, 2020.

The latest amendment adjusted the borrowing base to $350 million and made other modifications to the terms of the Credit Facility.

The fourth amendment on June 10, 2021, among other things, reaffirmed the borrowing base at $350 million and modified the definition for “Fall 2020 Borrowing Base Hedges,” from 4,000 barrels of oil per day to 3,100 barrels of oil per day for calendar year 2022.

The fifth amendment on June 25, 2021 incorporates contractual fallback language for US dollar LIBOR denominated syndicated loans, which language provides for the transition away from LIBOR to an alternative reference rate, and incorporates certain provisions that clarify the rights of agents to recover from lenders erroneous payments made to such lenders.

The Credit Facility is secured by a first lien on substantially all of the Company’s assets.

On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank (now Truist), as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), (which was amended several times) that provided for a maximum borrowing base of $1 billion with security consisting of substantially all of the assets of the Company.

In April 2019, the Company amended and restated the Credit Agreement with the Administrative Agent (as amended and restated, the “Credit Facility”).

On August 31, 2022, the Company modified its Credit Facility through a Second Amended and Restated Credit Agreement, extending the maturity date of the facility to August 2026.

In conjunction with the Stronghold Acquisition, with the newly acquired assets put up for collateral, the Company established a borrowing base of $600 million.

The borrowing base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time.

The borrowing base is redetermined semi-annually on each May 1 and November 1.

The Borrowing Base will be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.

The Credit Facility allows for Eurodollar Loans and Base Rate Loans (as respectively defined in the Credit Facility).

The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 2.5% and 3.5% (depending on the then-current level of Borrowing Base usage).

The annual interest rate on each Base Rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Credit Facility) plus 0.5% per annum, (iii) the adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 1.5% and 2.5% (depending on the then-current level of Borrowing Base usage).

The Credit Facility contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio (outstanding debt to adjusted earnings before interest, taxes, depreciation and amortization) of not more than 4.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Credit Facility) of 1.0 to 1.0.

The December 2020 amendment permitted a total Leverage Ratio not greater than 4.25 for the period ending March 31, 2021.

The Credit Facility also contains other customary affirmative and negative covenants and events of default.

The borrowing base is subject to reduction in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.

The syndicate was modified to add five lenders, replacing five exiting lenders.

Rather than Eurodollar loans, the reference rate on the Second Amended and Restated Credit Agreement is the Standard Overnight Financing Rate (“SOFR”).

Beginning on the June 30, 2023 financial statements and compliance certification delivery date, the Second Amended and Restated Credit Agreement will allow for the Company to declare dividends for its equity owners, subject to certain limitations.

These limitations include (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio, as defined in the Second Amended and Restated Credit Agreement, does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow, (iv) the Borrowing Base Utilization Percentage is not greater than 80%, and (v) a Responsible Officer certifies that the other four conditions are satisfied.

The interest rate on each SOFR Loan will be the adjusted term SOFR for the applicable interest period plus a margin between 3.0% and 4.0% (depending on the then-current level of borrowing base usage).

The annual interest rate on each base rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Second Amended and Restated Credit Agreement) plus 0.5% per annum, (iii) the adjusted term SOFR determined on a daily basis for an interest period of one month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 2.0% and 3.0% per annum (depending on the then-current level of borrowing base usage).

The Second Amended and Restated Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio (outstanding debt to adjusted earnings before interest, taxes, depreciation and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Second Amended and Restated Credit Agreement) of 1.0 to 1.0.

The Company is required to maintain on a rolling 24 months basis, hedging transactions in respect of crude oil and natural gas, on not less than 50% of the projected production from its proved, developed, producing oil and gas.

If the borrowing base utilization is less than 25% at the hedge testing date and the leverage ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for shall be 0% from such hedge testing date to the next succeeding hedge testing date.

If the borrowing base utilization percentage is equal to or greater than 25%, but less than 50% and the leverage ratio is not greater than 1.25 to 1.00, the required hedging percentage

for months 13 through 24 of the rolling 24 month period provided for shall be 25% from such hedge testing date to the next succeeding hedge testing date.

The Second Amended and Restated Credit Agreement also contains other customary affirmative and negative covenants and events of default.

As of December 31, 2022, $415,000,000 was outstanding on the Credit Facility.

As of December 31, 2021, we were in compliance with all covenants contained in the Credit Facility.

The Company is in compliance with all covenants contained in the Second Amended and Restated Credit Agreement as of December 31, 2022.

Equity Offering.

In October 2020, the Company closed on an underwritten public offering of 9,575,800 Common Shares, (ii) 13,428,500 Pre-Funded Warrants and (iii) 23,004,300 Common Warrants at a combined purchase price of $0.70.

In October 2020, the Company closed on an underwritten public offering of (i) 9,575,800 Common Shares, (ii) 13,428,500 Pre-Funded Warrants and (iii) 23,004,300 Common Warrants at a combined purchase price of $0.70.

This includes a partial exercise of the over-allotment.

5 unchanged sentences

Total gross proceeds from the 2020 underwritten public offering and the registered direct offering aggregated $20,846,282.

Total net proceeds aggregated $19,383,131.

Total net proceeds for the Common Warrants exercised in 2020 aggregated $19,379,832.

The Common Shares of 9,575,800 and 3,500,000 were issued in 2020, as shown in our Statements of Stockholders' Equity.

The Pre-Funded Warrants of 3,300,000 were exercised and common stock was issued in 2020 and the Pre-Funded Warrants of 13,428,500 were exercised and common stock was issued in 2021, as shown in our Statements of Stockholders' Equity.

Of the aforementioned 6,800,000 Common Warrants, all remained outstanding as of December 31, 2021 and 2022.

Of the aforementioned 23,004,300 Common Warrants, 442,600 were exercised and common stock was issued in 2021 and 10,253,907 were exercised and common stock was issued in 2022, as shown in our Statements of Stockholders' Equity.

Issuance of Common Stock and Convertible Preferred Stock for Stronghold Acquisition.

As part of the consideration for the Stronghold Acquisition, on August 31, 2022 the Company issued 21,339,986 shares of common stock and 153,176 shares of newly created Series A Convertible Preferred Stock, which was converted into 42,548,892 shares of common stock on October 27, 2022.

Historically, our primary sources of cash have been from operations, equity offerings and borrowings on our Credit Facility.

During 2021, 2020, and 2019 we had cash inflow from operations of $72,731,212, $72,159,255, and $106,616,221, respectively.

During the three years ended December 31, 2021, we financed $19,750,640 through proceeds from the sale of stock.

During 2021, 2020, and 2019, we had proceeds from drawdowns on our Credit Facility of $60,150,000, $26,500,000, and $327,000,000, respectively.

We primarily used this cash to fund our capital expenditures and development aggregating $528,032,951 over the three years ended December 31, 2021.

Additionally, during 2021 and 2020 we used $83,150,000 and $80,000,000, respectively, to reduce the outstanding balance on our Credit Facility.

As of December 31, 2021, we had cash on hand of $2,408,316 and negative working capital of $46,861,767, compared to cash on hand of $3,578,634 and negative working capital of $16,141,847 as of December 31, 2020 and cash on hand of $10,004,622 and negative working capital of $20,384,013 as of December 31, 2019.

During 2022, 2021, and 2020 we had cash inflow from operations of $197.0 million, $72.7 million, and $72.2 million, respectively.

During the three years ended December 31, 2022, we financed $28.0 million through proceeds from the sale of stock.

During 2022, 2021, and 2020, we had proceeds from drawdowns on our Credit Facility of $636.0 million, $60.2 million, and $26.5 million, respectively.

We primarily used this cash to fund our capital expenditures and development aggregating $405.2 million over the three years ended December 31, 2022.

Additionally, during 2022, 2021 and 2020, we used $511.0 million, $83.2 million and $80.0 million, respectively, to reduce the outstanding balance on our Credit Facility.

As of December 31, 2022, we had cash on hand of $3.7 million and negative working capital of $78.0 million, compared to cash on hand of $2.4 million and negative working capital of $46.9 million as of December 31, 2021 and cash on hand of $3.6 million and negative working capital of $16.1 million as of December 31, 2020.

Contractual Obligations.

The Company maintains a Credit Facility which currently has a $600.0 million borrowing base.

The outstanding balance on that Credit Facility as of December 31, 2021 is $290 million, which will require repayment or refinancing at or prior to maturity in April 2024.

The Company leases office space in The Woodlands, Texas.

The outstanding balance on that Credit Facility as of December 31, 2022 is $415.0 million, which will require repayment or refinancing at or prior to maturity in August 2026.

The Company leases office spaces in The Woodlands, Texas and Midland, Texas.

The Woodlands office is under a five-and-a-half-year lease beginning January 15, 2021.

The Company has financing leases for vehicles with varying maturity dates from April 2022 through August 2024.

At the end of the term of these leases, the Company will own the vehicles.

Future lease payments through August 2024 aggregate $692,090.

The Midland office lease was amended effective October 1, 2022, with the revised five-year lease ending September 30, 2027.

The Company has financing leases for vehicles with varying maturity dates through October 2025.

Future lease payments through October 2025 aggregate $1,900,595.

Subsequent Events

Effective February 1, 2022, the Company entered into a derivative contract with its lender for 1,000 barrels of oil per day for the remainder of 2022 (total notional quantity of 334,000 barrels).

Fixed swap prices vary by month, ranging from $90.78 per barrel in February to $80.01 per barrel by the end of the year, with a weighted average swap price of $84.61 per barrel.

Stronghold acquisition - On February 28, 2023, as discussed in "Note 5 - ACQUISITIONS & DIVESTITURES," the deferred cash consideration of $15.0 million in cash was paid to Stronghold in accordance with terms set forth in the Purchase Agreement for the Stronghold Acquisition.

In addition on March 1, 2023, the holdback amount of approximately $8.3 million which was held in escrow in accordance with the terms set forth in the Purchase Agreement for the Stronghold Acquisition was distributed to Stronghold.

Common stock issued pursuant to warrant exercise - On February 2, 2023, the Company issued 2,517,427 shares of common stock pursuant to the exercise of Common Warrants with an exercise price of $0.80.

Gross and net proceeds were $2,013,942.

On March 1, 2023, the Company issued 2,000,000 shares of common stock pursuant to the exercise of Common Warrants with an exercise price of $0.80.

Gross and net proceeds were $1,600,000.

Effects of Inflation and Pricing

11 unchanged sentences

Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors.

Our significant accounting policies, as well as considerations of recent accounting pronouncements, are detailed in Note 1 to our financial statements included in this Annual Report.

Our significant accounting policies, as well as considerations of recent accounting pronouncements, are detailed in "Note 1 - ORGANIZATION, BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES" to our financial statements included in this Annual Report.

We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.

1 unchanged sentence

In January 2018, the Company adopted Accounting Standards Update (“ASU”) 2014-09 Revenues from Contracts with Customers (Topic 606) (“ASU 2014-09”).

The timing of recognizing revenue from the sale of produced crude oil and

natural gas was not changed as a result of adopting ASU 2014-09.

The timing of recognizing revenue from the sale of produced crude oil and natural gas was not changed as a result of adopting ASU 2014-09.

The Company predominantly derives its revenue from the sale of produced crude oil and natural gas.

6 unchanged sentences

Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products.

See Note 2 of our financial statements for additional information.

See "Note 2 - REVENUE RECOGNITION" of our financial statements for additional information.

Full Cost Method of Accounting.

1 unchanged sentence

Under this method, all costs (internal or external) associated with property acquisition, exploration and development of oil and gas reserves are capitalized.

Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and cost of drilling and equipping productive and non-productive wells.

Costs capitalized include acquisition costs, geological and geophysical

expenditures, lease rentals on undeveloped properties and cost of drilling and equipping productive and non-productive wells.

Drilling costs include directly related overhead costs.

9 unchanged sentences

During 2020, the Company recorded a non-cash write-down of the carrying value of the Company’s proved oil and natural gas properties as a result of a ceiling test limitation of approximately $277.5 million, which is reflected with ceiling test and other impairments in the accompanying Statements of Operations.

The Company did not have any write-downs related to the full cost ceiling limitation in 2021.

The Company did not have any write-downs related to the full cost ceiling limitation in 2021 or 2022.

Our estimates of reserves and future cash flow as of December 31, 2022 and 2021 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2022 and 2021, respectively, in accordance with SEC guidelines.

12 unchanged sentences

Our proved reserve information included in this Annual Report was prepared and determined by Cawley, Gillespie & Associates, Inc., independent petroleum engineers.

Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately

We continually make revisions to reserve estimates throughout the year as additional properties are acquired.

5 unchanged sentences

This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled.

Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities.

Since our tax returns are filed after the financial

statements are prepared, estimates are required in valuing tax assets and liabilities.

We record adjustments to the actual values in the period the Company files its tax returns.

In assessing the Company’s deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized.

The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent up on the generation of future taxable income and the Company’s ability to utilize operation loss carryforwards during the periods in which the temporary differences become deductible.

The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and the Company’s ability to utilize operation loss carryforwards during the periods in which the temporary differences become deductible.

We also consider the scheduled reversal of deferred tax liabilities and available tax planning strategies.

In January 2017, the Company adopted ASU 2016-09, Compensation – Stock Compensation (Topic 718.) The Company used the modified retrospective method to account for unrecognized excess tax benefits from prior periods and uses the prospective method to account for current period and future excess tax benefit.

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