What changed in this filing

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Item 7. Management’s Discussion and Analysis

2022-03-16 compared with 2021-03-16 · 144 added, 181 removed, 166 unchanged (66% of the section changed)

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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 an exploration and production company based in The Woodlands that is engaged in oil and natural gas acquisition, exploration, development and production activities.

Our exploration and production interests are currently focused in Texas and New Mexico.

The Company seeks to exploit its acreage position through the drilling of highly economic, vertical and horizontal wells using the most recent drilling and completion techniques.

Our focus is drilling and developing our oil and gas properties through use of cash flow generated by our operations and reducing our long-term debt through the sale of non-core assets or through our excess cash flow while still working towards providing annual production growth.

We continue to evaluate potential transactions to acquire attractive acreage positions within our core areas of interest.

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

The Company seeks to exploit its acreage position through the drilling of highly economic, vertical and horizontal wells using the most recent drilling and completion techniques.

We continue to evaluate potential transactions to acquire attractive acreage positions within our core areas of interest.

The Company is focused on balancing the need to reduce long-term debt and further developing our oil and gas properties to maintain or grow our annual production.

We intend to achieve both through proper allocation of cash flow generated by our operations and potentially through the sale of non-core assets.

We intend to continue evaluating potential transactions to acquire strategic producing assets with attractive acreage positions that can provide competitive returns for our shareholders.

2021 Developments and Highlights

In March 2020, the World Health Organization declared the COVID-19 outbreak a pandemic.

Governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have caused a significant contraction in global economic activity, including a decline in the demand for oil and to a lesser extent natural gas.

Our business and operations have been adversely affected by, and may continue to be adversely affected by, the COVID-19 pandemic and the public health response thereto.

As a result of the COVID-19 outbreak and the adverse public health developments, including voluntary and mandatory quarantines, travel restrictions and other restrictions, our operations, and those of our subcontractors, customers and suppliers, have experienced, and may to continue to experience, delays or disruptions.

Starting the last week of April, essentially all of our production, other than that associated with our Delaware Basin property, was shut-in or curtailed.

The curtailments continued until early June, when, with commodity prices improving and price differentials decreasing, the Company began to bring wells back on-line, returning to near April levels by the end of the second quarter.

In the third quarter 2020, we had restored production to 9,549 net BOEPD and in the fourth quarter 2020 we produced 9,307 net BOEPD.

In addition, our financial condition and results of operations have been, and may continue to be, adversely affected by the ongoing coronavirus outbreak.

The timeline and potential magnitude of the COVID-19 outbreak and its consequences are currently unknown.

The prolongation or exacerbation of this pandemic could more extensively affect the United States and global economy, including the demand for oil and natural gas.

The Company has experienced the effects of a negatively impacted domestic and international demand for crude oil and natural gas, which has contributed to price volatility and impacted the price we received for our production, and moreover materially and adversely affected the demand for and marketability of our production.

For the Company, this means that production was shut in for some of our wells, and that we held some of our production as inventory to be sold at a later date because we refused to accept the unprecedented and exceptionally low price for our production.

Our 2020 first quarter results were negatively impacted by the pandemic response, and we continued to experience the pandemic’s negative impact through the fourth quarter of 2020.

At this time, we expect that our financial results for the first quarter of 2021 may be adversely impacted by our response to, the existence of and the global response to the COVID-19 pandemic.

Also, in March 2020, Saudi Arabia and Russia, along with OPEC producers, failed to agree to cut oil production, and Saudi Arabia significantly cut the sell price of its oil and announced plans to increase production, which events together contributed to a sharp drop in global oil prices.

While OPEC, Russia and other allied producers reached an agreement in April 2020, and most recently in March 2021, to reduce production, oil prices remained low until the first quarter of 2021.

While OPEC+ producers ultimately agreed to cut global petroleum output, such cut was not enough to offset the impact of COVID-19 on 2020 demand.

As a result of this decrease in demand and increase in supply, oil and natural gas prices decreased, which affected our liquidity.

Additionally, with depressed oil and natural gas prices, we incurred a write-down to our oil and gas properties and additional write-downs may be required in future periods if prices decrease from current levels.

The imbalance between the supply of and demand for oil, as well as the uncertainty around the extent and timing of an economic recovery, caused significant market volatility and a substantial adverse effect on commodity prices during the last three quarters of 2020.

The Company expects ongoing oil and gas price volatility over the short-term.

The full impact of the coronavirus on oil and natural gas prices continues to evolve as of the date of this report.

As such, the full magnitude of such events on the Company remains uncertain.

Management is actively monitoring the global situation and its impact on the Company’s future operations, financial position and liquidity in fiscal year 2020.

As a producer of oil and natural gas, we are recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic.

We have continued to operate as permitted under these regulations while taking steps to protect the health and safety of our workers.

We have implemented protocols to reduce the risk of an outbreak within our field operations, and these protocols have not reduced production or efficiency in a significant manner.

A substantial portion of our non-field level employees have transitioned temporarily to remote work-from-home arrangements.

With these arrangements in place, we have been able to maintain a consistent level of effectiveness, including maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting.

Our oil and natural gas producing properties are located in the Permian Basin.

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.

While natural gas prices also declined as a result of changes in demand, the decline in natural gas prices was far less significant than the decline in oil prices.

As of December 31, 2020, we have in place derivative contracts covering 9,000 and 1,750 barrels of oil per day for the calendar years 2021 and 2022, respectively, and covering 6,000 and 5,000 MMBTU of natural gas per day for the calendar years 2021 and 2022, respectively.

For 2021, contracts covering 4,500 of the 9,000 barrels of oil are in the form of costless collars of WTI Crude Oil prices.

“Costless collars” are the combination of two options, a put option (floor) and a call option (ceiling) with the options structured so that the premium paid for the put option will be offset by the premium received from selling the call option.

These collars have floors ranging from $40.00 to $45.00, with an averaged floor of $42.22 and have ceilings ranging between $52.71 and $55.35 per barrel, with an average ceiling of $54.57.

The remaining 4,500 barrels of oil in 2021 and all of the 1,750 barrels of oil in 2022 are in the form of swaps of WTI Crude Oil prices.

The oil swap prices for 2021 range from $45.00 to $45.96, with an average of $45.42.

The oil swap prices for 2022 range from $44.22 to $45.98, with an average of $44.84.

All of the contracts for natural gas for both 2021 and 2022 are in the form of swaps of Henry Hub.

The swap prices for 2021 and 2022 are $2.991 and $2.7255, respectively.

Our 2020 and 2021 derivative hedges resulted in total unrealized fair value loss of approximately $1.2 million during the twelve months ended December 31, 2020 and realized gain on derivates of approximately $22.5 million twelve months ended December 31, 2020.

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.

As such, any decreases in anticipated production, whether as a result of decreased development activity or shut-ins, will not impact our ability to realize the benefits of the hedges.

Our supply chain has experienced some interruptions.

In the second quarter of 2020, one of our purchasers cancelled its existing contracts to purchase produced oil from the Company.

However, we have since entered into new contracts with an existing purchaser to purchase the oil previously covered by the cancelled contracts.

In the second quarter of 2020, the industry overall experienced severe storage capacity constraints with respect to oil and certain natural gas products.

Although such restraints have relaxed significantly, we may become subject to such constraints if we are not able to sell our production, or certain components of our production.

The lack of a market or available storage for natural gas product or oil could result in us having to shut in production.

In addition, as previously announced, we reduced our drilling and completion capital budget for 2020 by approximately 70% since the beginning of the year.

Reductions in the 2020 capital budget may impact production levels in 2021 and forward to the extent fewer wells are brought online.

In May 2020, the Borrowing Base supporting our Credit Facility was subject to its semi-annual redetermination, which led to us entering into a second amendment to our Credit Facility on June 17, 2020.

The amendment, among other things, reduces the Company’s Borrowing Base under the Credit Facility from $425 million to $375 million.

The Company subsequently entered into a third amendment to our Credit Facility on December 23, 2020, subject to its semi-annual redetermination requirement.

The amendment, among other things, reduced the Company’s Borrowing Base from $375 million to $350 million.

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.

The COVID-19 pandemic, commodity market volatility and resulting financial market instability are variables beyond our control that can adversely impact our ability to generate sufficient funds from operating activities, our available borrowings under our Credit Facility and our ability to access the capital markets.

We believe we are taking appropriate steps in response to the evolving circumstances.

However, past performance is not a promise of future events and the Company cannot estimate all aspects of the ongoing impact of the pandemic-related events and the OPEC+ production adjustments on the Company’s financial statements.

Market Conditions and Commodity Prices

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.

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

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 caused Ring, as well as other operators, to re-evaluate our original capital budget plans for 2020 that led to changes we believed were in the best interest of the Company and our stockholders.

Although oil prices have recovered to pre-pandemic levels, we believe oil and natural gas prices may continue to be volatile.

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

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

Results of Operations

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Production costs and expenses

Oil and gas production costs

(excluding ad valorem taxes)

Lease operating expenses

Gathering, transportation and processing costs

Ad valorem taxes

2 unchanged sentences

Ceiling test impairment

Realized loss (gain) on derivatives

Accretion expense

Gain (loss) on derivative contracts

Asset retirement obligation accretion

Operating lease expense

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Oil and natural gas sales .

Oil and natural gas sales revenue increased from 2020 levels by approximately $83.3 million to $196.3 million in 2021.

Oil sales increased approximately $72.4 million and natural gas sales increased approximately $10.9 million.

The oil sales increase was the result of an increase in the average realized per barrel oil price from $38.95 in 2020 to $67.56 in 2021, slightly offset by a decrease in sales volume from 2,801,528 barrels of oil in 2020 to 2,686,940 barrels of oil in 2021.

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.

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.

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

Natural gas sales volumes in 2021 were positively impacted by higher volumes associated with reservoir de-pressurization at the Northwest Shelf properties which were partially offset by purchaser inability to receive gas volumes at certain times throughout the year due to downtime or mechanical issues effecting efficiencies with their facilities.

Lease operating expenses.

Our total lease operating expenses (“LOE”) increased slightly from $29,753,413 in 2020 to $30,312,399 in 2021 and increased on a BOE basis from $9.25 in 2020 to $9.75 in 2021.

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.

Gathering, transportation and processing costs.

Our total gathering, transportation and processing costs (“GTP”) increased slightly from $4,090,238 in 2020 to $4,333,232 in 2021 and increased on a BOE basis from $1.27 in 2020 to $1.39 in 2021.

GTP costs increased due to the higher gas volumes processed in the Northwest Shelf.

Ad valorem taxes.

Our total ad valorem taxes decreased from $3,125,222 in 2020 to $2,276,463 in 2021 and decreased on a BOE basis from $0.97 in 2020 to $0.73 in 2021.

Ad valorem taxes decreased due to the Company’s compliance department’s annual detailed review of each property’s current production, ownership, and lease operating expenses, which resulted in cost savings for the taxes assessed.

Oil and natural gas production taxes .

Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.63% during 2020 and increased to 4.65% in 2021.

The slight increase was due to higher Texas gas revenue which is taxed at 7.5%.

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 decreased from $43,010,660 in 2020 to $37,167,967 in 2021.

The decrease was the result of an increase in our total reserves and an average decrease of total property cost from the impairment in 2020, resulting in a reduction to our average depreciation, depletion and amortization rate from $13.37 per BOE during 2020 to $11.95 per BOE during 2021.

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 did not record a ceiling test write-down during 2021.

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, 2021, adjusted for market differentials, per SEC guidelines.

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 was reflected as ceiling test impairments in the accompanying Statements of Operations.

The primary reason for the write-down was 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 $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.

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.

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

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

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.

Interest expense .

Interest expense decreased from $17,617,614 in 2020 to $14,490,474 in 2021.

The decrease was the result of having lower amounts outstanding on our credit facility throughout 2021.

Gain (loss) on derivative contracts.

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

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

The significant change was due to the rise of crude oil prices during 2021, which was above the fixed price of the contracts.

Deposit forfeiture income .

During 2021, the Company did not earn 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.

Benefit from (Provision for) income taxes .

The benefit from (provision for) income taxes changed from a benefit of $6,001,176 for 2020 to a provision of $90,342 for 2021.

The change was primarily the result of a full valuation allowance on federal taxes in 2021 with only state tax activity recognized.

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.

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

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

Oil and natural gas production costs (including ad valorem taxes) .

Our aggregate oil and natural gas production costs decreased from $48,496,225 in 2019 to $36,968,873 in 2020 and decreased on a BOE basis from $12.28 in 2019 to $11.49 in 2020.

These per BOE amounts are calculated by dividing our total production costs by our total volume sold, in BOE.

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

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 .

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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 to $36.04.

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

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.

6 unchanged sentences

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

Realized gain on derivatives.

During 2020, the Company recorded a realized gain on derivatives of $22,522,591.

There was no similar gain or loss recorded during 2019.

The gain is the result of the reduction in the oil price during 2020.

Unrealized loss on derivatives.

During 2020, the Company recorded an unrealized loss on derivatives of $1,156,523, as compared to a loss of $3,000,078 during 2019.

The change was the result of variations between oil prices at the end of those periods versus the derivative contracts we had in place at the end of each year.

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 .

4 unchanged sentences

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 of $50,553,125.

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 as compared to a net loss of ($253,411,828) in 2020.

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.

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Oil and natural gas sales .

Oil and natural gas sales revenue increased approximately $75.6 million to $195.7 million in 2019.

Oil sales increased approximately $75.2 million while natural gas sales increased approximately $0.4 million.

The oil sales increase was primarily the result of an increase in sales volume from 2,047,295 barrels of oil in 2018 to 3,536,126 barrels of oil in 2019, partially offset by a decrease in the average realized per barrel oil price from $56.99 in 2018 to $54.27 in 2019.

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

Natural gas sales volume increased from 1,112,177 Mcf in 2018 to 2,476,472 Mcf in 2019 and the average realized per Mcf gas price decreased from $3.05 in 2018 to $1.54 in 2019.

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

The volume increases are the result of our ongoing development of existing properties.

Oil and natural gas sales volumes increased primarily as a result of the acquisition of the Northwest Shelf assets.

Of our 3,536,126 barrels of oil produced in 2019, 1,670,573 barrels came from the Northwest Shelf properties and of our 2,476,472 Mcf of natural gas produced in 2019, 1,221,807 Mcf came from the Northwest Shelf properties.

Oil and natural gas production costs (including ad valorem taxes) .

Our aggregate oil and natural gas production costs increased from $27,801,989 in 2018 to $48,496,225 in 2019 and decreased on a BOE basis from $12.45 in 2018 to $12.28 in 2019.

These per BOE amounts are calculated by dividing our total production costs by our total volume sold, in BOE.

The increase in total production costs is primarily a result of the acquisition of the Northwest Shelf assets.

The decrease in production costs per BOE is primarily the result increased production volumes from the Northwest Shelf assets.

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 2018 and decreased to 4.67% in 2019.

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 increased by $17,179,383 to $56,204,269 in 2019.

The increase was primarily the result of increased production volumes but was partially offset by a decrease in our average depreciation, depletion and amortization rate from $17.54 per BOE during 2018 to $14.23 per BOE during 2019.

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

The reduction in our depletion rate per BOE is primarily the result of added reserves from the acquisition of the Northwest Shelf assets.

Ceiling Test Write-Down.

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

The Company recorded a non-cash write-down of the carrying value of its proved oil and natural gas properties of $14,172,309 for the year ended December 31, 2018 as a result of ceiling test limitations, which is reflected as ceiling test impairments in the accompanying Statements of Operations.

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, 2018, 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.

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

General and administrative expenses increased from $12,867,686 in 2018 to $19,866,706 in 2019.

The increase was primarily related to acquisition related expenses, amortization of deferred financing costs and compensation related expenses.

Interest income .

Interest income was $13,511 in 2019 as compared to $97,855 in 2018.

The decrease was the result of lower average cash on hand during 2019.

Interest expense .

Interest expense was $13,865,556 in 2019 as compared to $427,898 in 2018.

The increase was the result of having larger amounts outstanding on our credit facility during 2019.

Realized loss on derivatives.

During 2018, the Company recorded a realized loss on derivatives of $11,153,702.

There was no similar gain or loss recorded during 2019.

The loss was the result of the WTI index price increasing during 2018.

Unrealized gain (loss) on derivatives.

During 2019, the Company recorded an unrealized loss on derivatives of $3,000,078, as compared to a gain of $3,968,287 during 2018.

The change was the result of variations between oil prices at the end of those periods versus the derivative contracts we had in place at the end of each year.

Provision for income taxes .

The provision for income taxes increased from $3,445,721 for 2018 to $13,787,654 for 2019.

The increase was the result of higher income before income taxes and also as a result of a $3,965,000 excess tax expense related to share based compensation.

The Company had net income of $29,496,551 in 2019 as compared to $8,999,760 in 2018.

The increase in net income primarily resulted from increased revenues, which was largely the result of the Northwest Shelf acquisition, and not having a ceiling test write down in 2019 partially offset by higher interest and income tax expense.

Liquidity and Capital Resources

1 unchanged sentence

We have historically funded our operations through cash available from operations and from equity offerings of our stock.

Our primary sources of cash in 2020 were from funds generated from the sale of oil and natural gas production and borrowing on our Credit Facility.

Our primary source of cash in 2021 was from funds generated from the sale of oil and natural gas production.

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

Credit Facility.

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

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, increases the maximum borrowing amount to $1 billion, extends the maturity date through April 2024 and makes other modifications to the terms of 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.

The Borrowing Base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time.

The Borrowing Base will be redetermined semi-annually on each May 1 and November 1.

The Borrowing Base will also 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 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).

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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 amendment to the credit facility in June 2020 allowed for a Leverage Ratio of not greater than 4.75 to 1 as of the last day of the fiscal quarter ending September 30, 2020.

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

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As of December 31, 2021, $290,000,000 was outstanding on the Credit Facility.

We are in compliance with all covenants contained in the Credit Facility.

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

Equity Offering.

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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 2020 we used $80,000,000 to reduce the outstanding balance on our Credit Facility.

As of December 31, 2020, we had cash on hand of $3,578,634 and negative working capital of $16,141,847, as compared to cash on hand of $10,004,622 and negative working capital of $20,384,013 as of December 31, 2019 and cash on hand of $3,363,726 and negative working capital of $35,066,175 as of December 31, 2018.

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.

Contractual Obligations.

The Company maintains a Credit Facility which currently has a $350 million borrowing base.

The outstanding balance on that Credit Facility as of December 31, 2020 is $313 million, which will require repayment or refinancing at or prior maturity in April 2024.

The Company leases office space in Midland, Texas.

The Midland office is under a five-year lease beginning January 1, 2021 with monthly rent payments of $12,000 through December 2023 and $13,000 per month from January 2024 through December 2025.

All other office space as of December 31, 2020 is month to month and will be discontinued during 2021.

The Company leases office equipment in our Midland office.

These leases are month-to-month but we anticipate continuing to lease this equipment through the term of the Midland office lease.

Payments for this equipment aggregate $711 per month.

The Company also leases field equipment for the operation of our wells.

These leases are on a month-to-month basis but we anticipate continuing to lease the equipment until the end of its useful life.

The current anticipated useful life of this equipment varies from December 2020 through December 2023.

Total payments under these leases are anticipated to be $815,960 through December 2023.

The Company has financing leases for vehicles with varying maturity dates from November 2021 through July 2022.

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 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 July 2022 aggregate $443,705.

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

Subsequent Events

The Company entered into a Sublease Agreement dated January 15, 2021, covering approximately 15,728 square feet at 1725 Hughes Landing Blvd, Suite 900, The Woodlands, TX 77380.

The sublease term will run until July 31, 2026.

The Company entered into a Purchase, Sale and Exchange Agreement dated February 1, 2021, effective January 1, 2021, with Vin Fisher Operating, Inc.

covering the sale and exchange of certain oil and gas interests in Andrews County, Texas.

After the sale and transfer of wells and leases between the two parties, the Company also received a net value consideration in cash of $2,000,000.

The deal greatly reduces the Company’s plug and abandonment obligation costs and also allows the Company to acquire new leasehold for the future drilling of additional horizontal wells.

Subsequent to December 31, 2020, the remaining 13,428,500 pre-funded warrants and 184,800 of the Common Warrants issued in the October 2020 offering were exercised.

Gross proceeds were $161,269.

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.

Effects of Inflation and Pricing

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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 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 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.

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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.

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A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.

During 2018 and 2020, the Company recorded non-cash write-downs of the carrying value of the Company’s proved oil and natural gas properties as a result of ceiling test limitations of approximately $14.2 million and $277.5 million, respectively, which is reflected with ceiling test and other impairments in the accompanying Statements of Operations.

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.

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Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties.

Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty

to be recoverable in future periods from known reservoirs under existing economic and operating conditions.

Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions.

Reserve quantities and future cash flows included in this Annual Report are prepared in accordance with guidelines established by the SEC and FASB.

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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 recovered.

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

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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 we file our tax returns.

For the year ended December 31, 2020, we recorded a valuation allowance against our deferred tax asset of $50,553,125.

We were in a deferred tax asset position as a result of the ceiling test write downs recorded during 2020.

No valuation allowance was recorded for the years ended December 31, 2019 or 2018.

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.

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.

For the years ended December 31, 2020, 2019 and 2018, we recorded a decrease of $2,026,006, an increase of $3,855,389 and an increase of $907,884, respectively, to our income tax provision.

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