What changed in this filing

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Item 7. Management’s Discussion and Analysis

2021-03-16 compared with 2020-03-16 · 198 added, 132 removed, 149 unchanged (69% 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 a Midland-based exploration and production company that is engaged in oil and natural gas acquisition, exploration, development and production activities.

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.

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Business Description and Plan of Operation

Ring is currently engaged in oil and natural gas acquisition, exploration, development and production in Texas and New Mexico.

We focus on developing our existing properties, while continuing to pursue acquisitions of oil and gas properties with upside potential.

Our goal is to increase stockholder value by investing in oil and natural gas projects with attractive rates of return on capital employed.

We plan to achieve this goal by exploiting and developing our existing oil and natural gas properties and pursuing strategic acquisitions of additional properties.

Specifically, our business strategy is to increase our stockholders’ value through the following:

● Growing production and reserves by developing our oil-rich resource base through conventional and horizontal drilling.

Ring intends to drill and develop its acreage base in an effort to maximize its value and resource potential, with a focus on the further drilling and development of its Northwest Shelf asset.

Ring plans to operate within its generated cash flow.

Ring's preliminary plan included drilling 18 horizontal wells on the Northwest Shelf and performing workovers and extensive infrastructure projects on its Northwest Shelf, Central Basin Platform and Delaware Basin assets in 2020.

Due to the recent drop in the price of oil, Ring has re-evaluated its current capital expenditure budget for 2020 and is making changes that the Company believes are in the best interest of the Company and its stockholders, including ceasing any further drilling until oil prices stabilize.

Of the 18 new wells, four were to be drilled in the first quarter of 2020.

Those four new wells have been drilled, but as of now, the Company does not plan to drill further until it is comfortable that commodity pricing has stabilized.

Ring’s portfolio of proved oil and natural gas reserves consists of 88% oil and 12% natural gas.

Of those reserves, 53% of the proved reserves are classified as proved developed producing, or “PDP,” 5% are classified as proved developed non-producing, or “PDNP,” and 42% are classified as proved undeveloped, or “PUD.” Ring plans to increase its production, reserves and cash flow while gaining favorable returns on invested capital through the conversion of undeveloped reserves to developed reserves.

Through December 31, 2019, we increased our proved reserves to approximately 81.1 million BOE (barrel of oil equivalent).

As of December 31, 2019, our estimated proved reserves had a pre-tax “PV10” (present value of future net revenues before income taxes discounted at 10%) of approximately $1.1 billion and a Standardized Measure of Discounted Future Net Cash Flows of approximately $923.2 million.

The difference between these two amounts is the effect of income taxes.

The Company presents the pre-tax PV10 value, which is a non-GAAP financial measure, because it is a widely used industry standard which we believe is useful to those who may review this Annual Report when comparing our asset base and performance to other comparable oil and natural gas exploration and production companies.

● Reduction of Long-Long Term Debt and De-Leveraging of Asset.

Ring intends to reduce its long-term debt, either through the sale of non-core assets, the use of excess cash flow from operations, or a combination.

Ring incurred long-term indebtedness in connection with the acquisition of core assets from Wishbone Energy Partners, LLC and its related entities.

The Company believes that with its market-leading completion margins, it is well positioned to maximize the value of its assets and plans to de-lever its balance sheet through strategic asset dispositions.

The Company is continuing to evaluate opportunities to strategically sell its non-core assets in transactions that maximize the Company’s return and provide the greatest upside to its stockholders.

In furtherance of this strategy, Ring is currently marketing its Delaware Basin assets.

● Employ industry leading drilling and completion techniques.

Ring’s executive team intends to utilize new and innovative technological advancements and careful geological evaluation in reservoir engineering to generate value for its stockholders and to build development opportunities for years to come.

Improved efficiency through employing technological advancements can provide a significant benefit in a continuous drilling program such as the one Ring contemplates for its current inventory of drilling locations.

● Pursue strategic acquisitions with exceptional upside potential.

Ring has a history of acquiring leasehold positions that it believes to have substantial resource potential and to meet its targeted returns on invested capital.

Ring has historically pursued acquisitions of properties that it believes to have exploitation and development potential comparable to its existing inventory of drilling locations.

The Company has developed and refined an acquisition program designed to increase reserves and complement existing core properties.

Ring’s experienced team of management and engineering professionals identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties.

Management intends to continue to pursue strategic acquisitions that meet the Company’s operational and financial targets.

The executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region.

Ring believes that leveraging its relationships will be a competitive advantage in identifying acquisition targets.

Management’s proven ability to evaluate resource potential will allow Ring to successfully acquire acreage and bring out more value in the assets.

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 maintaining or providing annual production growth.

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

2020 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.

Oil sales represented approximately 96.5% and 98.1% of our total revenue for the twelve months ended December 30, 2020 and 2019, 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.

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.

During the fourth quarter, the Company paid down approximately $47 million in debt leaving approximately $313 million outstanding on our credit facility as of December 31, 2020.

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

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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 recent drop in the price of oil has forced us, as well as other operators, to re-evaluate our current capital expenditure budget for 2020 and make changes that we believe are in the best interest of the Company and our stockholders.

Our preliminary capital expenditure budget for 2020 included the drilling of 18 new horizontal wells on our Northwest Shelf asset.

Of the 18 new wells, four were to be drilled in the first quarter of 2020.

Those four new wells have been drilled, but as of now, the Company has ceased new drilling until the Company is comfortable that oil commodity pricing has stabilized.

We expect oil and natural gas to remain volatile.

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.

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Oil and gas production costs

(excluding ad valorem taxes)

Ad valorem taxes

Production taxes

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Ceiling test impairment

Realized loss on derivatives

Realized loss (gain) on derivatives

Accretion expense

Operating lease expense

General and administrative expenses

General and administrative expense

(excluding stock-based compensation)

Stock-based compensation expense

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

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.

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.

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.

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 2,494,501 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 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, 1,893,888 barrels came from the Northwest Shelf properties and of our 2,476,472 Mcf of natural gas produced in 2019, 1,892,438 Mcf came from the Northwest Shelf properties.

Oil and natural gas production costs .

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.

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.

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.

Our production costs 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.

Oil and natural gas production taxes .

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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.

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.

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 $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 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 at December 31, 2018, adjusted for market differentials, per SEC guidelines.

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.

General and administrative expenses .

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.

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) .

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

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

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.

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.

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.

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 of $50,553,125.

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 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

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

The oil sales increase was the result of an increase in sales volume from 1,311,727 barrels of oil in 2017 to 2,047,295 barrels of oil in 2018 and an increase in the average realized per barrel oil price from $48.97 in 2017 to $56.99 in 2018.

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

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

Oil and natural gas production costs .

Our aggregate oil and natural gas production costs increased from $15,978,362 in 2017 to $27,801,989 in 2018 and increased on a BOE basis from $11.11 in 2017 to $12.45 in 2018.

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 production costs and the cost per BOE is primarily the result of higher electrical costs and to a lesser degree chemical costs, partially offset by increased production volumes.

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 .

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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 also affected by an increase in our average depreciation, depletion and amortization rate from $11.15 per BOE during 2017 to $17.54 per BOE during 2018.

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

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

General and administrative expenses .

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 increases in costs associated with compensation and employee benefits.

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

Interest income .

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Interest expense .

Interest expense was $427,898 in 2018 as compared to no interest expense in 2017.

The increase was the result of having outstanding amounts on our credit facility during 2018.

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 decreased from $10,416,171 in 2017 to $3,445,721 in 2018.

The change was due to an adjustment in 2017 to the value of our deferred tax asset as a result of a change in our future effective tax rate.

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 and from not having an additional provision for income taxes recorded for the change in tax rate as in 2017, partially offset by the ceiling test write down in 2018.

Liquidity and Capital Resources

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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 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, 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.

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, increases the borrowing base (the “Borrowing Base”) to $425 million, 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, 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.

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

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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 Credit Facility allows for Eurodollar Loans and Base Rate Loans.

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, the (iii) 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 0.75% and 1.75% (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 (as defined in the Credit Facility) of not more than 4.0 to 1.0 and (ii) a minimum current ratio of Current Assets to Current Liabilities (as such terms are defined in the Credit Facility) of 1.0 to 1.0.

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 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.

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

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

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.

This includes a partial exercise of the over-allotment.

The Common Warrants have a term of five years and an exercise price of $0.80 per share.

Gross proceeds totaled $16,089,582.

Concurrently with the underwritten public offering, the Company closed on a registered direct offering of (i) 3,500,000 Common Shares, (ii) 3,300,000 Pre-Funded Warrants and (iii) 6,800,000 Common Warrants at a combined purchase price of $0.70.

The Common Warrants have a term of five years and an exercise price of $0.80 per share.

Gross proceeds totaled $4,756,700.

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.

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

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We primarily used this cash to fund our capital expenditures and development aggregating $678,889,233 over the three years ended December 31, 2020.

At December 31, 2019, we had cash on hand of $10,004,622 and negative working capital of $20,384,013, as compared to cash on hand of $3,363,726 and negative working capital of $35,066,175 at December 31, 2018 and cash on hand of $15,006,581 and working capital of $19,319,525 at December 31, 2017.

Schedule of Contractual Obligations.

The following table summarizes our contractual obligations for periods subsequent to December 31, 2019.

Payment due by period

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.

Contractual Obligations.

Credit Facility (1)

Financing Lease Obligations (2)

Operating Lease Obligations - Office (3)

Operating Lease Obligations - Field (4)

(1) This table does not include future commitment fees, interest expense or other fees on this facility because they are floating rate instruments, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

(2) Financing Lease Obligations includes payments for vehicles under lease terms.

Per the term of the lease agreements, the Company will own the vehicles at the end of their term.

(3) Operating Lease Obligations – Office includes leases for our office spaces in Midland, Texas and Tulsa, Oklahomaand lease terms for certain office equipment.

The Midland office serves as our headquarters and is approximately 15,000 square feet.

The Tulsa office is our accounting office and is approximately 3,700 square feet.

The office equipment leased is for equipment that is used in our Midland and Andrews offices.

All of these leases are currently month to month but are presumed to continue for all of 2020.

The Company incurred lease expense related to the office space of $555,425, $527,600 and $537,582, respectively, for the years ended December 2019, 2018 and 2017.

(4) Operating Lease Obligations – Field includes equipment leased for the operation of our wells.

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

Long-term asset retirement obligation is not included in the above table as the timing of these payments cannot be reasonably predicted.

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.

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

Future lease payments through July 2022 aggregate $443,705.

Subsequent Events

Subsequent to December 31, 2019, the Company entered into new derivative contracts covering 4,500 barrels of oil per day for the period of January 2021 through December 2021.

All of the derivative contracts 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.

Please see the below table for information related to the put prices and call prices for the derivative contracts in place for 2021.

Date entered into

Barrels per day

2021 contracts

Subsequent to December 31, 2019, there has been a significant decline in oil prices due to global circumstances that are out of our control.

As a result, the value of our derivative contracts has changed significantly.

As of December 31, 2019, our balance sheet reflected a $3,000,078 derivative liability.

As of March 16, 2020, there has been an unrealized gain on derivativs and that liability has become an asset.

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.

Effects of Inflation and Pricing

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry.

Typically, as prices for oil and natural gas increase, so do all associated costs.

Typically, as prices for oil and natural gas increase, so do associated costs.

Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and the value of properties in purchase and sale transactions.

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The contractual performance obligation is satisfied when the product is delivered to the customer.

Revenue is recorded in the month the product is delivered to the purchaser and the Company receives payment from one to three months after delivery.

Revenue is recorded in the month the product is delivered to the purchaser.

The Company receives payment from one to three months after delivery.

The transaction price includes variable consideration as product pricing is based on published market prices and reduced for contract specified differentials.

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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, 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 ceiling test limitations of approximately $14.2 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 2017 and 2019.

Our reserve estimates, as of December 31, 2019, are based on an average price of $52.41 for oil and $1.47 for gas.

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.

The Company did not have any write-downs related to the full cost ceiling limitation in 2019.

Our estimates of reserves and future cash flow as of December 31, 2020 and 2019 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, 2020 and 2019, respectively, in accordance with SEC guidelines.

As of December 31, 2020, our reserves are based on an SEC average price of $36.04 per Bbl of WTI oil posted and $1.99 per MMBtu Henry Hub natural gas.

As of December 31, 2019, our reserves are based on an SEC average price of $52.19 per Bbl of WTI oil posted and $2.58 per MMBtu Henry Hub natural gas.

Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines.

Oil and Natural Gas Reserve Quantities.

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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● the judgments of the persons preparing the estimates.

Our proved reserve information included in this Annual Report was based on internal reports and audited by Cawley, Gillespie & Associates, Inc., independent petroleum engineers.

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.

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We record adjustments to the actual values in the period we file our tax returns.

Our balance sheet for the year ended December 31, 2019, includes a deferred tax liability of approximately $6.0 million.

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, resulting in an adjustment to our beginning balances of Deferred Income Taxes and Retained Loss of $1,596,463 and uses the prospective method to account for current period and future excess tax benefit.

For the years ended December 31, 2019, 2018 and 2017, we recorded an increase of $3,855,389, an increase of $907,884 and a decrease of $49,896, respectively, to our income tax provision.

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.

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