Item 7. Management’s Discussion and Analysis
Item 7:
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our accompanying financial statements and the notes to those financial statements included elsewhere in this Annual Report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs and our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors” and elsewhere in this Annual Report.
Overview
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 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
As the weak commodity price environment began to recover and the contraction in oil demand seen from the COVID-19 pandemic began to ease, Ring initiated its Phase I four well program in the Northwest Shelf Asset by drilling two wells in December 2020 and two wells in January 2021. All four wells were completed and placed on production during first quarter 2021. During that quarter, the Company also performed nine conversions from electrical submersible pumps to rod pumps (such conversions, “CTRs”) with seven performed in the Northwest Shelf and two in the Central Basin Platform. New wells were added throughout the year by drilling in phases, to ensure the Company would continue operating within cash flow. In the second quarter of 2021, the Company completed its Phase II drilling program and placed on production three new horizontal San Andres wells in the Northwest Shelf, along with four additional CTRs in the Northwest Shelf and one CTR in the Central Basin Platform. in the third quarter of 2021, the Phase III drilling program resulted in two horizontal San Andres wells in Northwest Shelf and two horizontal San Andres wells in the Central Basin Platform. During third quarter 2021, the Company also performed seven CTRs in the Northwest Shelf and three CTRs in the Central Basin Platform. In the fourth quarter of 2021, the Company drilled one new well and performed one CTR in the Northwest Shelf and drilled one new well in the Central Basin Platform. Lastly, during 2021 the Company participated with offset operators in two wells in the Northwest Shelf Asset as a non-operated working interest owner.
Our oil and natural gas producing properties are located in the Permian Basin of Texas and New Mexico. Oil sales represented approximately 92.5% and 96.5% of our total revenue for the twelve months ended December 30, 2021 and 2020, respectively. The 4% variance in oil sales revenue was due to higher realized gas and NGL prices in 2021. As of December 31, 2021, we had in place derivative contracts covering 3,129 barrels of oil per day for the calendar year 2022. All of the 3,129 barrels of oil in 2022 are in the form of swaps of WTI Crude Oil prices. The oil swap prices for 2022 range from $44.22 to $50.05, with a weighted average swap price of $46.60. Our 2021 derivative hedges resulted in total unrealized fair value loss of approximately $25.1 million for the year ended December 31, 2021 and realized loss on derivatives of approximately $52.8 million for the year ended December 31, 2021. All of our hedges are financial hedges and do not have physical delivery requirements.
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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.
Market Conditions and Commodity Prices
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 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
The following table sets forth selected operating data for the periods indicated:
For the Years Ended December 31,
2021
2020
2019
Net production:
Oil (Bbls)
2,686,940
2,801,528
3,536,126
Natural gas (Mcf)
2,535,188
2,494,502
2,476,472
Net sales:
Oil
$
181,533,093
$
109,113,557
$
191,891,314
Natural gas
14,772,873
3,911,581
3,811,517
Average sales price:
Oil (per Bbl)
$
67.56
$
38.95
$
54.27
Natural gas (per Mcf)
5.83
1.57
1.54
Production costs and expenses
Lease operating expenses
$
30,312,399
$
29,753,413
$
42,213,006
Gathering, transportation and processing costs
4,333,232
4,090,238
2,874,155
Ad valorem taxes
2,276,463
3,125,222
3,409,064
Production taxes
9,123,420
5,228,090
9,130,379
Depreciation, depletion and amortization expense
37,167,967
43,010,660
56,204,269
Ceiling test impairment
—
277,501,943
—
Gain (loss) on derivative contracts
(77,853,141)
21,366,068
(3,000,078)
Asset retirement obligation accretion
744,045
906,616
943,707
Operating lease expense
523,487
1,196,372
925,217
General and administrative expense
(excluding stock-based compensation)
13,649,782
11,509,888
16,784,081
Stock-based compensation expense
2,418,323
5,364,162
3,082,625
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Year Ended December 31, 2021 Compared to Year Ended December 31, 2020
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.
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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. Oil sales decreased approximately $82.8 million while natural gas sales increased approximately $0.1 million. The oil sales decrease was the result of both a decrease in sales volume from 3,536,126 barrels of oil in 2019 to 2,801,528 barrels of oil in 2020 and a decrease in the average realized per barrel oil price from $54.27 in 2019 to $38.95 in 2020. These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels. The reduction in oil volume was the result of shutting in production and reducing our capital development program due to oil commodity prices, which led to fewer wells drilled.
The natural gas sales volume increased slightly from 2,476,472 Mcf in 2019 to 2,494,502 Mcf in 2020 and the average realized per Mcf gas price increased from $1.54 in 2019 to $1.57 in 2020. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The slight increase was due to higher gas production volumes associated with reservoir de-pressurization at the Northwest Shelf properties.
Lease operating expenses. Our lease operating expenses (LOE) decreased from $42,213,006 in 2019 to $29,753,413 in 2020 and decreased on a BOE basis from $10.69 in 2019 to $9.25 in 2020. These per BOE amounts are calculated by dividing our total lease operating expenses by our total volume sold, in BOE. LOE decreased due to the extreme focus our operating team began early during the pandemic-induced downturn. We reduced overhead, expense repairs, and converted 29 electrical submersible pumps to rod pumps, which have an overall lower operating cost. In addition, artificial lift optimization has continued to reduce overall well failure rates, resulting in further reductions to operating costs.
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Gathering, transportation and processing costs. Our gathering, transportation and processing costs increased from $2,874,155 in 2019 to $4,090,238 in 2020. This is due to the acquisition of the Northwest Shelf in April 2019, which accounted for the lower GTP costs during the year ended December 31, 2019.
Ad valorem taxes. Our total ad valorem taxes decreased from $3,409,064 in 2019 to $3,125,222 in 2020 and increased on a BOE basis from $0.86 in 2019 to $0.97 in 2020. Ad valorem taxes decreased in total due to lower revenues and well counts year-over-year.
Oil and natural gas production taxes . Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.69% during 2019 and decreased to 4.63% in 2020. Production taxes vary from state to state. Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states, and on the possibility that any state may raise its production tax.
Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense decreased from $56,204,269 in 2019 to $43,010,660 in 2020. The decrease was the result of decreased sales volumes and a reduction in our average depreciation, depletion and amortization rate from $14.23 per BOE during 2019 to $13.37 per BOE during 2020. These per BOE amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in BOE.
Ceiling Test Write-Down. The Company recorded a non-cash write-down of the carrying value of its proved oil and natural gas properties of $277,501,943 for the year ended December 31, 2020 as a result of ceiling test limitations, which is reflected as ceiling test impairments in the accompanying Statements of Operations. The Company did not have any write-downs for the period ended December 31, 2019. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve-month period as of December 31, 2019, adjusted for market differentials, per SEC guidelines. The write-down reduced earnings in the period and is expected to result in a lower depreciation, depletion and amortization rate in future periods. The primary reason for the write-down is a reduction in the oil price used for calculating the reserves from $52.19 in 2019 to $36.04 in 2020.
Asset retirement obligation accretion. Our asset retirement obligation (ARO) accretion decreased from $943,707 in 2019 to $906,616 in 2020. This was a result of the settlement of the ARO during 2020.
Operating lease expense. Our operating lease expense increased from $925,217 in 2019 to $1,196,372 in 2020 due to operating leases entered into during 2019 which had only a partial year impact, as well as additional operating leases entered into during 2020.
General and administrative expenses (including share-based compensation). General and administrative expenses decreased from $19,866,706 in 2019 to $16,874,050 in 2020. The decrease was primarily related to acquisition related expenses incurred in 2019.
Interest income. Interest income decreased from $13,511 in 2019 to $8 in 2020. The decrease was the result of lower average cash on hand during 2020.
Interest expense. Interest expense increased from $13,865,556 in 2019 to $17,617,614 in 2020. The increase was the result of having larger amounts outstanding on our credit facility during 2020.
Gain(loss) on derivative contracts. During 2019, the Company recorded a loss on derivative contracts of $3,000,078. During 2020, the Company recorded a gain on derivative contracts of $21,366,068. The change was the result of the reduction in the oil price during 2020, compared to the prices within the derivative contracts held.
Deposit forfeiture income . During 2020, the Company received $5,500,000 in non-refundable deposits from the intended buyer regarding the attempted divestiture of the Company’s Delaware assets. With the cancellation of that agreement, the non-refundable deposits were recognized as income on our Statements of Operations. No similar income item occurred during 2019.
Benefit from (Provision for) income taxes. The benefit from (provision for) income taxes changed from a provision of $13,787,654 for 2019 to a benefit of $6,001,176 for 2020. The change was primarily the result of losses due to the ceiling test write-down in 2020 offset by a valuation allowance against the deferred tax asset.
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Net income (loss). The Company had net income of $29,496,551 in 2019 compared to a net loss of ($253,411,828) in 2020. The change in net income (loss) is primarily the result of the ceiling test write-down in 2020.
Liquidity and Capital Resources
Financing of Operations. We have historically funded our operations through cash available from operations and from equity offerings of our stock. 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 (now Truist), as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), which was amended on June 26, 2015, July 24, 2015, May 18, 2016, and June 14, 2018. In April 2019, the Company amended and restated its Credit Agreement with the Administrative Agent (as amended and restated, the “Credit Facility”). The amendment and restatement of the Credit Facility, among other things, increased the maximum borrowing amount to $1 billion, extended the maturity date through April 2024 and made other modifications to the terms of the Credit Facility. This Credit Facility was amended on December 23, 2020 and June 17, 2020. The latest amendment adjusted the borrowing base to $350 million and made other modifications to the terms of the Credit Facility. The fourth amendment on June 10, 2021, among other things, reaffirmed the borrowing base at $350 million and modified the definition for “Fall 2020 Borrowing Base Hedges,” from 4,000 barrels of oil per day to 3,100 barrels of oil per day for calendar year 2022. The fifth amendment on June 25, 2021 incorporates contractual fallback language for US dollar LIBOR denominated syndicated loans, which language provides for the transition away from LIBOR to an alternative reference rate, and incorporates certain provisions that clarify the rights of agents to recover from lenders erroneous payments made to such lenders. The Credit Facility is secured by a first lien on substantially all of the Company’s assets.
The Borrowing Base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The Borrowing Base is redetermined semi-annually on each May 1 and November 1. The Borrowing Base will be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.
The Credit Facility allows for Eurodollar Loans and Base Rate Loans (as respectively defined in the Credit Facility). The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 2.5% and 3.5% (depending on the then-current level of Borrowing Base usage). The annual interest rate on each Base Rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Credit Facility) plus 0.5% per annum, (iii) the adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 1.5% and 2.5% (depending on the then-current level of Borrowing Base usage).
The Credit Facility contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio (outstanding debt to adjusted earnings before interest, taxes, depreciation and amortization) of not more than 4.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Credit Facility) of 1.0 to 1.0. The December 2020 amendment permitted a total Leverage Ratio not greater than 4.25 for the period ending March 31, 2021. The Credit Facility also contains other customary affirmative and negative covenants and events of default. As of December 31, 2021, $290,000,000 was outstanding on the Credit Facility. As of December 31, 2021, we were in compliance with all covenants contained in the Credit Facility.
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.
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Cash Flows. Historically, our primary sources of cash have been from operations, equity offerings and borrowings on our Credit Facility. During 2021, 2020, and 2019 we had cash inflow from operations of $72,731,212, $72,159,255, and $106,616,221, respectively. During the three years ended December 31, 2021, we financed $19,750,640 through proceeds from the sale of stock. During 2021, 2020, and 2019, we had proceeds from drawdowns on our Credit Facility of $60,150,000, $26,500,000, and $327,000,000, respectively. We primarily used this cash to fund our capital expenditures and development aggregating $528,032,951 over the three years ended December 31, 2021. Additionally, during 2021 and 2020 we used $83,150,000 and $80,000,000, respectively, to reduce the outstanding balance on our Credit Facility. As of December 31, 2021, we had cash on hand of $2,408,316 and negative working capital of $46,861,767, compared to cash on hand of $3,578,634 and negative working capital of $16,141,847 as of December 31, 2020 and cash on hand of $10,004,622 and negative working capital of $20,384,013 as of December 31, 2019.
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, 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 August 2024 aggregate $692,090.
Subsequent Events
Effective February 1, 2022, the Company entered into a derivative contract with its lender for 1,000 barrels of oil per day for the remainder of 2022 (total notional quantity of 334,000 barrels). Fixed swap prices vary by month, ranging from $90.78 per barrel in February to $80.01 per barrel by the end of the year, with a weighted average swap price of $84.61 per barrel.
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 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. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for services related to production and exploration.
Off-Balance Sheet Financing Arrangements
As of December 31, 2021, we had no off-balance sheet financing arrangements.
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies, as well as considerations of recent accounting pronouncements, are detailed in Note 1 to our financial statements included in this Annual Report. 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.
Revenue Recognition. 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
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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. 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. 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. The new guidance regarding ASU 2014-09 does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and Ring engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. See Note 2 of our financial statements for additional information.
Full Cost Method of Accounting. We account for our oil and natural gas operations using the full cost method of accounting. Under this method, all costs (internal or external) associated with property acquisition, exploration and development of oil and gas reserves are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and cost of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. All of our properties are located within the continental United States.
Write-down of Oil and Natural Gas Properties . Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.
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.
Our estimates of reserves and future cash flow as of December 31, 2021 and 2020 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, 2021 and 2020, respectively, in accordance with SEC guidelines. As of December 31, 2021, our reserves are based on an SEC average price of $63.04 per Bbl of WTI oil posted and $3.598 per MMBtu Henry Hub natural gas. 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. 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. Reserve quantities and future cash flows included in this Annual Report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:
● the quality and quantity of available data;
● the interpretation of that data;
● the accuracy of various mandated economic assumptions; and
● the judgments of the persons preparing the estimates.
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
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recovered. We continually make revisions to reserve estimates throughout the year as additional properties are acquired. We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.
All capitalized costs of oil and natural gas properties, including estimated future costs to develop proved reserves and estimated future costs of site restoration, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent engineers. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined.
Income Taxes. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. 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.