RING ENERGY, INC. 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 aMidland -based exploration and production company that is engaged in oil and natural gas acquisition, exploration, development and production activities. Our exploration and production interests are currently focused inTexas andNew Mexico . The Company seeks to exploit its acreage position through the drilling of highly economic, vertical and horizontal wells using the most recent drilling and completion techniques. Our focus is drilling and developing our oil and gas properties through use of cash flow generated by our operations and reducing our long-term debt through the sale of non-core assets or through our excess cash flow while still working towards providing annual production growth. We continue to evaluate potential transactions to acquire attractive acreage positions within our core areas of interest.
Business Description and Plan of Operation
Ring is currently engaged in oil and natural gas acquisition, exploration,
development and production in
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
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.
ThroughDecember 31, 2019 , we increased our proved reserves to approximately 81.1 million BOE (barrel of oil equivalent). As ofDecember 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. 31 Table of Contents
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
? 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
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
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.
Market Conditions and Commodity Prices
Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. 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 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 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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Results of Operations
The following table sets forth selected operating data for the periods indicated:
For the Years Ended December 31, 2017 2018
2019
Net production:
Oil (Bbls) 1,311,727 2,047,295 3,536,126
Natural gas (Mcf) 761,517 1,112,177 2,476,472
Net sales:
Oil $ 64,236,490 $ 116,678,375 $ 191,891,314
Natural gas 2,463,210 3,386,986 3,811,517
Average sales price:
Oil (per Bbl) $ 48.97 $ 56.99 $ 54.27
Natural gas (per Mcf) 3.23 3.05 1.54
Production costs and expenses
Oil and gas production costs $ 15,978,362 $ 27,801,989 $ 48,496,225
Production taxes 3,152,562 5,631,093 9,130,379
Depreciation, depletion and amortization
expense 20,517,780 39,024,886 56,204,269
Ceiling test impairment - 14,172,309 -
Realized loss on derivatives 119,897 11,153,702 -
Accretion expense 567,968 606,459 943,707
Operating lease expense - - 925,217General and administrative expenses 10,515,887 12,867,686
19,866,706
Year Ended
Oil and natural gas sales. Oil and natural gas sales revenue increased approximately$75.6 million to$195.7 million in 2019. Oil sales increased approximately$75.2 million while natural gas sales increased approximately$0.4 million . The oil sales increase was primarily the result of an increase in sales volume from 2,047,295 barrels of oil in 2018 to 3,536,126 barrels of oil in 2019, partially offset by a decrease in the average realized per barrel oil price from$56.99 in 2018 to$54.27 in 2019. These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels. Natural gas sales volume increased from 1,112,177 Mcf in 2018 to 2,476,472 Mcf in 2019 and the average realized per Mcf gas price decreased from$3.05 in 2018 to$1.54 in 2019. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The volume increases are the result of our ongoing development of existing properties. Oil and natural gas sales volumes increased primarily as a result of the acquisition of the Northwest Shelf assets. Of our 3,536,126 barrels of oil produced in 2019, 1,893,888 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. These per BOE amounts are calculated by dividing our total production costs by our total volume sold, in BOE. The increase in total production costs is primarily a result of the acquisition of the Northwest Shelf assets. The decrease in production costs per BOE is primarily the result increased production volumes from the Northwest Shelf assets. Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.69% during 2018 and decreased to 4.67% in 2019. Production taxes vary from state to state. Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states, and on the possibility that any state may raise its production tax. 33 Table of Contents
Depreciation, depletion and amortization. Our depreciation, depletion and
amortization expense increased by
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 endedDecember 31, 2019 . The Company recorded a non-cash write-down of the carrying value of its proved oil and natural gas properties of$14,172,309 for the year endedDecember 31, 2018 as a result of ceiling test limitations, which is reflected as ceiling test impairments in the accompanying Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period atDecember 31, 2018 , adjusted for market differentials, perSEC 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
Interest income. Interest income was
Interest expense. Interest expense was
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. Net income. 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.
Year Ended
Oil and natural gas sales. Oil and natural gas sales revenue increased approximately$53.4 million to$120.1 million in 2018. Oil sales increased approximately$52.4 million while natural gas sales increased approximately$0.9 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. Natural gas sales volume increased from 761,517 Mcf in 2017 to 1,112,177 Mcf in 2018 and the average realized per Mcf gas price decreased from$3.23 in 2017 to$3.05 in 2018. 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 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. 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. Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.73% during 2017 and decreased to 4.69% in 2018. 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. 34 Table of Contents Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by$18,507,106 to$39,024,886 in 2018. 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. 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 endedDecember 31, 2018 as a result of ceiling test limitations, which is reflected as ceiling test impairments in the accompanying Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period atDecember 31, 2018 , adjusted for market differentials, perSEC guidelines. 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 endedDecember 31, 2017 .
General and administrative expenses. General and administrative expenses
increased from
Interest income. Interest income was
Interest expense. Interest expense was
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. Net income. The Company had net income of$8,999,760 in 2018 as compared to$1,753,869 in 2017. 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
Financing of Operations. We have historically funded our operations through cash available from operations and from equity offerings of our stock. Our primary sources of cash in 2019 were from funds generated from the sale of oil and natural gas production and borrowing on our Credit Facility. These cash flows were primarily used to fund our capital expenditures. Credit Facility. OnJuly 1, 2014 , the Company entered into a Credit Agreement withSunTrust Bank , as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the "Administrative Agent"), which was amended onJune 14, 2018 ,May 18, 2016 ,July 24, 2015 , andJune 26, 2015 . InApril 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 throughApril 2024 and makes 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. The Borrowing Base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The Borrowing Base will be redetermined semi-annually on eachMay 1 andNovember 1 . The Borrowing Base will also be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions. The Credit Facility allows for Eurodollar Loans and Base Rate Loans. The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 1.75% and 2.75% (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). 35 Table of Contents
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 Credit Facility also contains other customary affirmative and negative covenants and events of default. As ofDecember 31, 2019 ,$366,500,000 was outstanding on the Credit Facility. We are in compliance with all covenants contained in the Credit Facility. Cash Flows. Historically, our primary sources of cash have been from operations, equity offerings and borrowings on our Credit Facility. During 2019, 2018 and 2017, we had cash inflow from operations of$106,616,221 ,$70,357,321 and$42,806,224 , respectively. During the three years endedDecember 31, 2019 , we financed$140,848,094 through proceeds from the sale of stock. During 2019, 2018 and 2017, we had proceeds from drawdowns on our Credit Facility of$327,000,000 ,$39,500,000 , and$0 , respectively. We primarily used this cash to fund our capital expenditures and development aggregating$784,374,525 over the three years endedDecember 31, 2019 . AtDecember 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 atDecember 31, 2018 and cash on hand of$15,006,581 and working capital of$19,319,525 atDecember 31, 2017 .
Schedule of Contractual Obligations. The following table summarizes our
contractual obligations for periods subsequent to
Payment due by period
Less than 1 More than
Contractual Obligations Total year 13 years 35 years 5 years
Credit Facility (1) $ 366,500,000 $ - $
-
-
Operating Lease Obligations -
Office (3) 528,387 528,387 - - -
Operating Lease Obligations -
Field (4) 1,416,784 708,392 708,392 - -
Total $ 369,200,082 $ 1,547,985 $ 1,019,598 $ 366,632,499 $ -
This table does not include future commitment fees, interest expense or other (1) 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.
Financing Lease Obligations includes payments for vehicles under lease terms. (2) Per the term of the lease agreements, the Company will own the vehicles at
the end of their term.
Operating Lease Obligations - Office includes leases for our office spaces in
equipment. The
approximately 15,000 square feet. The Tulsa office is our accounting office (3) and is approximately 3,700 square feet. The office equipment leased is for
equipment that is used in our
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
2019, 2018 and 2017.
Operating Lease Obligations - Field includes equipment leased for the (4) 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.
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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 Put price Call price
2021 contracts
02/25/20 1,000 $ 45.00 $ 54.72
02/25/20 1,000 45.00 52.71
02/27/20 1,000 40.00 55.08
03/02/20 1,500 40.00 55.35
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.
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. 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
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 are detailed in Note 1 to our
financial statements included in this Annual Report. We have outlined below
certain of these policies as being of particular importance to the portrayal of
our financial position and results of operations and which require the
application of significant judgment by our management.
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Revenue Recognition. InJanuary 2018 , the Company adopted Accounting Standards Update ("ASU") 2014-09 Revenues from Contracts with Customers (Topic 606) ("ASU 2014-09"). The timing of recognizing revenue from the sale of produced crude oil and natural gas was not changed as a result of adopting ASU 2014-09. The 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 and 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 3 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 continentalUnited States . Write-down ofOil 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 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
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 theSEC 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 based on internal reports and audited byCawley, Gillespie & Associates, Inc. , independent petroleum engineers. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional properties are acquired. We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made. 38
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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 we file our tax returns. Our balance sheet for the year endedDecember 31, 2019 , includes a deferred tax liability of approximately$6.0 million . InJanuary 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 endedDecember 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.
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