Item 2. Properties
Item 2. Properties
Estimated Net Proved Reserves
The table below summarizes our estimated net proved reserves at December 31, 2021 and 2020 based on reports prepared by Cawley, Gillespie & Associates, Inc. (“Cawley”), our third-party independent reserve engineers for the years ending December 31, 2021 and 2020. In preparing its reports, Cawley evaluated properties representing all of our proved reserves at December 31, 2021 and 2020 in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities. Our estimated net proved reserves in the table below do not include probable or possible reserves and do not in any way include or reflect our commodity derivatives.
December 31, 2021 December 31, 2020
Proved Reserves
(MBoe)(1) % of
Total Proved Reserves
(MBoe)(2) % of
Total
SEC Proved Reserves:
Developed 170,598 59 % 84,145 69 %
Undeveloped 117,084 41 38,487 31
Total Proved Properties 287,682 100 % 122,632 100 %
___________________
(1) The table above values oil and natural gas reserve quantities as of December 31, 2021 assuming constant realized prices of $62.25 per barrel of oil and $3.37 per Mcf of natural gas. Under SEC guidelines, these prices represent the average prices per barrel of oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, after adjustment to reflect applicable transportation and quality differentials.
(2) The table above values oil and natural gas reserve quantities as of December 31, 2020 assuming constant realized prices of $32.69 per barrel of oil and $1.61 per Mcf of natural gas. Under SEC guidelines, these prices represent the average prices per barrel of oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, after adjustment to reflect applicable transportation and quality differentials.
Estimated net proved reserves at December 31, 2021 were 287,682 MBoe, a 135% increase from estimated net proved reserves of 122,632 MBoe at December 31, 2020. The increase was primarily due to the impact of our 2021 acquisitions, as well as higher activity levels in 2021 as compared to 2020. Increased development activity in 2021 led to an increase in our capital spending as well as an increase in the number of undeveloped drilling locations reflected in our 2021 proved reserve estimates. As a result of the higher activity levels and our 2021 acquisitions, the number of proved undeveloped wells included in the reserves was increased from 58.8 net wells in 2020 to 126.5 net wells in 2021.
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The following table sets forth summary information by reserve category with respect to estimated proved reserves at December 31, 2021:
SEC Pricing Proved Reserves (1)
Reserve Volumes PV-10 (3)
Reserve Category Oil
(MBbls) Natural Gas
(MMcf) Total
(MBoe) (2)
% Amount
(In thousands) %
PDP Properties 84,920 491,852 166,895 58 % $ 2,328,766 70 %
PDNP Properties 2,585 6,706 3,703 1 71,209 2
PUD Properties 43,890 439,165 117,084 41 941,114 28
Total 131,395 937,723 287,682 100 % $ 3,341,089 100 %
_____ ___________
(1) The SEC Pricing Proved Reserves table above values oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2021 based on average prices of $66.56 per barrel of oil and $3.60 per MMbtu of natural gas. Under SEC guidelines, these prices represent the average prices per barrel of oil and per MMbtu of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period. The average resulting price used as of December 31, 2021, after adjustment to reflect applicable transportation and quality differentials, was $62.25 per barrel of oil and $3.37 per Mcf of natural gas.
(2) Boe are computed based on a conversion ratio of one Boe for each barrel of oil and one Boe for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.
(3) Pre-tax PV10%, or “PV-10,” may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP measure. See “Reconciliation of PV-10 to Standardized Measure” below.
The table above assumes prices and costs discounted using an annual discount rate of 10% without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or federal income taxes. The information in the table above does not give any effect to or reflect our commodity derivatives.
Reconciliation of PV-10 to Standardized Measure
PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure for proved reserves calculated using SEC pricing. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. Moreover, GAAP does not provide a measure of estimated future net cash flows for reserves other than proved reserves or for reserves calculated using prices other than SEC prices. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.
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The following table reconciles the pre-tax PV10% value of our SEC Pricing Proved Reserves as of December 31, 2021 to the Standardized Measure of discounted future net cash flows.
SEC Pricing Proved Reserves
(In thousands)
Standardized Measure Reconciliation
Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%) $ 3,341,089
Future Income Taxes, Discounted at 10% (1)
(450,980)
Standardized Measure of Discounted Future Net Cash Flows $ 2,890,109
____________
(1) The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows. As a result of available net operating loss carryforwards and the remaining tax basis of our assets at December 31, 2021, our future income taxes were significantly reduced.
Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer estimating the reserves. Further, our actual realized price for our oil and natural gas is not likely to average the pricing parameters used to calculate our proved reserves. As such, the oil and natural gas quantities and the value of those commodities ultimately recovered from our properties will vary from reserve estimates.
Additional discussion of our proved reserves is set forth under the heading “Supplemental Oil and Gas Information - Unaudited” to our financial statements included later in this report.
Proved Undeveloped Reserves
At December 31, 2021, we had approximately 117.1 MMBoe of proved undeveloped reserves as compared to 38.5 MMBoe at December 31, 2020. A reconciliation of the change in proved undeveloped reserves during 2021 is as follows:
MMBoe
Estimated Proved Undeveloped Reserves at 12/31/2020 38.5
Converted to Proved Developed Through Drilling (8.7)
Added from Extensions and Discoveries 13.3
Purchases of Minerals in Place 60.7
Removed for 5-Year Rule (6.2)
Revisions 19.5
Estimated Proved Undeveloped Reserves at 12/31/2021 117.1
Our future development drilling program includes the drilling of approximately 126.5 proved undeveloped net wells before the end of 2026 at an estimated cost of $833.2 million. Our development plan for drilling proved undeveloped wells calls for the drilling of 62.5 net wells during 2022 (includes 32.0 net wells drilled at December 31, 2021, but classified as proved undeveloped due to Cawley’s internal guidelines which require greater than 50% of total costs to be incurred to be classified as developed), 25.0 net wells during 2023, 25.4 net wells during 2024, 10.7 net wells during 2025, and 2.9 net wells during 2026 for a total of 126.5 net wells. Our proved undeveloped locations were increased from 58.8 net wells at December 31, 2020 to 126.5 net wells at December 31, 2021 due to our 2021 acquisitions, higher commodity prices, and increased development activity. We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled including our acreage. All locations comprising our remaining proved undeveloped reserves are forecast to be drilled within five years from initially being recorded in accordance with our development plan.
At December 31, 2021, the PV-10 value of our proved undeveloped reserves amounted to 28% of the PV-10 value of our total proved reserves. Although our 2021 producing property additions exceeded our 5-year average development plan, there are numerous uncertainties. The development of these reserves is dependent upon a number of factors which include, but are not limited to: financial targets such as drilling within cash flow or reducing debt, drilling of obligatory wells, satisfactory
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rates of return on proposed drilling projects, and the levels of drilling activities by operators in areas where we hold leasehold interests. During 2021, we increased our development capital spending by 12% compared to 2020. With 70% of the PV-10 value of our total proved reserves supported by producing wells, we believe we will have sufficient cash flows and adequate liquidity to execute our development plan.
At December 31, 2021, we had spent a total of $61.3 million related to the development of proved undeveloped reserves, which resulted in the conversion of 8.7 MMBoe of proved undeveloped reserves as of December 31, 2020 to proved developed reserves as of December 31, 2021. Proved developed property additions in 2021 also included 4.5 MMBoe from the conversion of previously undeveloped locations that were not booked in our December 31, 2020 proved undeveloped reserves (the related development costs incurred at December 31, 2021 were $47.5 million). Additionally, our proved undeveloped reserves at December 31, 2021 included 62.6 MMBoe for net wells that had commenced drilling activities but remained classified as undeveloped reserves due to Cawley’s internal guidelines which require greater than 50% of the total costs to have been incurred in order to be classified as proved developed (the related development costs incurred at December 31, 2021 were $19.5 million).
In 2021, we also added 13.3 MMBoe of proved undeveloped reserves as a result of our acquisition and development activity. The SEC-prescribed commodity prices (after adjustment for transportation, quality and basis differentials) were $29.56 higher per barrel of oil and $1.76 higher per Mcf of natural gas at year-end 2021 as compared to year-end 2020. Additionally, we had positive revisions of 19.5 MMBoe primarily due to the aforementioned higher pricing. We also removed 6.2 MMBoe of proved undeveloped reserves due to the SEC-prescribed 5-year rule.
Proved Reserves Sensitivity by Price Scenario
The SEC disclosure rules allow for optional reserves sensitivity analysis, such as the sensitivity that oil and natural gas reserves have to price fluctuations. We have chosen to compare our proved reserves from the 2021 SEC case to one alternate pricing case, which uses a flat pricing deck of $50.00 per Bbl for oil and $3.00 per MMbtu for natural gas (the “$50 Flat Case”). The sensitivity scenario was not audited by a third-party. In this sensitivity scenario, all operating cost assumptions and other factors, other than the commodity price assumptions, have been held constant with the SEC case. However, the lower pricing in the sensitivity scenario did result in fewer future drilling locations that were economic at the $50 Flat Case compared to the 2021 SEC case. As a result, the $50 Flat Case included 16.6 fewer proved undeveloped net wells compared to the 126.5 proved undeveloped net wells included in the 2021 SEC case. This sensitivity is only meant to demonstrate the impact that changing commodity prices may have on estimated proved reserves and PV-10 and there is no assurance this outcome will be realized. The table below shows our proved reserves utilizing the 2021 SEC case compared with the $50 Flat Case.
Price Cases
SEC Case (1)
$50 Flat Case (2)
Net Proved Reserves (December 31, 2021)
Oil (MBbl)
Developed 87,505 80,920
Undeveloped 43,890 37,916
Total 131,395 118,835
Natural Gas (MMcf)
Developed 498,558 474,877
Undeveloped 439,165 428,019
Total 937,723 902,896
Total Proved Reserves (MBOE) 287,682 269,318
Pre-tax PV10% (in thousands) (3)
$ 3,341,089 $ 2,046,465
_________________
(1) Represents reserves based on pricing prescribed by the SEC. The unescalated twelve month arithmetic average of the first day of the month posted prices were adjusted for transportation and quality differentials to arrive at prices of $62.25 per Bbl for oil and $3.37 per Mcf for natural gas. Production costs were held constant for the life of the wells.
(2) Prices based on $50.00 per Bbl for oil and $3.00 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $45.75 per Bbl for oil and $2.74 per Mcf for natural gas.
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(3) Pre-tax PV10%, or PV-10, may be considered a non-GAAP financial measure. See “Reconciliation of PV-10 to Standardized Measure” above for a reconciliation of the PV-10 of our SEC Case proved reserves to the Standardized Measure. GAAP does not prescribe a corresponding measure for PV-10 of proved reserves based on other than SEC prices. As a result, it is not practicable for us to reconcile the PV-10 of our proved reserves based on the alternate pricing scenarios.
Independent Petroleum Engineers
We have utilized Cawley, an independent reserve engineering firm, as our third-party engineering firm. The selection of Cawley was approved by our Audit Committee. Cawley is a reservoir-evaluation consulting firm who evaluates oil and natural gas properties and independently certifies petroleum reserves quantities for various clients throughout the United States. Cawley has substantial experience calculating the reserves of various other companies with operations targeting the Bakken and Three Forks formations and, as such, we believe Cawley has sufficient experience to appropriately determine our reserves. Cawley utilizes proprietary technology, systems and data to calculate our reserves commensurate with this experience. The reports of our estimated proved reserves in their entirety are based on the information we provide to them. Cawley is a Texas Registered Engineering Firm (F-693). Our primary contact at Cawley is Todd Brooker, President. Mr. Brooker is a State of Texas Licensed Professional Engineer (License #83462). He is also a member of the Society of Petroleum Engineers.
In accordance with applicable requirements of the SEC, estimates of our net proved reserves and future net revenues are made using average prices at the beginning of each month in the 12-month period prior to the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation).
The reserves set forth in the Cawley report for the properties are estimated by performance methods or analogy. In general, reserves attributable to producing wells and/or reservoirs are estimated by performance methods such as decline curve analysis which utilizes extrapolations of historical production data. Reserves attributable to non-producing and undeveloped reserves included in our report are estimated by analogy. The estimates of the reserves, future production, and income attributable to properties are prepared using the economic software package Aries for Windows, a copyrighted program of Halliburton.
To estimate economically recoverable oil and natural gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which economic productivity from a reservoir is to be determined as of the effective date of the report. With respect to the property interests we own, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production taxes, recompletion and development costs and product prices are based on the SEC regulations, geological maps, well logs, core analyses, and pressure measurements.
The reserve data set forth in the Cawley report represents only estimates, and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.
Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. Our estimated net proved reserves, included in our SEC filings, have not been filed with or included in reports to any other federal agency. See “Item 1A. Risk Factors – Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”
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Internal Controls Over Reserves Estimation Process
We utilize a third-party reservoir engineering firm, as our independent reserves evaluator for 100% of our reserves base. In addition, we employ an internal reserve engineering department which is led by our Executive Vice President and Chief Engineer, who is responsible for overseeing the preparation of our reserves estimates. Our executive internal reserve engineer has a B.S. in petroleum engineering from Montana Tech, has over fifteen years of oil and gas experience on the reservoir side, and has experience working for large independents and financial firms on projects and acquisitions.
Our technical team meets with our independent third-party engineering firm to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data into our reserves evaluation software as well as management review, such as, but not limited to the following:
• Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in our reserves database;
• Review of working interests and net revenue interests in our reserves database against our well ownership system;
• Review of historical realized prices and differentials from index prices as compared to the differentials used in our reserves database;
• Review of updated capital costs prepared by our operations team;
• Review of internal reserve estimates by well and by area by our internal reservoir engineer;
• Discussion of material reserve variances among our internal reservoir engineer and our executive management; and
• Review of a preliminary copy of the reserve report by executive management.
Production, Price and Production Expense History
The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Oil supply in the United States has grown dramatically over the past few years, and the supply of oil could impact oil prices in the United States if the supply outstrips domestic demand. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.
The following table sets forth information regarding our oil and natural gas production, realized prices and production costs for the periods indicated. For additional information on price calculations, please see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
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Years Ended December 31,
2021 2020 2019
Net Production:
Oil (Bbl) 12,288,358 9,361,138 11,325,418
Natural Gas and NGLs (Mcf) 44,073,941 16,473,287 16,590,774
Total (Boe) 19,634,015 12,106,686 14,090,547
Oil (Bbl) per day 33,667 25,577 31,029
Mcf per day 120,751 45,009 45,454
Total (Boe) per day 53,792 33,078 38,604
Average Sales Prices:
Oil (per Bbl) $ 62.94 $ 32.61 $ 50.74
Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl) (10.17) 20.08 3.92
Oil Net of Settled Oil Derivatives (per Bbl) 52.77 52.69 54.66
Natural Gas and NGLs (per Mcf) 4.57 1.14 1.60
Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) (0.92) 0.02 —
Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) 3.65 1.16 1.60
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives 49.66 26.77 42.67
Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) (8.45) 15.55 3.15
Realized Price on a Boe Basis Including Settled Commodity Derivatives 41.21 42.32 45.82
Average Costs:
Production Expenses (per Boe) $ 8.70 $ 9.61 $ 8.44
Drilling and Development Activity
The following table sets forth the number of gross and net productive and non-productive wells drilled in the years ended December 31, 2021, 2020 and 2019. The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated.
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December 31,
2021 2020 2019
Gross Net (1)
Gross Net (1)
Gross Net (1)
Exploratory Wells:
Oil — — — — — —
Natural Gas — — — — — —
Non-Productive — — — — — —
Development Wells:
Oil 354 33.6 285 17.8 615 43.0
Natural Gas 8 2.2 — — — —
Non-Productive — — — — — —
Total Productive Exploratory and Development Wells 362 35.8 285 17.8 615 43.0
______________
(1) Net Well totals in 2021, 2020 and 2019 do not include an additional 169.4, 1.0 and 90.1 net wells, respectively, from acquisitions which were already producing when acquired.
The following table summarizes our cumulative gross and net productive oil and natural gas wells by geographic area within the United States at each of December 31, 2021, 2020 and 2019. Wells are classified as oil or natural gas wells according to the predominant production stream. All of our wells in the Williston and Permian Basins are classified as oil wells, although they also produce natural gas and condensate. All of our wells in the Appalachian Basin are classified as natural gas wells.
December 31,
2021 2020 2019
Gross Net Gross Net Gross Net
Williston Basin 6,996 571.7 6,633 474.5 6,156 458.7
Permian Basin 83 11.6 7 0.6 — —
Appalachian Basin 357 97.5 — — — —
Total 7,436 680.8 6,640 475.1 6,156 458.7
As of December 31, 2021, we had an additional 360 gross (42.5 net) wells in process, meaning wells that have been spud and are in the process of drilling, completing or waiting on completion.
Leasehold Properties
As of December 31, 2021, our principal assets included approximately 245,431 net acres located in the United States. The following table summarizes our estimated gross and net developed and undeveloped acreage by geographic area at December 31, 2021.
Developed Acreage Undeveloped Acreage Total Acreage
Gross Net Gross Net Gross Net
Williston Basin 594,668 163,431 32,424 16,952 627,092 180,383
Permian Basin 9,194 2,927 1,438 536 10,632 3,463
Appalachian Basin 202,888 47,388 93,390 14,197 296,278 61,585
Total: 806,750 213,746 127,252 31,685 934,002 245,431
As of December 31, 2021, approximately 87% of our total acreage was developed. All of our proved reserves are located in the United States.
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Recent Acquisitions
We generally assess acreage subject to near-term drilling activities on a lease-by-lease basis because we believe each lease’s contribution to a subject spacing unit is best assessed on that basis if development timing is sufficiently clear. Consistent with that approach, a significant portion of our acreage acquisitions involve properties that are selected by us on a lease-by-lease basis for their participation in a well expected to be spud in the near future, and the subject leases are then aggregated to complete one single closing with the transferor. As such, we generally view each acreage assignment from brokers, landmen and other parties as involving several separate acquisitions combined into one closing with the common transferor for convenience. However, in certain instances an acquisition may involve a larger number of leases presented by the transferors as a single package without negotiation on a lease-by-lease basis. In those instances, we still review each lease on a lease-by-lease basis to ensure that the package as a whole meets our acquisition criteria and drilling expectations. See Note 3 and Note 14 to our financial statements regarding our recent acquisition activity.
Acreage Expirations
As a non-operator, we are subject to lease expirations if an operator does not commence the development of operations within the agreed terms of our leases. All of our leases for undeveloped acreage summarized in the table below will expire at the end of their respective primary terms, unless we renew the existing leases, establish commercial production from the acreage or some other “savings clause” is exercised. In addition, our leases typically provide that the lease does not expire at the end of the primary term if drilling operations have been commenced. While we generally expect to establish production from most of our acreage prior to expiration of the applicable lease terms, there can be no guarantee we can do so. The approximate expiration of our net acres which are subject to expire between 2022 and 2026 and thereafter, are set forth below:
Acreage Subject to Expiration
Year Ended Gross Net
December 31, 2022 37,618 7,421
December 31, 2023 31,300 5,746
December 31, 2024 26,931 6,614
December 31, 2025 13,047 4,555
December 31, 2026 and thereafter 14,470 4,437
Total 123,366 28,773
During 2021, we had leases expire covering approximately 4,177 net acres. The 2021 lease expirations carried a cost of $3.0 million. We believe that the expired acreage was not material to our capital deployed.
Unproved Properties
All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion. Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion.
We assess all items classified as unproved property on an annual basis, or if certain circumstances exist, more frequently, for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and amortization.
We historically have acquired our unproved properties by purchasing individual or small groups of leases directly from mineral owners, landmen, or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators. We generally participate in drilling activities on a heads up basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling.
We believe that the majority of our unproved costs will become subject to depletion within the next five years by proving up reserves relating to our acreage through exploration and development activities, by impairing the acreage that will
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expire before we can explore or develop it further or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of our reserves.
Depletion of Oil and Natural Gas Properties
Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses during 2021, 2020 and 2019.
Years Ended December 31,
(In thousands, except per Boe data) 2021 2020 2019
Depletion of Oil and Natural Gas Properties $ 138,759 $ 160,643 $ 209,050
Depletion Expense (per Boe) 7.07 13.27 14.84
Research and Development
We do not anticipate performing any significant research and development under our plan of operation.
Delivery Commitments
For our properties in the Appalachian Basin, we have contractually agreed to deliver firm quantities of natural gas to certain third parties, which we seek to fulfill with production from existing reserves. In the event we are not able to meet these firm commitments, we are subject to deficiency payments. As a non-operator, we have limited control over the drilling of new wells and primarily rely on our third-party operating partners in this regard. The following table summarizes our total net commitments as of December 31, 2021.
(in Bcf) Commitment Volumes
2022 19.0
2023 19.0
2024 18.4
2025 3.2
Total 59.6
Item 3. Legal Proceedings
Our company is subject from time to time to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business.
Item 4. Mine Safety Disclosures
None.
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PART II