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Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)
 12 Months Ended
Dec. 31, 2021
Extractive Industries [Abstract]  
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)The supplemental information below includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves.
Capitalized Costs Related to Oil and Natural Gas Producing Activities

The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):
 December 31,
 202120202019
Oil and natural gas properties
Proved$1,454,016 $1,463,950 $1,484,359 
Unproved12,255 17,964 24,603 
Total oil and natural gas properties1,466,271 1,481,914 1,508,962 
Less accumulated depreciation, depletion and impairment(1,373,217)(1,375,692)(1,129,622)
Net oil and natural gas properties capitalized costs$93,054 $106,222 $379,340 

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):
Year Ended December 31,
202120202019
Acquisitions of properties
Proved$3,545 $3,701 $(210)
Unproved— — 2,653 
Exploration (1)905 1,005 2,900 
Development10,045 3,563 156,210 
Total cost incurred$14,495 $8,269 $161,553 
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(1)    Includes land, geological, geophysical and leasehold costs.

Results of Operations for Oil and Natural Gas Producing Activities

The following table presents the Company’s results of operations from oil and natural gas producing activities (in thousands), which exclude any interest costs or indirect general and administrative costs and, therefore, are not necessarily indicative of the impact the Company’s operations have on actual net earnings.
Year Ended December 31,
202120202019
Revenues$168,882 $114,450 $266,104 
Expenses
Production costs46,309 53,474 110,711 
Depreciation and depletion9,372 50,349 146,874 
Impairment — 218,399 409,574 
Total expenses55,681 322,222 667,159 
Income (loss) before income taxes113,201 (207,772)(401,055)
Income tax expense (benefit) (1)26,734 (51,750)(105,477)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)$86,467 $(156,022)$(295,578)
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(1)    Income tax (benefit) expense is hypothetical and is calculated by applying the Company’s statutory tax rate to (loss) income before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits.
Oil, Natural Gas and NGL Reserve Quantities

Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on oil, natural gas and NGL prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company’s engineers and independent petroleum consultants relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the reserve estimates is dependent on many factors, including the following:

•the quality and quantity of available data and the engineering and geological interpretation of that data;

•estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;

•the accuracy of mandated economic assumptions; and

•the judgment of the personnel preparing the estimates.

Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.

Over 96% of the Company’s proved reserves estimates have been prepared by independent reservoir engineers and geoscience professionals and the remaining 4% of proved reserves are estimated internally are reviewed by members of the Company’s senior management to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the SEC.

Cawley, Gillespie & Associates, independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs for over 96% of the Company’s net interest in oil and natural gas properties as of the end 2021 and Cawley, Gillespie & Associates and Ryder Scott together prepared over 90% as of the end of 2020 and 2019. Cawley, Gillespie & Associates and Ryder Scott are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Company or its properties and are not employed on a contingent basis. The remaining proved reserves were based on Company estimates.

The Company believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under recent, past or historical economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.

2021 Activity. Proved reserves increased from 36.9 MMBoe at December 31, 2020 to 71.3 MMBoe at December 31, 2021, primarily as a result of positive revisions of 27.3 MMBoe associated with the increase in year-end SEC commodity prices for oil and natural gas, 13.6 MMBoe associated with reduction in expenses and other commercial improvements, 3.7 MMBoe related to a well reactivation program, and purchases of 1.4 MMBoe of proved reserves. The Company also recorded 2021 production totaling 6.8 MMBoe and a decrease of 3.6 MMBoe due to sales and 1.2 MMBoe attributable to well shut-ins, and other revisions.

2020 Activity. Proved reserves decreased from 89.9 MMBoe at December 31, 2019 to 36.9 MMBoe at December 31, 2020, primarily as a result of downward revisions of 45.0 MMBoe associated with the decrease in year-end SEC commodity prices for oil and natural gas consisting of (27.8 MMBoe from removing PUDs, and 17.3 MMBoe from remaining proved reserves). The Company also recorded 2020 production totaling 8.7 MMBoe and a decrease of 9.0 MMBoe attributable to well
shut-ins, sales and other revisions. These reductions were partially offset by an 8.6 MMBoe increase associated with reduction in expenses and other commercial improvements, and purchases of 1.1 MMBoe of proved reserves.

2019 Activity. Proved reserves decreased from 160.2 MMBoe at December 31, 2018 to 89.9 MMBoe at December 31, 2019, primarily as a result of downward revisions of 50.9 MMBoe associated with the decrease in year-end SEC prices for oil and natural gas consisting of (i) 39.8 MMBoe from downgrading PUDs, and (ii) 11.1 MMBoe from remaining proved reserves. The Company also recorded a decrease of 10.9 MMBoe attributable to increased commodity price differentials, and a decrease of 3.2 MMBoe attributable to well performance. These reductions were partially offset by a 12.6 MMBoe increase associated with converting undeveloped well locations from SRLs to planned XRLs as well as reduced future estimated development capital on these undeveloped locations.

The summary below presents changes in the Company’s estimated reserves. NPB is included in 2021, 2020 and 2019.
OilNGLNatural GasTotal
 (MBbls)(MBbls)(MMcf) (1)MBoe
Proved developed and undeveloped reserves
As of December 31, 201864,019 28,175 407,891 160,176 
Revisions of previous estimates(25,530)(9,277)(142,239)(58,514)
Acquisitions of new reserves— — — — 
Extensions and discoveries635 94 2,127 1,084 
Sales of reserves in place(297)(223)(2,308)(905)
Production(3,519)(2,910)(33,164)(11,956)
As of December 31, 201935,308 15,859 232,307 89,885 
Revisions of previous estimates(24,650)(2,246)(107,426)(44,800)
Acquisitions of new reserves74 437 3,391 1,076 
Extensions and discoveries— — — — 
Sales of reserves in place(163)(111)(1,827)(579)
Production(2,084)(2,694)(23,552)(8,703)
As of December 31, 20208,485 11,245 102,893 36,879 
Revisions of previous estimates (2)3,627 14,924 148,736 43,340 
Acquisitions of new reserves135 438 5,235 1,446 
Extensions and discoveries— — — — 
Sales of reserves in place(3440)(28)(716)(3,587)
Production(957)(2,266)(21,417)(6,793)
As of December 31, 20217,850 24,313 234,731 71,285 
Proved developed reserves
As of December 31, 201914,078 14,532 200,853 62,086 
As of December 31, 20208,485 11,245 102,893 36,879 
As of December 31, 20217,850 24,313 234,731 71,285 
Proved undeveloped reserves
As of December 31, 201921,230 1,327 31,454 27,799 
As of December 31, 2020— — — — 
As of December 31, 2021— — — — 
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(1)    Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
(2)    Revisions include changes due to previous quantity estimates, pricing, and productions costs.
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with ASC Topic 932, Extractive Activities—Oil and Gas, ("ASC Topic 932"). The assumptions underlying the computation of the standardized measure of discounted cash flows may be summarized as follows:
•the standardized measure includes the Company’s estimate of proved oil, natural gas and NGL reserves and projected future production volumes based upon economic conditions;
•pricing is applied based upon SEC prices at December 31, 2021, 2020 and 2019, adjusted for fixed or determinable contracts that are in existence at year-end.
The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:
 At December 31,
 202120202019
Oil (per Bbl)$64.95 $36.54 $50.63 
NGL (per Bbl)$19.26 $6.40 $12.45 
Natural gas (per Mcf)$2.56 $0.87 $1.16 
•future development and production costs are determined based on trailing 12 month average cost at year-end;
•the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and
•a discount factor of 10% per year is applied annually to the future net cash flows.

The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands).
December 31,
202120202019
Future cash inflows from production$1,579,734 $471,038 $2,254,530 
Future production costs(735,904)(270,512)(1,028,695)
Future development costs (1)(66,732)(81,687)(536,081)
Future income tax expenses (2)— — — 
Undiscounted future net cash flows777,098 118,839 689,754 
10% annual discount(344,184)(13,853)(325,464)
Standardized measure of discounted future net cash flows (3)$432,914 $104,986 $364,290 
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(1)    Includes abandonment costs.
(2)    The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws, including expected tax benefits to be realized from the utilization of net operating loss carryforwards.
(3)    NPB is included in 2020 and 2019.
The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):
Year Ended December 31,
202120202019
Beginning present value $104,986 $364,290 $1,045,603 
Changes during the year
Revenues less production(122,964)(61,407)(155,772)
Net changes in prices, production and other costs380,026 (135,652)(491,035)
Development costs incurred83 — 90,591 
Net changes in future development costs (1)446 (2,167)450,162 
Extensions and discoveries— — 11,921 
Revisions of previous quantity estimates (1)112,926 (99,533)(478,238)
Accretion of discount6,016 36,429 101,778 
Purchases of reserves in-place15,541 4,744 — 
Sales of reserves in-place(29,792)(1,067)(3,331)
Timing differences and other (2)(34,354)(651)(207,389)
Net change for the year327,928 (259,304)(681,313)
Ending present value (3) (4)$432,914 $104,986 $364,290 
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(1)     The change in estimated future development costs and revisions of previous quantity estimates primarily reflect increases from the well reactivation program and extended reserve life due to increase in pricing.
(2)    The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.
(3)    Standardized Measure was determined using SEC prices, and does not reflect actual prices received or current market prices.
(4)    NPB is included in 2020 and 2019.