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SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) | 12 Months Ended
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Dec. 31, 2020
Extractive Industries [Abstract] |
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) | SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Oil and Gas Reserves Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures. Estimates of total proved reserves at December 31, 2020, 2019 and 2018 were based on studies performed by the Company's petroleum engineering staff. The estimates were computed using the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the respective year. The estimates were audited by Miller and Lents, Ltd. (Miller and Lents), who indicated that based on their investigation and subject to the limitations described in their audit letter, they believe the results of those estimates and projections were reasonable in the aggregate. No major discovery or other favorable or unfavorable event after December 31, 2020, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date. The following tables illustrate the Company's net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated, as estimated by the Company's engineering staff. All reserves are located within the continental United States.
| Natural Gas (Bcf) |  | Crude Oil & NGLs (Mbbl)(1) |  | Total (Bcfe)(2)
December 31, 2017 | 9,353 |  |  | 62,252 |  |  | 9,726 |
Revision of prior estimates(3) | 776 |  |  | 677 |  |  | 780 |
Extensions, discoveries and other additions(4) | 2,243 |  |  | — |  |  | 2,244 |
Production | (730) |  |  | (829) |  |  | (735) |
Sales of reserves in place(5) | (38) |  |  | (61,980) |  |  | (410) |
December 31, 2018 | 11,604 |  |  | 120 |  |  | 11,605 |
Revision of prior estimates(6) | 48 |  |  | (48) |  |  | 47 |
Extensions, discoveries and other additions(4) | 2,116 |  |  | — |  |  | 2,116 |
Production | (865) |  |  | — |  |  | (865) |
Sales of reserves in place | — |  |  | (50) |  |  | — |
December 31, 2019 | 12,903 |  |  | 22 |  |  | 12,903 |
Revision of prior estimates(7) | (347) |  |  | (3) |  |  | (347) |
Extensions, discoveries and other additions(4) | 1,974 |  |  | — |  |  | 1,974 |
Production | (858) |  |  | (4) |  |  | (858) |
December 31, 2020 | 13,672 |  |  | 15 |  |  | 13,672 |
Proved Developed Reserves |  |  |  |  |
December 31, 2017 | 6,001 |  |  | 31,066 |  |  | 6,187 |
December 31, 2018 | 7,402 |  |  | 107 |  |  | 7,403 |
December 31, 2019 | 8,056 |  |  | 22 |  |  | 8,056 |
December 31, 2020 | 8,608 |  |  | 15 |  |  | 8,608 |
Proved Undeveloped Reserves |  |  |  |  |
December 31, 2017 | 3,352 |  |  | 31,186 |  |  | 3,539 |
December 31, 2018 | 4,202 |  |  | 13 |  |  | 4,202 |
December 31, 2019 | 4,847 |  |  | — |  |  | 4,847 |
December 31, 2020 | 5,064 |  |  | — |  |  | 5,064 |
_______________________________________________________________________________ (1)There were no significant NGL reserves for 2020, 2019 and 2018. For 2017, NGL reserves were less than one percent of the Company's total proved equivalent reserves and 13.7 percent of the Company's proved crude oil and NGL reserves. (2)Includes natural gas and natural gas equivalents determined by using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or NGLs. (3)The net upward revision of 780 Bcfe was primarily due to an upward revision of 1,123 Bcfe associated with positive drilling results in the Dimock field in northeast Pennsylvania, partially offset by a downward revision of 345 Bcfe associated with proved undeveloped (PUD) reserves reclassifications. (4)Extensions, discoveries and other additions were primarily related to drilling activity in the Dimock field located in northeast Pennsylvania. The Company added 1,974 Bcfe, 2,116 Bcfe and 2,243 Bcfe of proved reserves in this field in 2020, 2019 and 2018, respectively. (5)Sales of reserves in place were primarily related to the divestiture of certain oil and gas properties in the Eagle Ford Shale in February 2018 and the Haynesville Shale in July 2018, which represented 404 Bcfe and 6 Bcfe, respectively. (6)The net upward revision of 47 Bcfe was primarily due to a net upward performance revision of 67 Bcfe, partially offset by a downward revision of 18 Bcfe associated with PUD reclassifications as a result of the five-year limitation. The net upward performance revision of 67 Bcfe was primarily due to an upward revision of 417 Bcfe associated with the Company's PUD reserves due to performance revisions and the drilling of longer lateral length wells, partially offset by a downward performance revision of 350 Bcfe related to certain proved developed producing properties. (7)The net downward revision of 347 Bcfe was primarily due to a net downward performance revision of 245 Bcfe and a downward revision of 66 Bcfe associated with PUD reclassifications as a result of the five-year limitation. The net downward performance revision of 245 Bcfe was primarily due to a downward performance revision of 368 Bcfe related to certain proved developed producing properties, partially offset by an upward revision of 123 Bcfe associated with our PUD reserves due to performance revisions and the drilling of longer lateral length wells. Capitalized Costs Relating to Oil and Gas Producing Activities Capitalized costs relating to oil and gas producing activities and related accumulated depreciation, depletion and amortization were as follows:
| December 31,
(In thousands) | 2020 |  | 2019 |  | 2018
Aggregate capitalized costs relating to oil and gas producing activities | $ | 7,154,452 |  |  | $ | 6,676,122 |  |  | $ | 5,995,194 |
Aggregate accumulated depreciation, depletion and amortization | (3,148,564) |  |  | (2,861,014) |  |  | (2,540,068) |
Net capitalized costs | $ | 4,005,888 |  |  | $ | 3,815,108 |  |  | $ | 3,455,126 |
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Costs incurred in property acquisition, exploration and development activities were as follows:
| Year Ended December 31,
(In thousands) | 2020 |  | 2019 |  | 2018
Property acquisition costs, proved | $ | — |  |  | $ | — |  |  | $ | — |
Property acquisition costs, unproved | 5,821 |  |  | 6,072 |  |  | 29,851 |
Exploration costs | 15,419 |  |  | 20,270 |  |  | 94,309 |
Development costs | 546,646 |  |  | 761,326 |  |  | 778,574 |
Total costs | $ | 567,886 |  |  | $ | 787,668 |  |  | $ | 902,734 |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following information has been developed based on natural gas and crude oil reserve and production volumes estimated by the Company's engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) be viewed as representative of the current value of the Company. The Company believes that the following factors should be taken into account when reviewing the following information: •Future costs and selling prices will differ from those required to be used in these calculations. •Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations. •Selection of a 10 percent discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues. •Future net revenues may be subject to different rates of income taxation. Under the Standardized Measure, future cash inflows were estimated by using the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year. The average prices (adjusted for basis and quality differentials) related to proved reserves are as follows:
| Year Ended December 31,
| 2020 |  | 2019 |  | 2018
Natural gas | $ | 1.64 |  |  | $ | 2.35 |  |  | $ | 2.58 |
Crude oil | $ | 32.53 |  |  | $ | 55.80 |  |  | $ | 65.21 |
NGLs | $ | — |  |  | $ | — |  |  | $ | 21.64 |
In the above table, natural gas prices are stated per Mcf and crude oil and NGL prices are stated per barrel. Future cash inflows were reduced by estimated future development and production costs based on year end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations. The applicable accounting standards require the use of a 10 percent discount rate. Management does not solely use the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of proved reserves, and varying price and cost assumptions considered more representative of a range of anticipated economic conditions. Standardized Measure is as follows:
| Year Ended December 31,
(In thousands) | 2020 |  | 2019 |  | 2018
Future cash inflows | $ | 22,385,385 |  |  | $ | 30,302,480 |  |  | $ | 29,904,474 |
Future production costs | (10,783,895) |  |  | (10,039,294) |  |  | (8,702,734) |
Future development costs(1) | (1,612,659) |  |  | (2,006,167) |  |  | (1,766,796) |
Future income tax expenses | (2,175,916) |  |  | (4,042,787) |  |  | (4,166,089) |
Future net cash flows | 7,812,915 |  |  | 14,214,232 |  |  | 15,268,855 |
10% annual discount for estimated timing of cash flows | (4,750,760) |  |  | (8,353,115) |  |  | (8,785,547) |
Standardized measure of discounted future net cash flows | $ | 3,062,155 |  |  | $ | 5,861,117 |  |  | $ | 6,483,308 |
______________________________________________________________________________ (1)Includes $223.7 million, $212.9 million and $193.5 million in plugging and abandonment costs for the years ended December 31, 2020, 2019 and 2018, respectively. Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following is an analysis of the changes in the Standardized Measure:
| Year Ended December 31,
(In thousands) | 2020 |  | 2019 |  | 2018
Beginning of year | $ | 5,861,117 |  |  | $ | 6,483,308 |  |  | $ | 5,010,446 |
Discoveries and extensions, net of related future costs | 311,336 |  |  | 1,075,839 |  |  | 1,280,499 |
Net changes in prices and production costs | (4,326,254) |  |  | (1,510,104) |  |  | 2,078,479 |
Accretion of discount | 750,041 |  |  | 813,480 |  |  | 596,569 |
Revisions of previous quantity estimates | (107,467) |  |  | 28,310 |  |  | 586,494 |
Timing and other | 5,992 |  |  | (192,563) |  |  | (76,761) |
Development costs incurred | 501,093 |  |  | 468,748 |  |  | 338,297 |
Sales and transfers, net of production costs | (746,310) |  |  | (1,316,752) |  |  | (1,343,872) |
Sales of reserves in place | — |  |  | (1,350) |  |  | (1,290,594) |
Net change in income taxes | 812,607 |  |  | 12,201 |  |  | (696,249) |
End of year | $ | 3,062,155 |  |  | $ | 5,861,117 |  |  | $ | 6,483,308 |

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