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Supplemental Oil and Gas Disclosures (Unaudited)
 12 Months Ended
Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Supplemental Oil and Gas Disclosures (Unaudited)
SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)
The Company’s operating natural gas and oil properties are located solely in the United States.  The Company also has licenses to properties in Canada, the development of which is subject to an indefinite moratorium.  See “Our Operations – Other – New Brunswick, Canada” in Item 1 of Part 1 of this Annual Report.
Net Capitalized Costs
The following table shows the capitalized costs of natural gas and oil properties and the related accumulated depreciation, depletion and amortization as of December 31, 2020 and 2019:
(in millions)20202019
Proved properties$25,789 $23,744 
Unproved properties1,472 1,506 
Total capitalized costs27,261 25,250 
Less:  Accumulated depreciation, depletion and amortization(23,362)(20,203)
Net capitalized costs$3,899 $5,047 
Natural gas and oil properties not subject to amortization represent investments in unproved properties and major development projects in which the Company owns an interest. These unproved property costs include unevaluated costs associated with leasehold or drilling interests and unevaluated costs associated with wells in progress.  The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2020:
(in millions)202020192018PriorTotal
Property acquisition costs$116 $44 $34 $1,022 $1,216 
Exploration and development costs17 17 14 20 68 
Capitalized interest62 47 33 46 188 
$195 $108 $81 $1,088 $1,472 
Of the total net unevaluated costs excluded from amortization as of December 31, 2020, approximately $1.1 billion is related to undeveloped properties in Southwest Appalachia (acquired in 2014 and 2015), $88 million is related to the recently acquired Montage properties and approximately $6 million is related to the acquisition of undeveloped properties in Northeast Appalachia.  Additionally, the Company has approximately $188 million of unevaluated capitalized interest and $61 million of unevaluated costs related to wells in progress.  The remaining costs excluded from amortization are related to properties which are not individually significant and on which the evaluation process has not been completed.  The timing and amount of property acquisition and seismic costs included in the amortization computation will depend on the location and timing of drilling wells, results of drilling and other assessments. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation.
Costs Incurred in Natural Gas and Oil Exploration and Development
The table below sets forth capitalized costs incurred in natural gas and oil property acquisition, exploration and development activities:
(in millions, except per Mcfe amounts)202020192018
Unproved property acquisition costs$124 
(1)
$162 $164 
Exploration costs— 2 5 
Development costs784 936 1,014 
Capitalized costs incurred$908 $1,100 $1,183 
Full cost pool amortization per Mcfe$0.38 $0.56 $0.51 
(1)Excludes $90 million of unevaluated property acquisition costs associated with the non-cash Montage Merger.
Capitalized interest is included as part of the cost of natural gas and oil properties.  The Company capitalized $88 million, $109 million and $115 million during 2020, 2019 and 2018, respectively, based on the Company’s weighted average cost of borrowings used to finance expenditures.
In addition to capitalized interest, the Company capitalized internal costs totaling $56 million, $77 million and $90 million during 2020, 2019 and 2018, respectively, which were directly related to the acquisition, exploration and development of the Company’s natural gas and oil properties. 
Results of Operations from Natural Gas and Oil Producing Activities
The table below sets forth the results of operations from natural gas and oil producing activities:
(in millions)202020192018
Sales$1,348 $1,703 $2,525 
Production (lifting) costs(866)(781)(974)
Depreciation, depletion and amortization(348)(462)(514)
Impairment of natural gas and oil properties(2,825)— — 
(2,691)460 1,037 
Provision for income taxes (1)
— 110 — 
Results of operations (2)
$(2,691)$350 $1,037 
(1)Prior to the recognition of a valuation allowance, in 2020 and 2018 the Company recognized an income tax provision (benefit) of ($624) million and $254 million, respectively.
(2)Results of operations exclude the gain (loss) on unsettled commodity derivative instruments.  See Note 6.
The results of operations shown above exclude general and administrative expenses and interest expense and are not necessarily indicative of the contribution made by the Company’s natural gas and oil operations to its consolidated operating results. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation, depletion and amortization, and after giving effect to permanent differences and tax credits.
Natural Gas and Oil Reserve Quantities
The Company engaged the services of Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm, to audit the reserves estimated by the Company’s reservoir engineers.  In conducting its audit, the engineers and geologists of NSAI studied the Company’s major properties in detail and independently developed reserve estimates.  NSAI’s audit consists primarily of substantive testing, which includes a detailed review of the Company’s major properties, and accounted for approximately 97% of the present worth of the Company’s total proved reserves as of December 31 of 2020. For 2019 and 2018, NSAI’s audit accounted for 99% of the present worth of the Company’s total proved properties.  A reserve audit is not the same as a financial audit, and a reserve audit is less rigorous in nature than a reserve report prepared by an independent petroleum engineering firm containing its own estimate of reserves.  Reserve estimates are inherently imprecise, and the Company’s reserve estimates are generally based upon extrapolation of historical production trends, historical prices of natural gas and crude oil and analogy to similar properties and volumetric calculations.  Accordingly, the Company’s estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available.
The following table summarizes the changes in the Company’s proved natural gas, oil and NGL reserves for 2020, 2019 and 2018, all of which were located in the United States:
Natural Gas
(Bcf)
Oil
(MBbls)
NGL
(MBbls)
Total
(Bcfe)
December 31, 201711,126 65,636 542,455 14,775 
Revisions of previous estimates due to price96 788 8,912 154 
Revisions of previous estimates other than price316 410 8,855 372 
Extensions, discoveries and other additions753 5,830 36,823 1,009 
Production(807)(3,407)(19,706)(946)
Acquisition of reserves in place— — — — 
Disposition of reserves in place (1)
(3,440)(250)(276)(3,443)
December 31, 20188,044 69,007 577,063 11,921 
Revisions of previous estimates due to price(480)(2,041)(37,492)(717)
Revisions of previous estimates other than price (2)
685 3,707 65,869 1,102 
Extensions, discoveries and other additions992 6,948 26,941 1,195 
Production(609)(4,696)(23,620)(778)
Acquisition of reserves in place— — — — 
Disposition of reserves in place (2)— — (2)
December 31, 20198,630 72,925 608,761 12,721 
Revisions of previous estimates due to price(2,143)(32,507)(338,639)(4,370)
Revisions of previous estimates other than price763 3,816 106,444 1,424 
Extensions, discoveries and other additions714 135 4,371 741 
Production(694)(5,141)(25,927)(880)
Acquisition of reserves in place (3)
1,911 18,796 55,141 2,354 
Disposition of reserves in place— — — — 
December 31, 20209,181 58,024 410,151 11,990 
(1)The 2018 disposition is primarily associated with the Fayetteville Shale sale.
(2)For the year ended December 31, 2019, revisions of previous estimates other than price includes 109 Bcfe of proved undeveloped reserves reclassified to unproved due to changes in the drilling plan, in accordance with the SEC five-year rule.
(3)The 2020 acquisition is primarily associated with the Montage Merger.
Natural Gas
(Bcf)
Oil
(MBbls)
NGL
(MBbls)
Total
(Bcfe)
Proved developed reserves as of:    
December 31, 20184,395 18,037 175,480 5,557 
December 31, 20194,906 26,124 226,271 6,421 
December 31, 20206,342 33,563 276,548 8,203 
Proved undeveloped reserves as of:    
December 31, 20183,649 50,970 401,583 6,364 
December 31, 20193,724 46,801 382,490 6,300 
December 31, 20202,839 24,461 133,603 3,787 
The Company’s estimated proved natural gas, oil and NGL reserves were 11,990 Bcfe at December 31, 2020, compared to 12,721 Bcfe at December 31, 2019.  The Company’s reserves decreased in 2020, compared to 2019, as acquisitions, non-price revisions, positive extensions, discoveries and other additions in Appalachia were more than offset by negative price revisions and production.  The increase in non-price revisions at December 31, 2020 resulted primarily from increased well performance and lower operating costs.
The increase in the Company’s reserves in 2019 primarily resulted from the positive extensions, discoveries, other additions and revisions in Appalachia were only partially offset by negative price revisions.  The decrease in the Company’s reserves in 2018 primarily resulted from the disposition of the reserves related to the Fayetteville Shale and was only partially offset by positive extensions, discoveries, other additions and revisions in Appalachia.  
The following table summarizes the changes in reserves for 2018, 2019 and 2020:
AppalachiaFayetteville  
(in Bcfe)NortheastSouthwest
Shale (1)
Other (2)
Total
December 31, 20174,126 6,962 3,679 8 14,775 
Net revisions
Price revisions41 106 6 1 154 
Performance and production revisions107 272 (6)(1)372 
Total net revisions148 378 — — 526 
Extensions, discoveries and other additions
Proved developed154 22 1 — 177 
Proved undeveloped397 435 — — 832 
Total reserve additions551 457 1 — 1,009 
Production(459)(243)(243)(1)(946)
Acquisition of reserves in place— — — — — 
Disposition of reserves in place— — (3,437)(6)(3,443)
December 31, 20184,366 7,554 — 1 11,921 
Net revisions
Price revisions(57)(660)— — (717)
Performance and production revisions (3)
127 975 — — 1,102 
Total net revisions70 315 — — 385 
Extensions, discoveries and other additions
Proved developed185 6 — — 191 
Proved undeveloped677 327 — — 1,004 
Total reserve additions862 333 — — 1,195 
Production(459)(319)— — (778)
Acquisition of reserves in place— — — — — 
Disposition of reserves in place(2)— — — (2)
December 31, 20194,837 7,883 — 1 12,721 
Net revisions
Price revisions(389)(3,981)— — (4,370)
Performance and production revisions46 1,378 — — 1,424 
Total net revisions(343)(2,603)— — (2,946)
Extensions, discoveries and other additions
Proved developed198 69 — — 267 
Proved undeveloped474 — — — 474 
Total reserve additions672 69 — — 741 
Production(473)(407)— — (880)
Acquisition of reserves in place223 2,131 — — 2,354 
Disposition of reserves in place— — — — — 
December 31, 20204,916 7,073 — 1 11,990 
(1)The Fayetteville Shale E&P assets and associated reserves were divested in December 2018.
(2)Other includes properties outside of Appalachia and Fayetteville Shale.
(3)Performance and production revisions for the year ended December 31, 2019 include 109 Bcfe of proved undeveloped reserves reclassified to unproved due to changes in the drilling plan, in accordance with the SEC five-year rule.
The Company’s December 31, 2020 proved reserves included 2,437 Bcfe of proved undeveloped reserves from 138 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but do not have a positive present value when discounted at 10%.  These properties had a negative present value of $207 million when discounted at 10%.  The Company made a final investment decision and is committed to developing these reserves within the next five years from the date of initial booking. 
The Company’s December 31, 2019 proved reserves included 929 Bcfe of proved undeveloped reserves from 90 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $50 million present value when discounted at 10%.  The Company’s December 31, 2018 proved reserves included 190
Bcfe of proved undeveloped reserves from 30 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $24 million present value when discounted at 10%.
The Company has no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil.  The Company used standard engineering and geoscience methods, or a combination of methodologies in determining estimates of material properties, including performance and test date analysis, offset statistical analogy of performance data, volumetric evaluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with estimated reservoir parameters (including reservoir temperature and pressure, formation depth and formation volume factors), geological analysis, including structure and isopach maps and seismic analysis, including review of 2-D and 3-D data to ascertain faults, closure and other factors.
Standardized Measure of Discounted Future Net Cash Flows
The following standardized measures of discounted future net cash flows relating to proved natural gas, oil and NGL reserves as of December 31, 2020, 2019 and 2018 are calculated after income taxes, discounted using a 10% annual discount rate and do not purport to present the fair market value of the Company’s proved gas, oil and NGL reserves:
(in millions)202020192018
Future cash inflows$17,997 $27,003 $34,523 
Future production costs(11,969)(14,981)(15,347)
Future development costs (1)
(1,924)(3,246)(4,095)
Future income tax expense— (476)(2,079)
Future net cash flows4,104 8,300 13,002 
10% annual discount for estimated timing of cash flows(2,257)(4,600)(7,003)
Standardized measure of discounted future net cash flows$1,847 $3,700 $5,999 
(1)Includes abandonment costs.
Under the standardized measure, future cash inflows were estimated by applying an average price from the first day of each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of year-end proved reserves.  Prices used for the standardized measure above were as follows:
(in millions)202020192018
Natural gas (per MMBtu)
$1.98 $2.58 $3.10 
Oil (per Bbl)
39.57 55.69 65.56 
NGLs (per Bbl)
10.27 11.58 17.64 
Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties after giving effect to permanent differences and tax credits.
Following is an analysis of changes in the standardized measure during 2020, 2019 and 2018:
(in millions)202020192018
Standardized measure, beginning of year$3,700 $5,999 $5,562 
Sales and transfers of natural gas and oil produced, net of production costs(478)(923)(1,564)
Net changes in prices and production costs(2,720)(3,510)2,162 
Extensions, discoveries, and other additions, net of future production and development costs81 234 335 
Acquisition of reserves in place443 — — 
Sales of reserves in place— (2)(2,022)
Revisions of previous quantity estimates(987)152 361 
Net change in income taxes35 491 (304)
Changes in estimated future development costs1,241 621 (166)
Previously estimated development costs incurred during the year624 704 536 
Changes in production rates (timing) and other(466)(718)521 
Accretion of discount374 652 578 
Standardized measure, end of year$1,847 $3,700 $5,999