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Supplemental Oil and Gas Disclosures (Unaudited)
 12 Months Ended
Dec. 31, 2021
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, 2021 and 2020:
(in millions)20212020
Proved properties$31,400 $25,789 
Unproved properties2,231 1,472 
Total capitalized costs33,631 27,261 
Less:  Accumulated depreciation, depletion and amortization(23,884)(23,362)
Net capitalized costs$9,747 $3,899 
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, 2021:
(in millions)202120202019PriorTotal
Property acquisition costs$784 $85 $9 $1,079 $1,957 
Exploration and development costs28 9 7 10 54 
Capitalized interest75 48 36 61 220 
$887 $142 $52 $1,150 $2,231 
Of the total net unevaluated costs excluded from amortization as of December 31, 2021, approximately $1.1 billion is related to undeveloped properties in Appalachia which were acquired in 2014 and 2015, $117 million is related to Montage properties acquired in November 2020 and approximately $759 million is related to the acquisition of undeveloped properties in Haynesville which were acquired in September 2021 and December 2021.  Additionally, the Company has approximately $220 million of unevaluated capitalized interest and $51 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)202120202019
Unproved property acquisition costs$139 $124 
(1)
$162 
Exploration costs— — 2 
Development costs984 784 936 
Capitalized costs incurred$1,123 $908 $1,100 
Full cost pool amortization per Mcfe$0.42 $0.38 $0.56 
(1)Excluded $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 $97 million, $88 million and $109 million during 2021, 2020 and 2019, 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 $64 million, $56 million and $77 million during 2021, 2020 and 2019, 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)202120202019
Sales$4,640 $1,348 $1,703 
Production (lifting) costs(1,304)(866)(781)
Depreciation, depletion and amortization(537)(348)(462)
Impairment of natural gas and oil properties— (2,825)— 
2,799 (2,691)460 
Provision for income taxes (1)
— — 110 
Results of operations (2)
$2,799 $(2,691)$350 
(1)Prior to the recognition of a valuation allowance, in 2020 the Company recognized an income tax benefit of $624 million.
(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 99% of the present worth of the Company’s total proved reserves as of December 31, 2021. For 2020 and 2019, NSAI’s audit accounted for 97% and 99%, respectively, of the then-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 2019, 2020 and 2021, all of which were located in the United States:
Natural Gas
(Bcf)
Oil
(MBbls)
NGL
(MBbls)
Total
(Bcfe)
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 (1)
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 (2)
1,911 18,796 55,141 2,354 
Disposition of reserves in place — — — — 
December 31, 20209,181 58,024 410,151 11,990 
Revisions of previous estimates due to price (3)
501 1,414 (15,525)415 
Revisions of previous estimates other than price248 1,900 1,500 269 
Extensions, discoveries and other additions2,543 24,865 211,598 3,962 
Production(1,015)(6,610)(30,940)(1,240)
Acquisition of reserves in place (4)
5,750 247 180 5,753 
Disposition of reserves in place(1)(61)— (1)
December 31, 202117,207 79,779 576,964 21,148 
(1)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.
(2)The 2020 acquisition amounts are primarily associated with the Montage Merger.
(3)The 15,525 MBbl reduction in NGL volumes for 2021 is the result of changes to the Company’s five-year development plan and elections to retain ethane in the natural gas stream in line with ethane transportation contracts. This election is driven by commodity pricing, whereby higher natural gas pricing relative to ethane pricing creates a more economically favorable position.
(4)The 2021 acquisition amounts are primarily associated with the Indigo Merger and the GEPH Merger.
Natural Gas
(Bcf)
Oil
(MBbls)
NGL
(MBbls)
Total
(Bcfe)
Proved developed reserves as of:    
December 31, 20194,906 26,124 226,271 6,421 
December 31, 20206,342 33,563 276,548 8,203 
December 31, 20219,308 40,930 296,832 11,335 
Proved undeveloped reserves as of:    
December 31, 20193,724 46,801 382,490 6,300 
December 31, 20202,839 24,461 133,603 3,787 
December 31, 20217,899 38,849 280,132 9,813 
The Company’s estimated proved natural gas, oil and NGL reserves were 21,148 Bcfe at December 31, 2021, compared to 11,990 Bcfe at December 31, 2020.  The Company’s reserves increased in 2021, compared to 2020, as acquisitions, additions and positive price and performance revisions were only partially offset by production and disposition.
The Company’s reserves decreased in 2020, as 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 following table summarizes the changes in reserves for 2019, 2020 and 2021:
(in Bcfe)AppalachiaHaynesville
Other (1)
Total
December 31, 201811,920 — 1 11,921 
Net revisions
Price revisions(717)— — (717)
Performance and production revisions (2)
1,102 — — 1,102 
Total net revisions385 — — 385 
Extensions, discoveries and other additions
Proved developed191 — — 191 
Proved undeveloped1,004 — — 1,004 
Total reserve additions1,195 — — 1,195 
Production(778)— — (778)
Acquisition of reserves in place— — — — 
Disposition of reserves in place(2)— — (2)
December 31, 201912,720 — 1 12,721 
Net revisions
Price revisions(4,370)— — (4,370)
Performance and production revisions1,424 — — 1,424 
Total net revisions(2,946)— — (2,946)
Extensions, discoveries and other additions
Proved developed267 — — 267 
Proved undeveloped474 — — 474 
Total reserve additions741 — — 741 
Production(880)— — (880)
Acquisition of reserves in place2,354 — — 2,354 
Disposition of reserves in place— — — — 
December 31, 202011,989 — 1 11,990 
Net revisions
Price revisions415 — — 415 
Performance and production revisions270 — (1)269 
Total net revisions685 — (1)684 
Extensions, discoveries and other additions
Proved developed451 — — 451 
Proved undeveloped (3)
3,511 — — 3,511 
Total reserve additions3,962 — — 3,962 
Production(1,108)(132)— (1,240)
Acquisition of reserves in place— 5,753 — 5,753 
Disposition of reserves in place(1)— — (1)
December 31, 202115,527 5,621 — 21,148 
(1)Other includes properties outside of Appalachia and Haynesville.
(2)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.
(3)For the year ended December 31, 2021, net extensions, discoveries and other additions in proved undeveloped reserves of 3,511 Bcfe was comprised of 1,768 Bcfe resulting from the addition of new undeveloped locations throughout the year through the Company’s successful drilling program and 1,743 Bcfe which was attributable to undeveloped locations which were uneconomical under prior year SEC pricing (and therefore excluded from prior year reserves) but which have become economical under current SEC pricing.
As of December 31, 2021, the Company had no proved undeveloped reserves that had a negative present value on a 10% discounted basis.
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 that have a negative $207 million present value when discounted at 10%.  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 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 measure of discounted future net cash flows relating to proved natural gas, oil and NGL reserves as of December 31, 2021, 2020 and 2019 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)202120202019
Future cash inflows$75,314 $17,997 $27,003 
Future production costs(23,235)(11,969)(14,981)
Future development costs (1)
(6,032)(1,924)(3,246)
Future income tax expense(8,135)— (476)
Future net cash flows37,912 4,104 8,300 
10% annual discount for estimated timing of cash flows(19,181)(2,257)(4,600)
Standardized measure of discounted future net cash flows$18,731 $1,847 $3,700 
(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:
202120202019
Natural gas (per MMBtu)
$3.60 $1.98 $2.58 
Oil (per Bbl)
66.56 39.57 55.69 
NGLs (per Bbl)
28.65 10.27 11.58 
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 2021, 2020 and 2019:
(in millions)202120202019
Standardized measure, beginning of year$1,847 $3,700 $5,999 
Sales and transfers of natural gas and oil produced, net of production costs(3,332)(478)(923)
Net changes in prices and production costs10,417 (2,720)(3,510)
Extensions, discoveries, and other additions, net of future production and development costs3,183 81 234 
Acquisition of reserves in place6,499 443 — 
Sales of reserves in place(1)— (2)
Revisions of previous quantity estimates596 (987)152 
Net change in income taxes(3,689)35 491 
Changes in estimated future development costs137 1,241 621 
Previously estimated development costs incurred during the year419 624 704 
Changes in production rates (timing) and other2,470 (466)(718)
Accretion of discount185 374 652 
Standardized measure, end of year$18,731 $1,847 $3,700