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Supplemental Oil and Gas Disclosures

12 Months Ended

Dec. 31, 2019

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

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, 2019 and 2018:


(in millions)	2019		2018
Proved properties	$	23,744	$	22,425
Unproved properties	1,506		1,755
Total capitalized costs	25,250		24,180
Less: Accumulated depreciation, depletion and amortization	(20,203)		(19,761)
Net capitalized costs	$	5,047	$	4,419

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, 2019:


(in millions)	2019		2018		2017		Prior		Total
Property acquisition costs	$	45	$	40	$	32	$	1,106	$	1,223
Exploration and development costs	53		23		16		12		104
Capitalized interest	67		47		27		38		179
	$	165	$	110	$	75	$	1,156	$	1,506

Of the total net unevaluated costs excluded from amortization as of December 31, 2019, approximately $1.2 billion is related to undeveloped properties in Southwest Appalachia (acquired in 2014 and 2015) and approximately $10 million is related to the acquisition of undeveloped properties in Northeast Appalachia. Additionally, the Company has approximately $179 million of unevaluated capitalized interest and $95 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)	2019		2018		2017
Unproved property acquisition costs	$	162	$	164	$	194
Exploration costs	2		5		22
Development costs	936		1,014		1,024
Capitalized costs incurred	$	1,100	$	1,183	$	1,240
Full cost pool amortization per Mcfe	$	0.56	$	0.51	$	0.45

Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $109 million, $115 million and $113 million during 2019, 2018 and 2017, 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 $77 million, $90 million and $99 million during 2019, 2018 and 2017, 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)	2019		2018		2017
Sales	$	1,703	$	2,525	$	2,086
Production (lifting) costs	(781)		(974)		(891)
Depreciation, depletion and amortization	(462)		(514)		(440)

	460		1,037		755
Provision for income taxes ⁽¹⁾	110		—		—
Results of operations ⁽²⁾	$	350	$	1,037	$	755

(1)Prior to the recognition of a valuation allowance, in 2018 and 2017 the Company recognized income tax provisions of $254 million and $287 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 99% of the present worth of the Company’s total proved reserves as of December 31 of 2019, 2018 and 2017. 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. For more information over reserves, refer to the table titled “Changes in Proved Undeveloped Reserves (Bcfe)” in “Business – Exploration and Production” in Item 1 of this Annual Report.

The following table summarizes the changes in the Company’s proved natural gas, oil and NGL reserves for 2019, 2018 and 2017, all of which were located in the United States:໿


	Natural Gas (Bcf)	Oil (MBbls)	NGL (MBbls)	Total (Bcfe)
December 31, 2016	4,866	10,523	53,931	5,253
Revisions of previous estimates due to price	1,327	3,197	57,447	1,691
Revisions of previous estimates other than price	571	(1,529)	13,102	641
Extensions, discoveries and other additions ⁽¹⁾	5,159	55,772	432,220	8,087
Production	(797)	(2,327)	(14,245)	(897)
Acquisition of reserves in place	—	—	—	—
Disposition of reserves in place	—	—	—	—
December 31, 2017	11,126	65,636	542,455	14,775
Revisions of previous estimates due to price	96	788	8,912	154
Revisions of previous estimates other than price	316	410	8,855	372
Extensions, discoveries and other additions	753	5,830	36,823	1,009
Production	(807)	(3,407)	(19,706)	(946)
Acquisition of reserves in place	—	—	—	—
Disposition of reserves in place ⁽²⁾	(3,440)	(250)	(276)	(3,443)
December 31, 2018	8,044	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⁽³⁾	685	3,707	65,869	1,102
Extensions, discoveries and other additions	992	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, 2019	8,630	72,925	608,761	12,721

(1)The 2017 PUD additions are primarily associated with the increase in commodity prices.

(2)The 2018 disposition is primarily associated with the Fayetteville Shale sale.

(3)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.


	Natural Gas (Bcf)	Oil (MBbls)	NGL (MBbls)	Total (Bcfe)
Proved developed reserves as of:
December 31, 2017	6,979	14,513	142,213	7,920
December 31, 2018	4,395	18,037	175,480	5,557
December 31, 2019	4,906	26,124	226,271	6,421
Proved undeveloped reserves as of:
December 31, 2017	4,147	51,123	400,242	6,855
December 31, 2018	3,649	50,970	401,583	6,364
December 31, 2019	3,724	46,801	382,490	6,300

The Company’s estimated proved natural gas, oil and NGL reserves were 12,721 Bcfe at December 31, 2019, compared to 11,921 Bcfe at December 31, 2018. The Company’s reserves increased in 2019, compared to 2018, as positive extensions, discoveries, other additions and non-price 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 increase in the Company’s reserves in 2017 was primarily due to extensions, discoveries and other additions in Appalachia along with increases in both price and performance revisions across the portfolio.

The following table summarizes the changes in reserves for 2017, 2018 and 2019:໿


	Appalachia			Fayetteville
(in Bcfe)	Northeast	Southwest	Shale ⁽¹⁾	Other ⁽²⁾	Total
December 31, 2016	1,574	677	2,997	5	5,253
Net revisions
Price revisions	903	738	49	1	1,691
Performance and production revisions	154	125	358	4	641
Total net revisions	1,057	863	407	5	2,332
Extensions, discoveries and other additions
Proved developed	790	419	48	1	1,258
Proved undeveloped	1,100	5,186	543	—	6,829
Total reserve additions	1,890	5,605	591	1	8,087
Production	(395)	(183)	(316)	(3)	(897)
Acquisition of reserves in place	—	—	—	—	—
Disposition of reserves in place	—	—	—	—	—
December 31, 2017	4,126	6,962	3,679	8	14,775
Net revisions
Price revisions	41	106	6	1	154
Performance and production revisions	107	272	(6)	(1)	372
Total net revisions	148	378	—	—	526
Extensions, discoveries and other additions
Proved developed	154	22	1	—	177
Proved undeveloped	397	435	—	—	832
Total reserve additions	551	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, 2018	4,366	7,554	—	1	11,921
Net revisions
Price revisions	(57)	(660)	—	—	(717)
Performance and production revisions⁽³⁾	127	975	—	—	1,102
Total net revisions	70	315	—	—	385
Extensions, discoveries and other additions
Proved developed	185	6	—	—	191
Proved undeveloped	677	327	—	—	1,004
Total reserve additions	862	333	—	—	1,195
Production	(459)	(319)	—	—	(778)
Acquisition of reserves in place	—	—	—	—	—
Disposition of reserves in place	(2)	—	—	—	(2)
December 31, 2019	4,837	7,883	—	1	12,721

(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 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.

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 do not have a positive present value when discounted at 10%. These properties had a negative present value of $50 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, 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’s December 31, 2017 proved reserves included 1,375

Bcfe of proved undeveloped reserves from 330 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $124 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, 2019, 2018 and 2017 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)	2019		2018		2017
Future cash inflows	$	27,003	$	34,523	$	36,576
Future production costs	(14,981)		(15,347)		(18,390)
Future development costs ⁽¹⁾	(3,246)		(4,095)		(4,676)
Future income tax expense	(476)		(2,079)		(1,342)
Future net cash flows	8,300		13,002		12,168
10% annual discount for estimated timing of cash flows	(4,600)		(7,003)		(6,606)
Standardized measure of discounted future net cash flows	$	3,700	$	5,999	$	5,562

(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)	2019		2018		2017
Natural gas (per MMBtu)	$	2.58	$	3.10	$	2.98
Oil (per Bbl)	55.69		65.56		47.79
NGLs (per Bbl)	11.58		17.64		14.41

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 2019, 2018 and 2017:


(in millions)	2019		2018		2017
Standardized measure, beginning of year	$	5,999	$	5,562	$	1,665
Sales and transfers of natural gas and oil produced, net of production costs	(923)		(1,564)		(1,191)
Net changes in prices and production costs	(3,510)		2,162		1,963
Extensions, discoveries, and other additions, net of future production and development costs	234		335		1,715
Acquisition of reserves in place	—		—		—
Sales of reserves in place	(2)		(2,022)		—
Revisions of previous quantity estimates	152		361		1,721
Net change in income taxes	491		(304)		(222)
Changes in estimated future development costs	621		(166)		(6)
Previously estimated development costs incurred during the year	704		536		55
Changes in production rates (timing) and other	(718)		521		(304)
Accretion of discount	652		578		166
Standardized measure, end of year	$	3,700	$	5,999	$	5,562