Natural Gas Producing Activities (Unaudited)

12 Months Ended

Dec. 31, 2019

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Natural Gas Producing Activities (Unaudited)

Natural Gas Producing Activities (Unaudited)

The following supplementary information summarized presents the results of natural gas and oil activities in accordance with the successful efforts method of accounting for production activities.

Production Costs

The following tables present total aggregate capitalized costs and costs incurred related to natural gas, NGLs and oil production activities.

	Years Ended December 31,
	2019		2018		2017
	(Thousands)
Capitalized costs
Proved properties	$	17,994,820	$	17,648,731	$	18,920,855
Unproved properties	3,322,014		4,166,048		5,016,299
Total capitalized costs	21,316,834		21,814,779		23,937,154
Less: Accumulated depreciation and depletion	5,402,515		4,666,212		5,121,646
Net capitalized costs	$	15,914,319	$	17,148,567	$	18,815,508

	Years Ended December 31,
	2019		2018		2017
	(Thousands)
Costs incurred (a)
Property acquisition:
Proved properties (b)	$	40,316	$	77,099	$	5,251,711
Unproved properties (c)	154,128		198,854		3,310,995
Exploration (d)	7,223		1,708		15,505
Development	1,560,346		2,443,980		1,357,165

(a) Amounts exclude capital expenditures for facilities and information technology.

(b) Amounts in 2018 include $5.2 million and $9.2 million for the purchase of Marcellus and Utica wells, respectively, including the impact of measurement period adjustments for the 2017 acquisitions discussed in Note 8. Amounts in 2017 include $2,530.4 million and $1,192.0 million for the purchase of Marcellus wells and leases, respectively, acquired in the 2017 acquisitions discussed in Note 8, including the impact of measurement period adjustments for 2016 acquisitions. Amounts in 2017 also include $1,228.6 million and $0.3 million for the purchase of Utica wells and leases, respectively, acquired in the 2017 acquisitions discussed in Note 8.

(c) Amounts in 2017 include $2,625.1 million and $0.5 million for the purchase of Marcellus leases and Utica leases, respectively, acquired in the 2017 acquisitions discussed in Note 8.

(d) Amounts include capitalizable exploratory costs and exploration expense, excluding impairments.

Results of Operations for Producing Activities

The following table presents the results of operations related to natural gas, NGLs and oil production.

	Years Ended December 31,
	2019			2018			2017
	(Thousands)
Sales of natural gas, NGLs and oil	$	3,791,414		$	4,695,519		$	2,651,318
Transportation and processing	1,752,752			1,697,001			1,164,783
Production	153,785			195,775			181,349
Exploration	7,223			6,765			17,565
Depreciation and depletion	1,538,745			1,569,038			970,985
Impairment/loss on sale/exchange of long-lived assets	1,138,287			2,709,976			—
Impairment and expiration of leases	556,424			279,708			7,552
Income tax (benefit) expense	(340,843		)	(454,009		)	121,359
Results of operations from producing activities, excluding corporate overhead	$	(1,014,959	)	$	(1,308,735	)	$	187,725

Reserve Information

Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred.

The Company's estimate of proved natural gas, NGLs and crude oil reserves was prepared by Company engineers. The engineer primarily responsible for overseeing the preparation of the reserves estimate holds a bachelor's degree in chemical engineering from Michigan Technological University, a master's degree in chemical engineering from Colorado State University and an executive master of business administration in energy from the University of Oklahoma and has 19 years of experience in the oil and gas industry. To support the accurate and timely preparation and disclosure of its reserve estimates, the Company established internal controls over its reserve estimation processes and procedures, including the following: the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves are reviewed by management; division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems; the reserves reconciliation between prior year reserves and current year reserves is reviewed by senior management; and the estimates of proved natural gas, NGLs and crude oil reserves are audited by Ryder Scott Company, L.P. (Ryder Scott), an independent consulting firm hired by management. Since 1937, Ryder Scott has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally. There were no differences between the internally prepared and externally audited estimates.

In the course of its audit, Ryder Scott reviewed 100% of the total net natural gas, NGLs and oil proved reserves attributable to the Company's interests as of December 31, 2019. Ryder Scott conducted a detailed, well-by-well, audit of the Company's largest properties. For undeveloped locations, the Company determined, and Ryder Scott reviewed and approved, the areas within its acreage that the Company considered proven. Reserves were assigned and projected by the Company's reserve engineers for locations within these proven areas and approved by Ryder Scott based on offset production information and analogous type curves. In cases where historical production and pressure data was available and considered definitive, performance methods, including decline curve analysis, were used. Approximately 94% of the proved developed reserves attributable to producing wells or reserves that Ryder Scott reviewed were estimated using performance methods. The remaining 6% of those proved developed reserves were estimated by analogy, which calculates reserves based on correlation to comparable surrounding wells. All of the Company's proved reserves are located in the United States.

For all tables presented, NGLs and oil were converted at a rate of one Mbbl to approximately six million cubic feet (MMcf).

	Years Ended December 31,
	2019		2018		2017
	(MMcf)
Natural gas, NGLs and oil
Proved developed and undeveloped reserves:
Balance at January 1	21,816,776		21,445,667		13,508,407
Revision of previous estimates	(4,907,239	)	(1,124,904	)	(2,766,981	)
Purchase of hydrocarbons in place	—		—		9,389,638
Sale of hydrocarbons in place	—		(1,748,557	)	(2,646	)
Extensions, discoveries and other additions	2,067,753		4,739,233		2,225,141
Production	(1,507,896	)	(1,494,663	)	(907,892	)
Balance at December 31	17,469,394		21,816,776		21,445,667
Proved developed reserves:
Balance at January 1	11,550,161		11,297,956		6,842,958
Balance at December 31	12,443,987		11,550,161		11,297,956
Proved undeveloped reserves:
Balance at January 1	10,266,615		10,147,711		6,665,449
Balance at December 31	5,025,407		10,266,615		10,147,711

	Years Ended December 31,
	2019		2018		2017
	(MMcf)
Natural gas
Proved developed and undeveloped reserves:
Balance at January 1	20,805,452		19,830,236		12,331,867
Revision of previous estimates	(4,722,799	)	(960,285	)	(2,760,467	)
Purchase of natural gas in place	—		—		8,890,145
Sale of natural gas in place	—		(1,331,391	)	(1,210	)
Extensions, discoveries and other additions	2,029,683		4,659,835		2,164,578
Production	(1,435,134	)	(1,392,943	)	(794,677	)
Balance at December 31	16,677,202		20,805,452		19,830,236
Proved developed reserves:
Balance at January 1	10,887,953		10,152,543		6,074,958
Balance at December 31	11,811,521		10,887,953		10,152,543
Proved undeveloped reserves:
Balance at January 1	9,917,499		9,677,693		6,256,909
Balance at December 31	4,865,681		9,917,499		9,677,693

	Years Ended December 31,
	2019		2018		2017
	(Mbbl)
NGLs
Proved developed and undeveloped reserves:
Balance at January 1	162,395		258,507		189,695
Revision of previous estimates	(30,312	)	(33,653	)	(6,189	)
Purchase of NGLs in place	—		—		82,894
Sale of NGLs in place	—		(59,080	)	(100	)
Extensions, discoveries and other additions	6,177		12,895		10,084
Production	(11,305	)	(16,274	)	(17,877	)
Balance at December 31	126,955		162,395		258,507
Proved developed reserves:
Balance at January 1	106,879		180,170		121,605
Balance at December 31	100,945		106,879		180,170
Proved undeveloped reserves:
Balance at January 1	55,516		78,337		68,090
Balance at December 31	26,010		55,516		78,337

	Years Ended December 31,
	2019		2018		2017
	(Mbbl)
Oil
Proved developed and undeveloped reserves:
Balance at January 1	6,159		10,731		6,395
Revision of previous estimates	(428	)	6,217		5,103
Purchase of oil in place	—		—		355
Sale of oil in place	—		(10,447	)	(139	)
Extensions, discoveries and other additions	168		338		9
Production	(822	)	(680	)	(992	)
Balance at December 31	5,077		6,159		10,731
Proved developed reserves:
Balance at January 1	3,489		10,731		6,395
Balance at December 31	4,466		3,489		10,731
Proved undeveloped reserves:
Balance at January 1	2,670		—		—
Balance at December 31	611		2,670		—

The change in reserves during the year ended December 31, 2019 resulted from the following:

• Conversions into 2,646 Bcfe of proved undeveloped reserves to proved developed reserves.

• Extensions, discoveries and other additions of 2,068 Bcfe, which exceeded 2019 production of 1,508 Bcfe. Extensions, discoveries and other additions included an increase of 1,796 Bcfe from proved undeveloped additions associated with acreage that was previously unproved, but became proved due to 2019 reserve development that expanded the number of the Company's technically proven locations, implementation of, and alignment with, the Company's combo-development strategy and revisions to the Company's five-year drilling plan; 156 Bcfe from converting unproved reserves to proved developed reserves; and 116 Bcfe from extension of proved undeveloped reserves lateral lengths.

• Negative revisions of 4,508 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of implementation of the Company's combo-development strategy, which has refocused operations in the Company's core assets and driven execution of new development sequencing processes that emphasize productivity. While these efforts are expected to result in decreased well costs, they negatively impact proved undeveloped reserves as a result of (i) derecognizing previously-recorded proved undeveloped

reserves that are now outside the Company's substantially revised five-year capital allocation program for purposes of the Company's reserves calculations and (ii) executing new development sequencing processes that will result in increased probable-to-proved developed conversion.

The change in reserves during the year ended December 31, 2018 resulted from the following:

• Conversions into 2,722 Bcfe of proved undeveloped reserves to proved developed reserves.

• Extensions, discoveries and other additions of 4,739 Bcfe, which exceeded 2018 production of 1,495 Bcfe. Extensions, discoveries and other additions included an increase of 315 Bcfe from proved developed reserves extensions from reservoirs underlying acreage not previously booked as proved in the Company's Ohio, Pennsylvania and West Virginia Marcellus fields; 886 Bcfe from proved undeveloped reserves extensions from acreage proved by drilling activity in the Company's Ohio, Pennsylvania and West Virginia Marcellus fields; and 3,538 Bcfe from other proved undeveloped additions associated with acreage that was excluded from prior year proved reserves bookings, but subsequently became proved due to inclusion within the Company's five-year drilling plan.

• Negative revisions of 1,273 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of changes in the Company's future development plans to focus more heavily on developing the Company's core Pennsylvania assets.

• Upward revisions of 148 Bcfe from proved developed locations, due primarily to increased reserves from producing wells and improved commodity prices.

• Sale of hydrocarbons in place of 1,749 Bcfe due to the 2018 Divestitures described in Note 7.

The change in reserves during the year ended December 31, 2017 resulted from the following:

• Conversions into 987 Bcfe of proved undeveloped reserves to proved developed reserves.

• Increase of 3,330 Bcfe and 6,060 Bcfe associated with the acquisition of proved developed reserves and proved undeveloped reserves, respectively, in the Marcellus, Upper Devonian and Utica plays.

• Extensions, discoveries and other additions of 2,225 Bcfe, which exceeded the 2017 production of 908 Bcfe. Extensions, discoveries and other additions included an increase of 300 Bcfe from proved developed reserves extensions from reservoirs underlying acreage not previously booked as proved in the Company's Ohio, Pennsylvania and West Virginia Marcellus fields; 893 Bcfe from proved undeveloped reserves extensions from acreage proved by drilling activity in the Company's Ohio, Pennsylvania and West Virginia Marcellus fields; and 1,032 Bcfe from other proved undeveloped additions associated with acreage that was excluded from prior year proved reserves bookings, but subsequently became proved due to inclusion within the Company's five-year drilling plan.

• Negative revisions of 3,522 Bcfe from proved undeveloped locations, of which 3,074 Bcfe was from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of the Company's acquisition of new acreage.

• Upward revisions of 477 Bcfe from proved developed locations, due primarily to increased reserves from producing wells.

• Upward revisions of 278 Bcfe associated with previously booked locations whose economic lives had been extended due to improved commodity prices.

Standard Measure of Discounted Future Cash Flow

Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.

The following table summarizes estimated future net cash flows from natural gas and crude oil reserves.

	December 31,
	2019			2018			2017
	(Thousands)
Future cash inflows (a)	$	42,499,686		$	60,603,624		$	51,423,920
Future production costs (b)	(19,114,076		)	(20,463,567		)	(18,379,892		)
Future development costs	(2,617,731		)	(5,854,503		)	(5,637,676		)
Future income tax expenses	(3,013,667		)	(6,823,621		)	(5,811,125		)
Future net cash flow	17,754,212			27,461,933			21,595,227
10% annual discount for estimated timing of cash flows	(9,261,539		)	(15,850,035		)	(12,593,293		)
Standardized measure of discounted future net cash flows	$	8,492,673		$	11,611,898		$	9,001,934

(a) The majority of the Company's production is sold through liquid trading points on interstate pipelines.

For 2019, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $55.69 per Bbl for WTI less regional adjustments of $14.26 per Bbl, or $41.43 per Bbl, and $2.58 per MMBtu for NYMEX less regional adjustments of $0.29 per MMBtu, or $2.41 per Mcf. Regional adjustments were calculated using historical average realized prices received by the Company in the Appalachian Basin. For 2019, NGL pricing using average first-day-of-the-month closing prices for the prior twelve months for NGL components, adjusted using the regional component makeup of proved NGLs, resulted in a price of $16.81 per Bbl.

For 2018, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $65.56 per Bbl for WTI less regional adjustments, $2.888 per Dth for Columbia Gas Transmission Corp., $2.568 per Dth for Dominion Transmission, Inc., $2.587 per Dth for Texas Eastern Transmission Corp., $2.320 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company and $2.939 per Dth for the Rockies Express Pipeline Zone 3. For 2018, NGL pricing using average first-day-of-the-month closing prices for the prior twelve months for NGL components, adjusted using the regional component makeup of produced NGLs, resulted in prices of $21.93 per Bbl from certain West Virginia Marcellus reserves and $33.89 per Bbl from Ohio Utica reserves.

For 2017, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $51.34 per Bbl for WTI less regional adjustments, $2.801 per Dth for Columbia Gas Transmission Corp., $2.100 per Dth for Dominion Transmission, Inc., $2.914 per Dth for the East Tennessee Natural Gas Pipeline, $2.058 per Dth for Texas Eastern Transmission Corp., $1.995 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $2.321 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.665 per Dth for Waha and $2.840 per Dth for the Rockies Express Pipeline Zone 3. For 2017, NGL pricing using average first-day-of-the-month closing prices for the prior twelve months for NGL components, adjusted using the regional component makeup of produced NGLs, resulted in prices of $23.07 per Bbl from certain West Virginia Marcellus reserves, $31.11 per Bbl from certain Kentucky reserves, $29.47 per Bbl from Ohio Utica reserves and $27.93 per Bbl from Permian reserves.

(b) Includes approximately $1,186 million, $883 million and $1,400 million for future plugging and abandonment costs as of December 31, 2019, 2018 and 2017, respectively.

Holding production and development costs constant, a change in price of $0.10 per Dth for natural gas, $10 per barrel for NGLs and $10 per barrel for oil would result in a change in the December 31, 2019 discounted future net cash flows before income taxes of the Company's proved reserves of approximately $809 million, $163 million and $24 million, respectively.

The following table summarizes the changes in the standardized measure of discounted future net cash flows.    

	Years Ended December 31,
	2019			2018			2017
	(Thousands)
Net sales and transfers of natural gas and oil produced	$	(1,884,877	)	$	(2,802,742	)	$	(1,305,186	)
Net changes in prices, production and development costs	(3,502,434		)	2,949,606			2,236,183
Extensions, discoveries and improved recovery, net of related costs	870,504			1,616,653			1,269,712
Development costs incurred	1,002,389			1,630,506			712,635
Net purchase of minerals in place	—			—			5,357,921
Net sale of minerals in place	—			(849,162		)	(284		)
Revisions of previous quantity estimates	(2,080,040		)	(811,576		)	(297,437		)
Accretion of discount	900,004			834,026			115,437
Net change in income taxes	1,444,368			(289,549		)	(1,477,603		)
Timing and other (a)	130,861			332,202			1,401,802
Net (decrease) increase	(3,119,225		)	2,609,964			8,013,180
Balance at January 1	11,611,898			9,001,934			988,754
Balance at December 31	$	8,492,673		$	11,611,898		$	9,001,934

(a)

Timing and other for the year ended December 31, 2017 was primarily driven by timing changes to the Company's development plan as a result of the Rice Merger described in Note 8.