Natural Gas Producing Activities (Unaudited)

The supplementary information summarized below 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 the total aggregate capitalized costs and the costs incurred relating to natural gas, NGLs and oil production activities (a):



	For the Years Ended December 31,
	2018		2017		2016
	(Thousands)
At December 31:
Capitalized Costs:
Proved properties	$	17,648,731	$	18,920,855	$	12,179,833
Unproved properties	4,166,048		5,016,299		1,698,826
Total capitalized costs	21,814,779		23,937,154		13,878,659
Accumulated depreciation and depletion	4,666,212		5,121,646		4,217,154
Net capitalized costs	$	17,148,567	$	18,815,508	$	9,661,505



	For the Years Ended December 31,
	2018		2017		2016
	(Thousands)
Costs incurred: (a)
Property acquisition:
Proved properties (b)	$	77,099	$	5,251,711	$	403,314
Unproved properties (c)	198,854		3,310,995		880,545
Exploration (d)	1,708		15,505		6,047
Development	2,443,980		1,357,165		777,787
Geological and geophysical	—		—		—


(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, which includes the impact of measurement period adjustments for the 2017 acquisitions discussed in Note 3 and 7. 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 transactions discussed in Notes 3 and 7. The purchase of Marcellus leases includes measurement period adjustments to the 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 transactions discussed in Notes 3 and 7. Amounts in 2016 include $256.2 million and $112.2 million for the purchase of Marcellus wells and leases, respectively, acquired in the 2016 transactions discussed in Note 7.


(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 transactions discussed in Notes 3 and 7. Amounts in 2016 include $770.4 million for the purchase of Marcellus leases acquired in the 2016 transactions discussed in Note 7.


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

Capitalized costs of unproved oil and gas properties are evaluated at least annually for recoverability on a prospective basis. Indicators of potential impairment include changes brought about by economic factors, potential shifts in business strategy employed by management and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches if drilling activity has not commenced. If it is determined that the Company does not intend to drill on the property prior to expiration or does not have the intent and ability to extend, renew, trade, or sell the lease prior to expiration, an impairment expense is recorded. Expense for lease expirations that were not previously impaired are recorded as the leases expire. For the years ended December 31, 2018, 2017 and 2016, the Company recorded $279.7 million, $7.6 million and $15.7 million, respectively for lease impairments and expirations. The Company’s unproved properties had a net book value of $4,166.0 million and $5,016.3 million at December 31, 2018 and 2017, respectively.

Results of Operations for Producing Activities

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



	For the Years Ended December 31,
	2018			2017		2016
	(Thousands)
Revenues	$	4,695,519		$	2,651,318	$	1,594,997
Transportation and processing	1,697,001			1,164,783		880,191
Production	195,775			181,349		174,170
Exploration	6,765			17,565		4,663
Depreciation and depletion	1,569,038			970,985		856,451
Impairment of long-lived assets	2,709,976			—		—
Lease impairments and expirations	279,708			7,552		15,686
Income tax (benefit) expense	(454,009		)	121,359		(135,029		)
Results of operations from producing activities (excluding corporate overhead)	$	(1,308,735	)	$	187,725	$	(201,135	)

Reserve Information

The information presented below represents estimates of proved natural gas, NGLs and oil reserves prepared by Company engineers. The engineer primarily responsible for preparing the reserve report and the technical aspects of the reserves audit received a bachelor’s degree in Chemical Engineering from the Pennsylvania State University and has 21 years of experience in the oil and gas industry. To ensure that the reserves are materially accurate, management reviews the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves; division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems; the reserve reconciliation between prior year reserves and current year reserves is reviewed by senior management; and the estimates of proved natural gas, NGLs and oil reserves are audited by the independent consulting firm of Ryder Scott Company, L.P. (Ryder Scott), which is hired by the Company’s management. Since 1937, Ryder Scott has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.

Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. There were no differences between the internally prepared and externally audited estimates. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred. 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, 2018. Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties. This audit covered 81% of the Company’s proved developed reserves. Ryder Scott’s audit of the remaining 19% of the Company’s proved developed properties consisted of an audit of aggregated groups not exceeding 200 wells per case for operated wells and 115 wells per case for non-operated wells. For undeveloped locations, the Company determined, and Ryder Scott reviewed and approved, the areas within the Company’s acreage considered to be 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 analogous type curves and offset production information. The audit utilized the performance method and the analogy method. Where historical reserve or production data was definitive, the performance method, which extrapolates historical data, was utilized. In other cases the analogy method, which calculates reserves based on correlations to comparable surrounding wells, was utilized. All of the Company’s proved reserves are located in the United States.



	Years Ended December 31,
	2018		2017		2016
	(Millions of Cubic Feet)
Total - Natural Gas, Oil, and NGLs (a)
Proved developed and undeveloped reserves:
Beginning of year	21,445,667		13,508,407		9,976,597
Revision of previous estimates	(1,124,904	)	(2,766,981	)	(472,285	)
Purchase of hydrocarbons in place	—		9,389,638		2,395,776
Sale of hydrocarbons in place	(1,748,557	)	(2,646	)	—
Extensions, discoveries and other additions	4,739,233		2,225,141		2,384,682
Production	(1,494,663	)	(907,892	)	(776,363	)
End of year	21,816,776		21,445,667		13,508,407
Proved developed reserves:
Beginning of year	11,297,956		6,842,958		6,279,557
End of year	11,550,161		11,297,956		6,842,958
Proved undeveloped reserves:
Beginning of year	10,147,711		6,665,449		3,697,040
End of year	10,266,615		10,147,711		6,665,449

(a) Oil and NGLs were converted at the rate of one thousand Bbl equal to approximately 6 million cubic feet (MMcf).



	Years Ended December 31,
	2018		2017		2016
	(Millions of Cubic Feet)
Natural Gas
Proved developed and undeveloped reserves:
Beginning of year	19,830,236		12,331,867		9,110,311
Revision of previous estimates	(960,285	)	(2,760,467	)	(607,171	)
Purchase of natural gas in place	—		8,890,145		2,288,166
Sale of natural gas in place	(1,331,391	)	(1,210	)	—
Extensions, discoveries and other additions	4,659,835		2,164,578		2,241,528
Production	(1,392,943	)	(794,677	)	(700,967	)
End of year	20,805,452		19,830,236		12,331,867
Proved developed reserves:
Beginning of year	10,152,543		6,074,958		5,652,989
End of year	10,887,953		10,152,543		6,074,958
Proved undeveloped reserves:
Beginning of year	9,677,693		6,256,909		3,457,322
End of year	9,917,499		9,677,693		6,256,909



	Years Ended December 31,
	2018		2017		2016
	(Thousands of Bbls)
Oil (a)
Proved developed and undeveloped reserves:
Beginning of year	10,731		6,395		5,900
Revision of previous estimates	6,217		5,103		1,159
Purchase of oil in place	—		355		3
Sale of oil in place	(10,447	)	(139	)	—
Extensions, discoveries and other additions	338		9		62
Production	(680	)	(992	)	(729	)
End of year	6,159		10,731		6,395
Proved developed reserves:
Beginning of year	10,731		6,395		5,900
End of year	3,489		10,731		6,395
Proved undeveloped reserves:
Beginning of year	—		—		—
End of year	2,670		—		—

(a) One thousand Bbl equals approximately 6 million cubic feet (MMcf).



	Years Ended December 31,
	2018		2017		2016
	(Thousands of Bbls)
NGLs (a)
Proved developed and undeveloped reserves:
Beginning of year	258,507		189,695		138,481
Revision of previous estimates	(33,653	)	(6,189	)	21,322
Purchase of NGLs in place	—		82,894		17,932
Sale of NGLs in place	(59,080	)	(100	)	—
Extensions, discoveries and other additions	12,895		10,084		23,797
Production	(16,274	)	(17,877	)	(11,837	)
End of year	162,395		258,507		189,695
Proved developed reserves:
Beginning of year	180,170		121,605		98,528
End of year	106,879		180,170		121,605
Proved undeveloped reserves:
Beginning of year	78,337		68,090		39,953
End of year	55,516		78,337		68,090

(a) One thousand Bbl equals approximately 6 million cubic feet (MMcf).

2018 Changes in Reserves


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


•	Extensions, discoveries and other additions of 4,739 Bcfe, which exceeded the 2018 production of 1,495 Bcfe.


◦	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.


◦	Increase of 886 Bcfe from proved undeveloped reserves extensions from acreage proved by drilling activity in the Company’s Ohio, Pennsylvania and West Virginia Marcellus fields.


◦	Increase of 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, resulting from 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 primarily due to increased reserves from producing wells and improved commodity prices.


•	The sale of hydrocarbons in place of 1,749 Bcfe is due to the 2018 Divestitures as described in Note 8.

2017 Changes in Reserves


•	Transfer of 987 Bcfe of proved undeveloped reserves to proved developed reserves.


•	Increase of 9,390 Bcfe associated with the acquisition of proved developed reserves (3,330 Bcfe) and proved undeveloped reserves (6,060 Bcfe) in the Company’s Marcellus, Upper Devonian and Utica plays.


•	Extensions, discoveries and other additions of 2,225 Bcfe, which exceeded the 2017 production of 908 Bcfe.


◦	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.


◦	Increase of 893 Bcfe from proved undeveloped reserves extensions from acreage proved by drilling activity in the Company’s Ohio, Pennsylvania and West Virginia Marcellus fields.


◦	Increase of 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, primarily due to 3,074 Bcfe from locations that are no longer anticipated to be drilled within 5 years of booking as a result of acquiring new acreage. The acquired acreage presents opportunities to drill considerably longer laterals, realize operational efficiencies and improve overall returns.


•	Upward revisions of 477 Bcfe from proved developed locations, primarily due 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.

2016 Changes in Reserves


•	Transfer of 647 Bcfe of proved undeveloped reserves to proved developed reserves.


•	Increase of 2,396 Bcfe associated with the acquisition of proved developed reserves (320 Bcfe) and proved undeveloped reserves (2,076 Bcfe) in the Company’s Marcellus and Upper Devonian plays.


•	Extensions, discoveries and other additions of 2,385 Bcfe, which exceeded the 2016 production of 776 Bcfe.


◦	Increase of 341 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.


◦	Increase of 673 Bcfe from proved undeveloped reserves extensions from acreage proved by drilling activity in the Company’s Ohio, Pennsylvania and West Virginia Marcellus fields.


◦	Increase of 1,371 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 509 Bcfe from proved undeveloped locations, primarily due to 389 Bcfe from economic locations that the Company no longer expects to develop within 5 years of booking, along with the removal of locations that are no longer economic as determined in accordance with Securities and Exchange Commission (SEC) pricing requirements.


•	Upward revisions of 68 Bcfe from proved developed locations, primarily due to increased reserves from producing wells.


•	Negative revisions of 31 Bcfe associated with previously booked locations whose economic lives had been shortened due to reduced 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 estimated future net cash flows from natural gas and oil reserves as of December 31, 2018 and 2017 includes the impact of the Tax Cuts and Jobs Act, which resulted in a lower federal income tax rate than as of December 31, 2016.

Estimated future net cash flows from natural gas and oil reserves are as follows at December 31:



	2018			2017			2016
	(Thousands)
Future cash inflows (a)	$	60,603,624		$	51,423,920		$	24,011,281
Future production costs (b)	(20,463,567		)	(18,379,892		)	(14,864,126		)
Future development costs	(5,854,503		)	(5,637,676		)	(3,778,698		)
Future income tax expenses	(6,823,621		)	(5,811,125		)	(1,753,067		)
Future net cash flow	27,461,933			21,595,227			3,615,390
10% annual discount for estimated timing of cash flows	(15,850,035		)	(12,593,293		)	(2,626,636		)
Standardized measure of discounted future net cash flows	$	11,611,898		$	9,001,934		$	988,754



(a)	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2018, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2018 of $65.56 per Bbl of oil (first day of each month closing price for West Texas Intermediate (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 arithmetic averages of the closing prices on the first day of each month during 2018 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $21.93 per Bbl of NGLs for certain West Virginia Marcellus reserves and $33.89 per Bbl of NGLs per Bbl for Ohio Utica reserves.

	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2017, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2017 of $51.34 per Bbl of oil (first day of each month closing price for West Texas Intermediate (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 arithmetic averages of the closing prices on the first day of each month during 2017 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $23.07 per Bbl of NGLs from certain West Virginia Marcellus reserves, $31.11 per Bbl of NGLs from certain Kentucky reserves, $29.47 per Bbl for Ohio Utica reserves, and $27.93 per Bbl for Permian reserves.

	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2016, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2016 of $42.75 per Bbl of oil (first day of each month closing price for WTI) less regional adjustments, $2.342 per Dth for Columbia Gas Transmission Corp., $1.348 per Dth for Dominion Transmission, Inc., $2.334 per Dth for the East Tennessee Natural Gas Pipeline, $1.325 per Dth for Texas Eastern Transmission Corp., $1.305 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $1.862 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.343 per Dth for Waha, and $2.402 per Dth for the Rockies Express Pipeline Zone 3. For 2016, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2016 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $13.87 per Bbl of NGLs from certain West Virginia Marcellus reserves, $17.27 per Bbl of NGLs from certain Kentucky reserves, $14.71 per Bbl for Ohio Utica reserves, and $18.91 per Bbl for Permian reserves.

(b)	Includes approximately $883 million, $1,400 million and $790 million as of December 31, 2018, 2017 and 2016 respectively for future plugging and abandonment costs.

Holding production and development costs constant, a change in price of $0.20 per Dth for natural gas, $10 per barrel for oil and $10 per barrel for NGLs would result in a change in the December 31, 2018 discounted future net cash flows before income taxes of the Company’s proved reserves of approximately $1.9 billion, $34.2 million and $665.7 million, respectively.

Summary of changes in the standardized measure of discounted future net cash flows for the years ended December 31:



	2018			2017			2016
	(Thousands)
Sales and transfers of natural gas and oil produced – net	$	(2,802,742	)	$	(1,305,186	)	$	(540,636	)
Net changes in prices, production and development costs	2,949,606			2,236,183			(1,129,026		)
Extensions, discoveries and improved recovery, less related costs	1,616,653			1,269,712			590,885
Development costs incurred	1,630,506			712,635			402,891
Purchase of minerals in place – net	—			5,357,921			592,078
Sale of minerals in place – net	(849,162		)	(284		)	—
Revisions of previous quantity estimates	(811,576		)	(297,437		)	(60,959		)
Accretion of discount	834,026			115,437			122,674
Net change in income taxes	(289,549		)	(1,477,603		)	(91,823		)
Timing and other (a)	332,202			1,401,802			125,116
Net increase (decrease)	2,609,964			8,013,180			11,200
Beginning of year	9,001,934			988,754			977,554
End of year	$	11,611,898		$	9,001,934		$	988,754


(a)	Increase in 2017 primarily driven by timing changes to the Company’s development plan as a result of the Rice Merger.