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, 2017 and 2016:


(in millions)	2017		2016
Proved properties	$	22,073	$	20,548
Unproved properties		1,817		2,105
Total capitalized costs		23,890		22,653
Less: Accumulated depreciation, depletion and amortization		(19,287)		(18,897)
Net capitalized costs	$	4,603	$	3,756

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, 2017:


(in millions)	2017		2016		2015		Prior		Total
Property acquisition costs	$	80	$	18	$	145	$	1,295	$	1,538
Exploration and development costs		67		7		32		14		120
Capitalized interest		67		41		33		18		159
	$	214	$	66	$	210	$	1,327	$	1,817

Of the total net unevaluated costs excluded from amortization as of December 31, 2017, approximately $1.5 billion is related to the acquisition of undeveloped properties in Southwest Appalachia, approximately $90 million is related to the acquisition of the Company’s undeveloped properties in Northeast Appalachia and approximately $16 million is related to the acquisition of undeveloped properties outside the Appalachian Basin and the Fayetteville Shale. Additionally, the Company has approximately $159 million of unevaluated capitalized interest and $88 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)	2017		2016		2015
Proved property acquisition costs	$	–	$	–	$	81
Unproved property acquisition costs		194		171		692
Exploration costs		22		17		50
Development costs		1,024		433		1,417
Capitalized costs incurred		1,240		621		2,240
Full cost pool amortization per Mcfe	$	0.45	$	0.38	$	1.00

Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $113 million, $152 million and $204 million during 2017, 2016 and 2015, 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 $99 million, $87 million and $175 million during 2017, 2016 and 2015, 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)	2017		2016		2015
Sales	$	2,086	$	1,413	$	2,074
Production (lifting) costs		(891)		(839)		(989)
Depreciation, depletion and amortization		(440)		(371)		(1,028)
Impairment of natural gas and oil properties		–		(2,321)		(6,950)
		755		(2,118)		(6,893)
Provision (benefit) for income taxes (1)		–		–		(2,619)
Results of operations (2)	$	755	$	(2,118)	$	(4,274)

(1)

Prior to the recognition of a valuation allowance, in 2017 and 2016 the Company recognized income tax provisions of $287 million and $805 million, respectively.

(2)

Results of operations exclude the gain (loss) on unsettled commodity derivative instruments. See Note 4 - Derivatives and Risk Management

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%, 99% and 100% of the present worth of the Company’s total proved reserves as of December 31, 2017, 2016 and 2015, respectively. 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 2017, 2016 and 2015, all of which were located in the United States:


	Natural
	Gas	Oil	NGL	Total
	(Bcf)	(MBbls)	(MBbls)	(Bcfe)
December 31, 2014	9,809	37,615	118,699	10,747
Revisions of previous estimates (1)	(3,458)	(28,394)	(75,664)	(4,083)
Extensions, discoveries and other additions	546	1,367	6,274	592
Production	(899)	(2,265)	(10,702)	(976)
Acquisition of reserves in place	97	525	2,340	115
Disposition of reserves in place	(178)	(95)	–	(180)
December 31, 2015	5,917	8,753	40,947	6,215
Revisions of previous estimates	(446)	1,564	13,794	(354)
Extensions, discoveries and other additions	198	2,417	11,576	282
Production	(788)	(2,192)	(12,372)	(875)
Acquisition of reserves in place	–	–	–	–
Disposition of reserves in place	(15)	(19)	(14)	(15)
December 31, 2016	4,866	10,523	53,931	5,253
Revisions of previous estimates	1,898	1,668	70,549	2,332
Extensions, discoveries and other additions (2)	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

(1)

The significant revisions of previous estimates in 2015 was primarily due to price revision, as a result of lower average commodity prices in 2015.

(2)

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


	Natural
	Gas	Oil	NGL	Total
	(Bcf)	(MBbls)	(MBbls)	(Bcfe)
Proved developed reserves as of:
December 31, 2015	5,474	8,753	40,947	5,772
December 31, 2016	4,789	10,523	53,931	5,176
December 31, 2017	6,979	14,513	142,213	7,920
Proved undeveloped reserves as of:
December 31, 2015	443	–	–	443
December 31, 2016	77	–	–	77
December 31, 2017	4,147	51,123	400,242	6,855

The Company’s estimated proved natural gas, oil and NGL reserves were 14,775 Bcfe at December 31, 2017, compared to 5,253 Bcfe at December 31, 2016. The increase in the Company’s reserves in 2017, compared to 2016, primarily resulted through extensions, discoveries and other additions in the Appalachian Basin along with increases in both price and performance revisions across the portfolio. The decrease in the Company's reserves in 2016 was primarily due to the decrease in commodity prices. The significant decrease in the Company's reserves in 2015 was primarily due to the decrease in commodity prices.

The following table summarizes the changes in reserves for 2015, 2016 and 2017:


	Appalachia		Fayetteville
(in Bcfe)	Northeast	Southwest	Shale	Other (1)	Total
December 31, 2014	3,191	2,297	5,069	190	10,747
Net revisions
Price revisions	(2,315)	(1,875)	(1,496)	(32)	(5,718)
Performance and production revisions	1,383	209	10	33	1,635
Total net revisions	(932)	(1,666)	(1,486)	1	(4,083)
Extensions, discoveries and other additions
Proved developed	202	84	129	1	416
Proved undeveloped	138	4	34	–	176
Total reserve additions	340	88	163	1	592
Production	(360)	(143)	(465)	(8)	(976)
Acquisition of reserves in place	80	35	–	–	115
Disposition of reserves in place	–	–	–	(180)	(180)
December 31, 2015	2,319	611	3,281	4	6,215
Net revisions
Price revisions	(794)	(127)	(116)	–	(1,037)
Performance and production revisions	318	199	163	3	683
Total net revisions	(476)	72	47	3	(354)
Extensions, discoveries and other additions
Proved developed	81	157	19	–	257
Proved undeveloped	–	–	25	–	25
Total reserve additions	81	157	44	–	282
Production	(350)	(148)	(375)	(2)	(875)
Acquisition of reserves in place	–	–	–	–	–
Disposition of reserves in place	–	(15)	–	–	(15)
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

(1)

Other includes properties outside of the Appalachian Basin and Fayetteville Shale along with Ark-La-Tex properties divested in May 2015.

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 do not have a positive present value when discounted at 10%. These properties had a negative present value of $124 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, 2016 proved reserves included 77 Bcfe of proved undeveloped reserves from 15 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $11 million present value when discounted at 10%. The Company's December 31, 2015 proved reserves included 217 Bcfe of proved undeveloped reserves from 75 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $34 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, 2017, 2016 and 2015 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)	2017		2016		2015
Future cash inflows	$	36,576	$	9,064	$	11,887
Future production costs		(18,390)		(5,880)		(7,376)
Future development costs (1)		(4,676)		(485)		(792)
Future income tax expense (2)		(1,342)		–		–
Future net cash flows		12,168		2,699		3,719
10% annual discount for estimated timing of cash flows		(6,606)		(1,034)		(1,302)
Standardized measure of discounted future net cash flows	$	5,562	$	1,665	$	2,417

(1)

Includes abandonment costs.

(2)

The December 31, 2016 and 2015 standardized measure computation does not have future income taxes because the Company’s tax basis in the associated oil and gas properties exceeded expected pre-tax cash inflows. Future net cash flows are not permitted to be increased by excess tax basis.

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:

	2017		2016		2015
Natural gas (per MMBtu)	$	2.98	$	2.48	$	2.59
Oil (per Bbl)	$	47.79	$	39.25	$	46.79
NGLs (per Bbl)	$	14.41	$	6.74	$	6.82

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 2017, 2016 and 2015:


(in millions)	2017		2016		2015
Standardized measure, beginning of year	$	1,665	$	2,417	$	7,543
Sales and transfers of natural gas and oil produced, net of production costs		(1,191)		(574)		(1,082)
Net changes in prices and production costs		1,963		(415)		(8,075)
Extensions, discoveries, and other additions, net of future production and development costs		1,715		45		162
Acquisition of reserves in place		–		–		28
Sales of reserves in place		–		(10)		(244)
Revisions of previous quantity estimates		1,721		(140)		(1,385)
Net change in income taxes		(222)		–		1,915
Changes in estimated future development costs		(6)		71		2,007
Previously estimated development costs incurred during the year		55		114		875
Changes in production rates (timing) and other		(304)		(85)		(273)
Accretion of discount		166		242		946
Standardized measure, end of year	$	5,562	$	1,665	$	2,417