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, 2016 and 2015:


	2016		2015
	(in millions)
Proved properties	$	20,548	$	18,751
Unproved properties		2,105		3,727
Total capitalized costs		22,653		22,478
Less: Accumulated depreciation, depletion and amortization		(18,897)		(16,248)
Net capitalized costs	$	3,756	$	6,230

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, 2016:


	2016		2015		2014		Prior		Total
	(in millions)
Property acquisition costs	$	22	$	213	$	1,501	$	54	$	1,790
Exploration and development costs		55		64		24		16		159
Capitalized interest		70		55		10		21		156
	$	147	$	332	$	1,535	$	91	$	2,105

Of the total net unevaluated costs excluded from amortization as of December 31, 2016, approximately $1.6 billion is related to the Chesapeake and Statoil Property Acquisitions, approximately $100 million is related to the acquisition of undeveloped properties outside the Appalachian Basin and the Fayetteville Shale, excluding licenses in Canada subject to an indefinite moratorium, and approximately $94 million is related to the acquisition of the Company’s undeveloped properties in Northeast Appalachia. Additionally, the Company has approximately $113 million of unevaluated costs related to costs of 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:


	2016		2015		2014
	(in millions, except per Mcfe amounts)
Proved property acquisition costs	$	–	$	81	$	1,455
Unproved property acquisition costs		171		692		3,934
Exploration costs		17		50		232
Development costs		433		1,417		1,600
Capitalized costs incurred		621		2,240		7,221
Full cost pool amortization per Mcfe	$	0.38	$	1.00	$	1.10

Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $152 million, $204 million and $55 million during 2016, 2015 and 2014, 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 $112 million, $307 million and $320 million during 2016, 2015 and 2014, respectively, which were directly related to the acquisition, exploration and development of the Company’s natural gas and oil properties. Included in these amounts are internal costs from the Company’s subsidiaries involved with vertical integration of the Company’s exploration and development activities, which totaled $19 million, $118 million and $123 million during 2016, 2015 and 2014, respectively. All internal costs are included in the Company’s cost of 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:


	2016			2015		2014
	(in millions)
Sales	$	1,413		$	2,074	$	2,862
Production (lifting) costs		(839)			(989)		(776)
Depreciation, depletion and amortization		(371)			(1,028)		(884)
Impairment of natural gas and oil properties		(2,321)			(6,950)		–
		(2,118)			(6,893)		1,202
Provision (benefit) for income taxes		–	(1)		(2,619)		457
Results of operations (2)	$	(2,118)		$	(4,274)	$	745

(1)

Prior to the Company’s recognition of a valuation allowance in 2016, the Company recognized an income tax benefit of $805 million.

(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%, 100% and 97% of the present worth of the Company’s total proved reserves as of December 31, 2016, 2015 and 2014, 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 2016, 2015 and 2014, all of which were located in the United States:


	2016			2015			2014
	Natural			Natural			Natural
	Gas	Oil	NGL	Gas	Oil	NGL	Gas	Oil	NGL
	(Bcf)	(MBbls)	(MBbls)	(Bcf)	(MBbls)	(MBbls)	(Bcf)	(MBbls)	(MBbls)
Proved reserves, beginning of year	5,917	8,753	40,947	9,809	37,615	118,699	6,974	373	–
Revisions of previous estimates	(446)	1,564	13,794	(3,458)	(28,394)	(75,664)	542	(14)	66
Extensions, discoveries and other additions	198	2,417	11,576	546	1,367	6,274	1,692	250	48
Production	(788)	(2,192)	(12,372)	(899)	(2,265)	(10,702)	(766)	(235)	(231)
Acquisition of reserves in place	–	–	–	97	525	2,340	1,367	37,246	118,816
Disposition of reserves in place	(15)	(19)	(14)	(178)	(95)	–	–	(5)	–
Proved reserves, end of year	4,866	10,523	53,931	5,917	8,753	40,947	9,809	37,615	118,699

Proved developed reserves:
Beginning of year	5,474	8,753	40,947	5,675	7,445	38,632	4,237	372	–
End of year	4,789	10,523	53,931	5,474	8,753	40,947	5,675	7,445	38,632

Proved undeveloped reserves:
Beginning of year	443	–	–	4,134	30,170	80,067	2,737	1	–
End of year	77	–	–	443	–	–	4,134	30,170	80,067

The Company’s estimated proved natural gas, oil and NGL reserves were 5,253 Bcfe at December 31, 2016, compared to 6,215 Bcfe at December 31, 2015. 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 significant increase in the Company's reserves in 2014 was primarily due to the acquisition of approximately 413,000 net acres in Southwest Appalachia, successful development drilling programs in the Fayetteville Shale and Northeast Appalachia and upward performance revisions in Northeast Appalachia. In 2014, the Company replaced 550% of its production volumes with proved reserve additions and proved reserve additions as a result of acquisitions primarily associated with acreage in Southwest Appalachia. The following table summarizes the changes in reserves for 2014, 2015 and 2016:


		Appalachia		Fayetteville
	Total	Northeast	Southwest	Shale	Other(1)
	(in Bcfe)
December 31, 2013	6,976	1,963	–	4,795	218
Production	(768)	(254)	(3)	(494)	(17)
Disposition of reserves in place	–	–	–	–	–
Acquisition of reserves in place	2,303	1	2,300	–	2
Net revisions
Price revisions	54	10	–	38	6
Performance and production revisions	489	636	–	(126)	(21)
Total net revisions	543	646	–	(88)	(15)
Reserve additions
Proved developed	531	246	–	283	2
Proved undeveloped	1,162	589	–	573	–
Total reserve additions	1,693	835	–	856	2
December 31, 2014	10,747	3,191	2,297	5,069	190
Production	(976)	(360)	(143)	(465)	(8)
Disposition of reserves in place	(180)	–	–	–	(180)
Acquisition of reserves in place	115	80	35	–	–
Net revisions
Price revisions	(5,718)	(2,315)	(1,875)	(1,496)	(32)
Performance and production revisions	1,635	1,383	209	10	33
Total net revisions	(4,083)	(932)	(1,666)	(1,486)	1
Reserve additions
Proved developed	416	202	84	129	1
Proved undeveloped	176	138	4	34	–
Total reserve additions	592	340	88	163	1
December 31, 2015	6,215	2,319	611	3,281	4
Production	(875)	(350)	(148)	(375)	(2)
Disposition of reserves in place	(15)	–	(15)	–	–
Acquisition of reserves in place	–	–	–	–	–
Net revisions
Price revisions	(1,037)	(794)	(127)	(116)	–
Performance and production revisions	683	318	199	163	3
Total net revisions	(354)	(476)	72	47	3
Reserve additions
Proved developed	257	81	157	19	–
Proved undeveloped	25	–	–	25	–
Total reserve additions	282	81	157	44	–
December 31, 2016	5,253	1,574	677	2,997	5

(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, 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 do not have a positive present value when discounted at 10%. These properties had a negative present value of $11 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, 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's December 31, 2014 proved reserves included 181 Bcfe of proved undeveloped reserves from 60 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $28 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, 2016, 2015 and 2014 are calculated after income taxes, discounted using a 10% annual discount rate and do not purport to present the fair market value the Company’s proved gas, oil and NGL reserves:


	2016		2015		2014
	(in millions)
Future cash inflows	$	9,064	$	11,887	$	41,812
Future production costs		(5,880)		(7,376)		(16,477)
Future development costs (1)		(485)		(792)		(5,750)
Future income tax expense (2)		–		–		(4,743)
Future net cash flows		2,699		3,719		14,842
10% annual discount for estimated timing of cash flows		(1,034)		(1,302)		(7,299)
Standardized measure of discounted future net cash flows	$	1,665	$	2,417	$	7,543

(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 $2.48 per MMBtu for natural gas, $39.25 per barrel for oil and $6.74 per barrel for NGLs in 2016, $2.59 per MMBtu for natural gas, $46.79 per barrel for oil and $6.82 per barrel for NGLs in 2015, and $4.35 per MMBtu for natural gas, $91.48 per barrel for oil and $23.79 per barrel for NGLs in 2014. 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 2016, 2015 and 2014:


	2016		2015		2014
	(in millions)
Standardized measure, beginning of year	$	2,417	$	7,543	$	3,736
Sales and transfers of natural gas and oil produced, net of production costs		(574)		(1,082)		(2,084)
Net changes in prices and production costs		(415)		(8,075)		1,192
Extensions, discoveries, and other additions, net of future production and development costs		45		162		1,049
Acquisition of reserves in place		–		28		1,897
Sales of reserves in place		(10)		(244)		–
Revisions of previous quantity estimates		(140)		(1,385)		622
Accretion of discount		242		946		513
Net change in income taxes		–		1,915		(522)
Changes in estimated future development costs		71		2,007		110
Previously estimated development costs incurred during the year		114		875		815
Changes in production rates (timing) and other		(85)		(273)		215
Standardized measure, end of year	$	1,665	$	2,417	$	7,543