Exploration and Production Activities (Unaudited)

Fidelity is involved in the development and production of oil and natural gas resources. Fidelity shares revenues and expenses from the development of specified properties in the Rocky Mountain and Mid-Continent/Gulf States regions of the United States in proportion to its ownership interests.

The information that follows includes Fidelity's proportionate share of all its oil and natural gas interests.

The following table sets forth capitalized costs and accumulated depreciation, depletion and amortization related to oil and natural gas producing activities at December 31:



	2014		2013		2012
	(In thousands)
Subject to amortization	$	3,205,036	$	2,893,010	$	2,531,562
Not subject to amortization	132,141		124,869		191,794
Total capitalized costs	3,337,177		3,017,879		2,723,356
Less accumulated depreciation, depletion and amortization	1,752,566		1,562,116		1,383,386
Net capitalized costs	$	1,584,611	$	1,455,763	$	1,339,970


Note:	Net capitalized costs reflect noncash write-downs of the Company's oil and natural gas properties, as discussed in Note 1.

Capital expenditures, including those not subject to amortization, related to oil and natural gas producing activities were as follows:



Years ended December 31,	2014		*	2013		*	2012		*
	(In thousands)
Acquisitions:
Proved properties	$	87,919		$	1,817		$	839
Unproved properties	138,683			4,608			31,109
Exploration	16,879			26,975			235,906
Development	331,400			355,421			275,959
Total capital expenditures	$	574,881		$	388,821		$	543,813


*	Excludes net additions/(reductions) to property, plant and equipment related to the recognition of future liabilities for asset retirement obligations associated with the plugging and abandonment of oil and natural gas wells, as discussed in Note 10, of $(9.0) million, $(10.7) million and $(200,000) for the years ended December 31, 2014, 2013 and 2012, respectively.

The preceding table excludes proceeds from the sales of oil and natural gas properties of $246.6 million, $83.6 million and $6.0 million for the years ended December 31, 2014, 2013 and 2012, respectively.

The following summary reflects income resulting from the Company's operations of oil and natural gas producing activities, excluding corporate overhead and financing costs:



Years ended December 31,	2014		2013			2012
			(In thousands)
Revenues:
Sales to affiliates	$	47,045	$	45,099		$	35,966
Sales to external customers	468,668		497,018			379,647
Realized gain on commodity derivatives	8,458		173			33,628
Unrealized gain (loss) on commodity derivatives	23,400		(6,267		)	(624		)
Production costs	146,793		144,136			134,795
Depreciation, depletion and amortization*	193,944		182,352			157,078
Write-downs of oil and natural gas properties	—		—			391,800
Pretax income (loss)	206,834		209,535			(235,056		)
Income tax expense (benefit)	75,483		75,836			(88,612		)
Results of operations for producing activities	$	131,351	$	133,699		$	(146,444	)

*Includes accretion of discount for asset retirement obligations of $3.5 million, $3.6 million and $3.3 million for the years ended December 31, 2014, 2013 and 2012, respectively, as discussed in Note 10.

Estimates of proved reserves were prepared in accordance with guidelines established by the industry and the SEC. The estimates are arrived at using actual historical wellhead production trends and/or standard reservoir engineering methods utilizing available geological, geophysical, engineering and economic data. The proved reserve estimates as of December 31, 2014, 2013 and 2012, were calculated using SEC Defined Prices. Other factors used in the proved reserve estimates are current estimates of well operating and future development costs (which include asset retirement costs), taxes, timing of operations, and the interests owned by the Company in the properties. These estimates are refined as new information becomes available.

The reserve estimates are prepared by internal engineers assigned to an asset team by geographic area. Senior management reviews and approves the reserve estimates to ensure they are materially accurate. In addition, the Company engaged Ryder Scott, an independent third party, to audit its proved reserve quantity estimates.

Estimates of economically recoverable oil, NGL and natural gas reserves and future net revenues therefrom are based upon a number of variable factors and assumptions. For these reasons, estimates of economically recoverable reserves and future net revenues may vary from actual results.

The Company's interests in oil, NGL and natural gas reserves are located in the United States and in and around the Gulf of Mexico.

The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2014, were as follows:



	Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed and undeveloped reserves:
Balance at beginning of year	41,019		6,602		198,445		80,695
Production	(4,919	)	(609	)	(20,822	)	(8,998	)
Extensions and discoveries	9,654		3,634		64,420		24,025
Improved recovery	—		—		—		—
Purchases of proved reserves	5,463		—		7,711		6,748
Sales of proved reserves	(4,945	)	(3,109	)	(40,451	)	(14,796	)
Revisions of previous estimates	(2,354	)	669		35,708		4,266
Balance at end of year	43,918		7,187		245,011		91,940

Significant changes in proved reserves for the year ended December 31, 2014, include:


•	Extensions and discoveries of 24.0 MMBOE, primarily due to drilling activity at the Company's East Texas, Bakken and Powder River Basin properties


•	Purchases of proved reserves of 6.7 MMBOE, primarily due to the purchase of working interests and leasehold positions in the Powder River Basin


•	Sales of proved reserves of (14.8) MMBOE, primarily at the Company's South Texas and Bakken properties


•	Revisions of previous estimates of 4.3 MMBOE, largely the result of higher natural gas prices and well performance revisions

The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2013, were as follows:



	Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed and undeveloped reserves:
Balance at beginning of year	33,453		7,153		239,278		80,486
Production	(4,815	)	(781	)	(28,008	)	(10,264	)
Extensions and discoveries	13,313		1,333		26,428		19,050
Improved recovery	—		—		—		—
Purchases of proved reserves	—		—		—		—
Sales of proved reserves	(1,286	)	(25	)	(40,055	)	(7,987	)
Revisions of previous estimates	354		(1,078	)	802		(590	)
Balance at end of year	41,019		6,602		198,445		80,695

Significant changes in proved reserves for the year ended December 31, 2013, include:


•	Extension and discoveries of 19.1 MMBOE, primarily due to drilling activity and new PUD locations at the Company's Bakken and Paradox Basin properties, as well as new PUD locations at Big Horn and East Texas


•	Sales of proved reserves of (8.0) MMBOE, primarily at the Company's Green River Basin property

The changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2012, were as follows:



	Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed and undeveloped reserves:
Balance at beginning of year	27,005		7,342		379,827		97,651
Production	(3,694	)	(828	)	(33,214	)	(10,058	)
Extensions and discoveries	9,874		1,817		18,386		14,756
Improved recovery	—		—		—		—
Purchases of proved reserves	—		—		—		—
Sales of proved reserves	(39	)	—		(2,307	)	(423	)
Revisions of previous estimates	307		(1,178	)	(123,414	)	(21,440	)
Balance at end of year	33,453		7,153		239,278		80,486

Significant changes in proved reserves for the year ended December 31, 2012, include:


•	Extensions and discoveries of 14.8 MMBOE, primarily due to drilling activity at the Company's Bakken, South Texas and Paradox properties


•	Revisions of previous estimates of (21.4) MMBOE, largely the result of lower natural gas prices resulting in a reduction of PDP and PUD reserves principally in the Company's Coalbed, Baker, Bowdoin, East Texas and Green River Basin natural gas properties

The following table summarizes the breakdown of the Company's proved reserves between proved developed and PUD reserves at December 31:



	2014	2013	2012
Proved developed reserves:
Oil (MBbls)	30,130	31,394	27,412
NGL (MBbls)	4,217	5,322	5,342
Natural Gas (MMcf)	184,437	176,546	218,259
Total (MBOE)	65,086	66,140	69,131
PUD reserves:
Oil (MBbls)	13,788	9,625	6,041
NGL (MBbls)	2,970	1,280	1,811
Natural Gas (MMcf)	60,574	21,899	21,019
Total (MBOE)	26,854	14,555	11,355
Total proved reserves:
Oil (MBbls)	43,918	41,019	33,453
NGL (MBbls)	7,187	6,602	7,153
Natural Gas (MMcf)	245,011	198,445	239,278
Total (MBOE)	91,940	80,695	80,486

As of December 31, 2014, the Company had 26.9 MMBOE of PUD reserves, which is an increase of 12.3 MMBOE from December 31, 2013. The increase relates to the Company adding 21.2 MMBOE of new PUD reserves and acquiring 3.9 MMBOE. This was partially offset by the Company converting 3.7 MMBOE, requiring $98.3 million of drilling and completion capital in 2014, divesting of 6.4 MMBOE, and negative PUD revisions of 2.7 MMBOE. At December 31, 2014, the Company did not have any PUD locations that remained undeveloped for five years or more. Future development costs estimated to be spent in each of the next three years to develop PUD reserves at December 31, 2014, are $141.8 million in 2015, $157.4 million in 2016 and $120.9 million in 2017. The future development costs are prepared using year-end costs and assuming continuation of existing economic and operating conditions and are not necessarily reflective of the Company’s expectations. The timing of marketing the exploration and production business may also affect future development costs.

The standardized measure of the Company's estimated discounted future net cash flows of total proved reserves associated with its various oil and natural gas interests at December 31 was as follows:



	2014		2013		2012
			(In thousands)
Future cash inflows	$	5,185,500	$	4,507,000	$	3,696,200
Future production costs	1,856,900		1,734,800		1,536,500
Future development costs	570,200		403,000		301,600
Future net cash flows before income taxes	2,758,400		2,369,200		1,858,100
Future income tax expense	686,100		545,200		304,900
Future net cash flows	2,072,300		1,824,000		1,553,200
10% annual discount for estimated timing of cash flows	997,400		810,000		669,800
Discounted future net cash flows relating to proved oil, NGL and natural gas reserves	$	1,074,900	$	1,014,000	$	883,400

The following are the sources of change in the standardized measure of discounted future net cash flows by year:



	2014			2013			2012
				(In thousands)
Beginning of year	$	1,014,000		$	883,400		$	978,800
Net revenues from production	(368,900		)	(398,000		)	(280,800		)
Net change in sales prices and production costs related to future production	86,300			162,200			(406,300		)
Extensions and discoveries, net of future production-related costs	231,900			366,500			355,300
Improved recovery, net of future production-related costs	—			—			—
Purchases of proved reserves, net of future production-related costs	103,800			—			—
Sales of proved reserves	(219,300		)	(37,800		)	(2,600		)
Changes in estimated future development costs	65,100			6,700			37,600
Development costs incurred during the current year	104,600			141,500			77,700
Accretion of discount	109,400			94,600			121,400
Net change in income taxes	(33,400		)	(141,400		)	110,000
Revisions of previous estimates	(16,300		)	(55,800		)	(100,700		)
Other	(2,300		)	(7,900		)	(7,000		)
Net change	60,900			130,600			(95,400		)
End of year	$	1,074,900		$	1,014,000		$	883,400

The estimated discounted future cash inflows from estimated future production of proved reserves were computed using prices as previously discussed. Future production and development costs, which include asset retirement costs, attributable to proved reserves were computed by applying year-end costs to be incurred in producing and further developing the proved reserves. Future income tax expenses were computed by applying statutory tax rates to the estimated net future pretax cash flows less the tax basis of the oil and gas properties, adjusted for permanent differences and tax credits.

The standardized measure of discounted future net cash flows does not purport to represent the fair market value of oil and natural gas properties. There are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production and the timing and amount of future costs. In addition, future realization of oil, NGL and natural gas prices over the remaining reserve lives may vary significantly from SEC Defined Prices.