Exploration and Production Activities (Unaudited)

Fidelity is involved in the acquisition, exploration, 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:



	2013		2012		2011
	(In thousands)
Subject to amortization	$	2,893,010	$	2,531,562	$	2,345,114
Not subject to amortization	124,869		191,794		232,462
Total capitalized costs	3,017,879		2,723,356		2,577,576
Less accumulated depreciation, depletion and amortization	1,562,116		1,383,386		1,229,654
Net capitalized costs	$	1,455,763	$	1,339,970	$	1,347,922
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,	2013		*	2012		*	2011		*
	(In thousands)
Acquisitions:
Proved properties	$	1,817		$	839		$	3,999
Unproved properties	4,608			31,109			63,354
Exploration	26,975			235,906			41,775
Development	355,421			275,959			161,647
Total capital expenditures	$	388,821		$	543,813		$	270,775

* 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 $(10.7) million, $(200,000) and $(1.8) million for the years ended December 31, 2013, 2012 and 2011, respectively.

The preceding table excludes proceeds from the sales of oil and natural gas properties of $83.6 million, $6.0 million and $12.4 million for the years ended December 31, 2013, 2012 and 2011, 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,	2013			2012			2011
	(In thousands)
Revenues:
Sales to affiliates	$	45,099		$	35,966		$	93,713
Sales to external customers	497,018			379,647			348,428
Realized gain on commodity derivatives	173			33,628			9,618
Unrealized gain (loss) on commodity derivatives	(6,267		)	(624		)	1,827
Production costs	144,136			134,795			140,606
Depreciation, depletion and amortization*	182,352			157,078			139,539
Write-downs of oil and natural gas properties	—			391,800			—
Pretax income (loss)	209,535			(235,056		)	173,441
Income tax expense (benefit)	75,836			(88,612		)	63,655
Results of operations for producing activities	$	133,699		$	(146,444	)	$	109,786

* Includes accretion of discount for asset retirement obligations of $3.6 million, $3.3 million and $3.6 million for the years ended December 31, 2013, 2012 and 2011, 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, 2013, 2012 and 2011, 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, 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:


•	Extensions 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:


•	Extension 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 changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2011, were as follows:



	Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed and undeveloped reserves:
Balance at beginning of year	25,666		7,201		448,397		107,599
Production	(2,724	)	(776	)	(45,598	)	(11,099	)
Extensions and discoveries	4,717		1,421		28,221		10,842
Improved recovery	—		—		—		—
Purchases of proved reserves	223		16		54		247
Sales of proved reserves	—		—		—		—
Revisions of previous estimates	(877	)	(520	)	(51,247	)	(9,938	)
Balance at end of year	27,005		7,342		379,827		97,651

Significant changes in proved reserves for the year ended December 31, 2011, include:


•	Extensions and discoveries of 10.8 MMBOE primarily due to drilling activity at the Company's Bakken and Big Horn properties


•	Revisions of previous estimates of (9.9) MMBOE, largely the result of a reduction in PUD reserves of 8.9 MMBOE resulting principally in the Company's Bowdoin, Baker, Coalbed, East Texas and Big Horn Basin properties. The remaining negative revisions were a reduction in PDP natural gas reserves.

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



	2013	2012	2011
Proved developed reserves:
Oil (MBbls)	31,394	27,412	23,653
NGL (MBbls)	5,322	5,342	5,225
Natural Gas (MMcf)	176,546	218,259	303,495
Total (MBOE)	66,140	69,131	79,460
PUD reserves:
Oil (MBbls)	9,625	6,041	3,352
NGL (MBbls)	1,280	1,811	2,117
Natural Gas (MMcf)	21,899	21,019	76,332
Total (MBOE)	14,555	11,355	18,191
Total proved reserves:
Oil (MBbls)	41,019	33,453	27,005
NGL (MBbls)	6,602	7,153	7,342
Natural Gas (MMcf)	198,445	239,278	379,827
Total (MBOE)	80,695	80,486	97,651

As of December 31, 2013, the Company had 14.6 MMBOE of PUD reserves, which is an increase of 3.2 MMBOE from December 31, 2012. The increase relates to the Company adding 11.9 MMBOE of new PUD reserves, primarily in the Company's oil properties. This was partially offset by the Company converting 7.1 MMBOE, requiring $127.3 million of drilling and completion capital in 2013 and PUD revision of (1.6) MMBOE. At December 31, 2013, 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 as of December 31, 2013, are $143.6 million in 2014, $116.0 million in 2015 and $18.1 million in 2016.

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:



	2013		2012		2011
	(In thousands)
Future cash inflows	$	4,507,000	$	3,696,200	$	4,188,000
Future production costs	1,734,800		1,536,500		1,560,300
Future development costs	403,000		301,600		285,300
Future net cash flows before income taxes	2,369,200		1,858,100		2,342,400
Future income tax expense	545,200		304,900		531,100
Future net cash flows	1,824,000		1,553,200		1,811,300
10% annual discount for estimated timing of cash flows	810,000		669,800		832,500
Discounted future net cash flows relating to proved oil, NGL and natural gas reserves	$	1,014,000	$	883,400	$	978,800

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



	2013			2012			2011
	(In thousands)
Beginning of year	$	883,400		$	978,800		$	896,100
Net revenues from production	(398,000		)	(280,800		)	(301,500		)
Net change in sales prices and production costs related to future production	162,200			(406,300		)	82,300
Extensions and discoveries, net of future production-related costs	366,500			355,300			226,300
Improved recovery, net of future production-related costs	—			—			—
Purchases of proved reserves, net of future production-related costs	—			—			9,500
Sales of proved reserves	(37,800		)	(2,600		)	—
Changes in estimated future development costs	6,700			37,600			51,100
Development costs incurred during the current year	141,500			77,700			56,300
Accretion of discount	94,600			121,400			105,000
Net change in income taxes	(141,400		)	110,000			(55,800		)
Revisions of previous estimates	(55,800		)	(100,700		)	(92,900		)
Other	(7,900		)	(7,000		)	2,400
Net change	130,600			(95,400		)	82,700
End of year	$	1,014,000		$	883,400		$	978,800

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.