Supplementary Financial Information

Quarterly Data (Unaudited)

The following unaudited information shows selected items by quarter for the years 2012 and 2011:



	First Quarter			Second Quarter			*	Third Quarter			**	Fourth Quarter			***
	(In thousands, except per share amounts)
2012
Operating revenues	$	852,807		$	967,962			$	1,173,518			$	1,081,144
Operating expenses	781,750			876,248				1,207,553				1,190,673
Operating income (loss)	71,057			91,714				(34,035		)		(109,529		)
Income (loss) from continuing operations	35,890			49,007				(29,532		)		(69,686		)
Income (loss) from discontinued operations, net of tax	(100		)	5,106				(139		)		8,700
Net income (loss)	35,790			54,113				(29,671		)		(60,986		)
Earnings (loss) per common share - basic:
Earnings (loss) before discontinued operations	.19			.26				(.16		)		(.37		)
Discontinued operations, net of tax	—			.03				—				.05
Earnings (loss) per common share - basic	.19			.29				(.16		)		(.32		)
Earnings (loss) per common share - diluted:
Earnings (loss) before discontinued operations	.19			.26				(.16		)		(.37		)
Discontinued operations, net of tax	—			.03				—				.05
Earnings (loss) per common share - diluted	.19			.29				(.16		)		(.32		)
Weighted average common shares outstanding:
Basic	188,811			188,831				188,831				188,831
Diluted	189,182			189,107				188,831				188,831

2011
Operating revenues	$	901,805		$	930,757			$	1,152,181			$	1,065,749
Operating expenses	823,739			848,454				1,032,760				939,172
Operating income	78,066			82,303				119,421				126,577
Income from continuing operations	42,529			45,235				64,100				74,088
Income (loss) from discontinued operations, net of tax	448			(168		)		(126		)		(13,080		)
Net income	42,977			45,067				63,974				61,008
Earnings per common share - basic:
Earnings before discontinued operations	.22			.24				.34				.39
Discontinued operations, net of tax	.01			—				—				(.07		)
Earnings per common share - basic	.23			.24				.34				.32
Earnings per common share - diluted:
Earnings before discontinued operations	.22			.24				.34				.39
Discontinued operations, net of tax	.01			—				—				(.07		)
Earnings per common share - diluted	.23			.24				.34				.32
Weighted average common shares outstanding:
Basic	188,671			188,794				188,794				188,794
Diluted	188,815			188,968				188,797				188,932

* 2012 reflects a net benefit of $15.0 million (after tax) related to natural gas gathering operations litigation and a net benefit largely related to estimated insurance recoveries related to the guarantee of a construction contract. For more information, see Note 19.

** 2012 reflects a $100.9 million after-tax noncash write-down of oil and natural gas properties. For more information, see Note 1.

*** 2012 reflects a $145.9 million after-tax noncash write-down of oil and natural gas properties and the reversal of an arbitration charge of $13.0 million (after tax) related to a guarantee of a construction contract, which was partially offset by the reversal of estimated insurance recoveries, as previously discussed. 2011 reflects an arbitration charge of $13.0 million (after tax) related to a guarantee of a construction contract. For more information, see Notes 1 and 19, respectively.

Certain Company operations are highly seasonal and revenues from and certain expenses for such operations may fluctuate significantly among quarterly periods. Accordingly, quarterly financial information may not be indicative of results for a full year.

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:



	2012		2011		2010
	(In thousands)
Subject to amortization	$	2,531,562	$	2,345,114	$	2,138,565
Not subject to amortization	191,794		232,462		182,402
Total capitalized costs	2,723,356		2,577,576		2,320,967
Less accumulated depreciation, depletion and amortization	1,383,386		1,229,654		1,093,723
Net capitalized costs	$	1,339,970	$	1,347,922	$	1,227,244

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,	2012		*	2011		*	2010		*
	(In thousands)
Acquisitions:
Proved properties	$	839		$	3,999		$	89,733
Unproved properties	31,109			63,354			92,100
Exploration	235,906			41,775			33,226
Development	275,959			161,647			139,733
Total capital expenditures	$	543,813		$	270,775		$	354,792

* 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 $(200,000), $(1.8) million and $11.1 million for the years ended December 31, 2012, 2011 and 2010, 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,	2012			2011		2010
	(In thousands)
Revenues:
Sales to affiliates	$	35,966		$	93,713	$	115,784
Sales to external customers	412,651			359,873		318,565
Production costs	134,795			140,606		127,403
Depreciation, depletion and amortization*	157,078			139,539		127,266
Write-downs of oil and natural gas properties	391,800			—		—
Pretax income (loss)	(235,056		)	173,441		179,680
Income tax expense (benefit)	(88,612		)	63,655		66,293
Results of operations for producing activities	$	(146,444	)	$	109,786	$	113,387

* Includes accretion of discount for asset retirement obligations of $3.3 million, $3.6 million and $3.2 million for the years ended December 31, 2012, 2011 and 2010, 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, 2012, 2011 and 2010, were calculated using SEC Defined Prices. Other factors used in the proved reserve estimates are current estimates of well operating and future development 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, 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 changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2010, were as follows:



	Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)		Total (MBOE)
Proved developed and undeveloped reserves:
Balance at beginning of year	25,930		8,286		448,425		108,954
Production	(2,767	)	(495	)	(50,391	)	(11,661	)
Extensions and discoveries	2,793		596		36,191		9,421
Improved recovery	—		—		—		—
Purchases of proved reserves	911		68		55,119		10,165
Sales of proved reserves	(18	)	—		(92	)	(34	)
Revisions of previous estimates	(1,183	)	(1,254	)	(40,855	)	(9,246	)
Balance at end of year	25,666		7,201		448,397		107,599

Significant changes in proved reserves for the year ended December 31, 2010, include:


•	Extensions and discoveries of 9.4 MMBOE primarily due to drilling activity at the Company's Bakken, Baker, Bowdoin and east Texas properties


•	Purchases of proved reserves of 10.2 MMBOE as a result of the Company's acquisition of natural gas properties in the Green River Basin in Wyoming, as discussed in Note 2

•

Revisions of previous estimates of (9.2) MMBOE largely the result of negative performance revisions resulting primarily from new information gained from production history and developmental drilling activity in the Company's Bowdoin, south Texas, Baker and east Texas properties and removal of PUD reserves due to the five-year limitation rule, partially offset by positive revisions due to increased oil and natural gas prices

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



	2012	2011	2010
Proved developed reserves:
Oil (MBbls)	27,412	23,653	22,352
NGL (MBbls)	5,342	5,225	4,234
Natural Gas (MMcf)	218,259	303,495	334,911
Total (MBOE)	69,131	79,460	82,404
PUD reserves:
Oil (MBbls)	6,041	3,352	3,314
NGL (MBbls)	1,811	2,117	2,967
Natural Gas (MMcf)	21,019	76,332	113,486
Total (MBOE)	11,355	18,191	25,195
Total proved reserves:
Oil (MBbls)	33,453	27,005	25,666
NGL (MBbls)	7,153	7,342	7,201
Natural Gas (MMcf)	239,278	379,827	448,397
Total (MBOE)	80,486	97,651	107,599

As of December 31, 2012, the Company had 11.4 MMBOE of PUD reserves, which is a decrease of 6.8 MMBOE from December 31, 2011. The decrease relates to the Company converting 3.9 MMBOE of its December 31, 2011, PUD reserves into proved developed reserves in 2012, requiring $58.4 million of drilling and completion capital in 2012 and 10.3 MMBOE of negative revisions applied to PUD locations primarily in the Company's natural gas properties. These changes were partially offset by 7.4 MMBOE of new PUD reserves primarily in the Company's oil properties. At December 31, 2012, 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, 2012, are $147.5 million in 2013, $24.3 million in 2014 and $12.0 million in 2015.

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:



	2012		2011		2010
	(In thousands)
Future cash inflows	$	3,696,200	$	4,188,000	$	3,790,700
Future production costs	1,536,500		1,560,300		1,393,000
Future development costs	301,600		285,300		312,500
Future net cash flows before income taxes	1,858,100		2,342,400		2,085,200
Future income tax expense	304,900		531,100		432,800
Future net cash flows	1,553,200		1,811,300		1,652,400
10% annual discount for estimated timing of cash flows	669,800		832,500		756,300
Discounted future net cash flows relating to proved oil, NGL and natural gas reserves	$	883,400	$	978,800	$	896,100

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



	2012			2011			2010
	(In thousands)
Beginning of year	$	978,800		$	896,100		$	658,800
Net revenues from production	(280,800		)	(301,500		)	(270,000		)
Net change in sales prices and production costs related to future production	(406,300		)	82,300			362,400
Extensions and discoveries, net of future production-related costs	355,300			226,300			130,500
Improved recovery, net of future production-related costs	—			—			—
Purchases of proved reserves, net of future production-related costs	—			9,500			99,800
Sales of proved reserves	(2,600		)	—			(500		)
Changes in estimated future development costs	37,600			51,100			34,100
Development costs incurred during the current year	77,700			56,300			43,100
Accretion of discount	121,400			105,000			76,500
Net change in income taxes	110,000			(55,800		)	(103,300		)
Revisions of previous estimates	(100,700		)	(92,900		)	(132,000		)
Other	(7,000		)	2,400			(3,300		)
Net change	(95,400		)	82,700			237,300
End of year	$	883,400		$	978,800		$	896,100

The estimated discounted future cash inflows from estimated future production of proved reserves were computed using prices as previously discussed. Future development and production 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, adjusted for permanent differences and tax credits, to estimated net future pretax cash flows.

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.