Supplementary Financial Information

Quarterly Data (Unaudited)

The following unaudited information shows selected items by quarter for the years 2011 and 2010:



	First Quarter		Second Quarter			Third Quarter			*	Fourth Quarter			**
	(In thousands, except per share amounts)
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

2010
Operating revenues	$	834,777	$	906,444		$	1,125,923			$	1,042,551
Operating expenses	751,848		817,782			1,016,961				912,377
Operating income	82,929		88,662			108,962				130,174
Income from continuing operations	41,772		48,938			61,010				92,300
Loss from discontinued operations, net of tax	—		—			—				(3,361		)
Net income	41,772		48,938			61,010				88,939
Earnings per common share - basic:
Earnings before discontinued operations	.22		.26			.32				.49
Discontinued operations, net of tax	—		—			—				(.02		)
Earnings per common share - basic	.22		.26			.32				.47
Earnings per common share - diluted:
Earnings before discontinued operations	.22		.26			.32				.49
Discontinued operations, net of tax	—		—			—				(.02		)
Earnings per common share - diluted	.22		.26			.32				.47
Weighted average common shares outstanding:
Basic	187,963		188,129			188,170				188,281
Diluted	188,220		188,267			188,338				188,374

* 2010 reflects a natural gas gathering arbitration charge of $16.5 million (after tax). For more information, see Note 19.

** 2011 reflects an arbitration charge of $13.0 million (after tax) related to a guarantee of a construction contract. For more information, see Note 19. 2010 reflects a $13.8 million (after tax) gain on the sale of the Brazilian Transmission Lines. For more information, see Note 4.

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 natural gas and oil resources. Fidelity's activities include the acquisition of producing properties with potential development opportunities, exploratory drilling and the operation and development of natural gas and oil production properties. 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 natural gas and oil interests.

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



	2011		2010		2009
	(In thousands)
Subject to amortization	$	2,345,114	$	2,138,565	$	1,815,380
Not subject to amortization	232,462		182,402		178,214
Total capitalized costs	2,577,576		2,320,967		1,993,594
Less accumulated depreciation, depletion and amortization	1,229,654		1,093,723		969,630
Net capitalized costs	$	1,347,922	$	1,227,244	$	1,023,964

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

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



Years ended December 31,	2011		*	2010		*	2009		*
	(In thousands)
Acquisitions:
Proved properties	$	3,999		$	89,733		$	3,879
Unproved properties	63,354			92,100			8,771
Exploration	41,775			33,226			33,123
Development	161,647			139,733			135,202
Total capital expenditures	$	270,775		$	354,792		$	180,975

* 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 natural gas and oil wells, as discussed in Note 10, of $(1.8) million, $11.1 million and $2.0 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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



Years ended December 31,	2011		2010		2009
	(In thousands)
Revenues:
Sales to affiliates	$	93,713	$	115,784	$	101,230
Sales to external customers	359,873		318,565		338,425
Production costs	140,606		127,403		123,148
Depreciation, depletion and amortization*	139,539		127,266		126,278
Write-down of natural gas and oil properties	—		—		620,000
Pretax income	173,441		179,680		(429,771		)
Income tax expense	63,655		66,293		(164,216		)
Results of operations for producing activities	$	109,786	$	113,387	$	(265,555	)

* Includes accretion of discount for asset retirement obligations of $3.6 million, $3.2 million and $2.7 million for the years ended December 31, 2011, 2010 and 2009, 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 reserve estimates as of December 31, 2011, 2010 and 2009, were calculated using SEC Defined Prices and prior to that time, reserve estimates were calculated using spot market prices that existed at the end of the applicable period. Other factors used in the 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 natural gas and oil 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 natural gas and oil 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 natural gas and oil reserves for the year ended December 31, 2011, were as follows:



	Natural Gas (MMcf)		Oil (MBbls)		Total (MMcfe)
Proved developed and undeveloped reserves:
Balance at beginning of year	448,397		32,867		645,596
Production	(45,598	)	(3,500	)	(66,596	)
Extensions and discoveries	28,221		6,138		65,049
Improved recovery	—		—		—
Purchases of proved reserves	54		239		1,486
Sales of proved reserves	—		—		—
Revisions of previous estimates	(51,247	)	(1,397	)	(59,627	)
Balance at end of year	379,827		34,347		585,908

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


•	Extensions and discoveries of 65.0 Bcfe primarily due to drilling activity at the Company's Bakken and Big Horn properties


•	Revisions of previous estimates of (59.6) Bcfe, largely the result of a reduction in PUD reserves of 53.6 Bcfe 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 natural gas and oil reserves for the year ended December 31, 2010, were as follows:



	Natural Gas (MMcf)		Oil (MBbls)		Total (MMcfe)
Proved developed and undeveloped reserves:
Balance at beginning of year	448,425		34,216		653,724
Production	(50,391	)	(3,262	)	(69,963	)
Extensions and discoveries	36,191		3,389		56,523
Improved recovery	—		—		—
Purchases of proved reserves	55,119		979		60,991
Sales of proved reserves	(92	)	(18	)	(202	)
Revisions of previous estimates	(40,855	)	(2,437	)	(55,477	)
Balance at end of year	448,397		32,867		645,596

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


•	Extensions and discoveries of 56.5 Bcfe primarily due to drilling activity at the Company's Bakken, Baker, Bowdoin and east Texas properties


•	Purchases of proved reserves of 61.0 Bcfe 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 (55.5) Bcfe 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 natural gas and oil prices

The changes in the Company's estimated quantities of proved natural gas and oil reserves for the year ended December 31, 2009, were as follows:



	Natural Gas (MMcf)		Oil (MBbls)		Total (MMcfe)
Proved developed and undeveloped reserves:
Balance at beginning of year	604,282		34,348		810,371
Production	(56,632	)	(3,111	)	(75,299	)
Extensions and discoveries	26,882		2,569		42,297
Improved recovery	—		—		—
Purchases of proved reserves	—		—		—
Sales of proved reserves	(22	)	(248	)	(1,510	)
Revisions of previous estimates	(126,085	)	658		(122,135	)
Balance at end of year	448,425		34,216		653,724

Significant changes in proved reserves for the year ended December 31, 2009, include:


•	Extensions and discoveries of 42.3 Bcfe primarily due to drilling activity at the Company's Bowdoin, Bakken, Baker and east Texas properties


•	Revisions of previous estimates of (122.1) Bcfe largely the result of negative revisions resulting from decreased natural gas and oil prices and negative performance revisions resulting primarily from new information gained from production history and developmental drilling activity in the Company's east Texas and south Texas properties

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



	2011	2010	2009
Proved developed reserves:
Natural Gas (MMcf)	303,495	334,911	321,561
Oil (MBbls)	28,878	26,586	26,794
Total (MMcfe)	476,763	494,426	482,329
PUD reserves:
Natural Gas (MMcf)	76,332	113,486	126,864
Oil (MBbls)	5,469	6,281	7,422
Total (MMcfe)	109,145	151,170	171,395
Total proved reserves:
Natural Gas (MMcf)	379,827	448,397	448,425
Oil (MBbls)	34,347	32,867	34,216
Total (MMcfe)	585,908	645,596	653,724

As of December 31, 2011, the Company had 109.1 Bcfe of PUD reserves, which is a decrease of 42.0 Bcfe from December 31, 2010. The decrease relates to the Company converting 27.1 Bcfe of its December 31, 2010, PUD reserves into proved developed reserves in 2011, requiring $62.9 million of drilling and completion capital and 53.6 Bcfe of negative revisions applied to PUD locations primarily in the Company's natural gas properties. These changes were partially offset by 38.7 Bcfe of new PUD reserves primarily in the Company's oil properties. At December 31, 2011, 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, 2011, are $109.3 million in 2012, $47.8 million in 2013 and $13.7 million in 2014.

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



	2011		2010		2009
	(In thousands)
Future cash inflows	$	4,188,000	$	3,790,700	$	2,991,200
Future production costs	1,560,300		1,393,000		1,095,600
Future development costs	285,300		312,500		315,000
Future net cash flows before income taxes	2,342,400		2,085,200		1,580,600
Future income tax expense	531,100		432,800		291,000
Future net cash flows	1,811,300		1,652,400		1,289,600
10% annual discount for estimated timing of cash flows	832,500		756,300		630,800
Discounted future net cash flows relating to proved natural gas and oil reserves	$	978,800	$	896,100	$	658,800

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



	2011			2010			2009
	(In thousands)
Beginning of year	$	896,100		$	658,800		$	969,800
Net revenues from production	(301,500		)	(270,000		)	(200,900		)
Net change in sales prices and production costs related to future production	82,300			362,400			(364,800		)
Extensions and discoveries, net of future production-related costs	226,300			130,500			70,500
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	—			(500		)	(1,100		)
Changes in estimated future development costs	51,100			34,100			43,600
Development costs incurred during the current year	56,300			43,100			46,400
Accretion of discount	105,000			76,500			115,900
Net change in income taxes	(55,800		)	(103,300		)	142,800
Revisions of previous estimates	(92,900		)	(132,000		)	(155,500		)
Other	2,400			(3,300		)	(7,900		)
Net change	82,700			237,300			(311,000		)
End of year	$	978,800		$	896,100		$	658,800

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 natural gas and oil 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 natural gas and oil prices over the remaining reserve lives may vary significantly from SEC Defined Prices.