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Supplemental Financial Information (Unaudited) | 12 Months Ended
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Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract] |
Supplementary Financial Information-Quarterly Data (Unaudited) | 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.

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- Definition The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished. + References Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher SEC -Name Staff Accounting Bulletin (SAB) -Number Topic 6 -Section G -Subsection 1 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Accounting Standards Codification -Topic 270 -SubTopic 10 -Section 45 -Paragraph 12 -URI http://asc.fasb.org/extlink&oid=6372559&loc=d3e725-108305 Reference 3: http://www.xbrl.org/2003/role/presentationRef -Publisher AICPA -Name Accounting Principles Board Opinion (APB) -Number 28 -Paragraph 23, 24 -LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy. Reference 4: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Accounting Standards Codification -Topic 270 -SubTopic 10 -Section 45 -Paragraph 13 -URI http://asc.fasb.org/extlink&oid=6372559&loc=d3e765-108305 Reference 5: http://www.xbrl.org/2003/role/presentationRef -Publisher AICPA -Name Accounting Principles Board Opinion (APB) -Number 28 -Paragraph 30 -Subparagraph a-j -LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy. Reference 6: http://www.xbrl.org/2003/role/presentationRef -Publisher SEC -Name Regulation S-K (SK) -Number 229 -Section 302 -Paragraph a Reference 7: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Accounting Standards Codification -Topic 270 -SubTopic 10 -Section 50 -Paragraph 1 -Subparagraph (a)-(j) -URI http://asc.fasb.org/extlink&oid=6952194&loc=d3e1280-108306 + Details
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