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Exploration and Production Activities (Unaudited) (Notes) | 12 Months Ended
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Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract] |
Exploration and production activities | Exploration and Production Activities (Unaudited) In the third and fourth quarters of 2015 and the first quarter of 2016, the Company entered into purchase and sale agreements to sell the vast majority of Fidelity's assets, comprising greater than 93 percent of total production for 2014. A majority of the sales were completed in the fourth quarter of 2015. At the time the Company committed to a plan to sell Fidelity, the Company stopped the use of the full-cost method of accounting for its oil and natural gas production activities. The assets and liabilities have been classified as held for sale and the results of operations included in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. Prior to the asset sales, Fidelity was significantly involved in the development and production of oil and natural gas resources. For more information, see Note 2. Fidelity shares revenues and expenses from the development of specified properties 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:
| 2015 |  | * | 2014 |  | 2013 |
| (In thousands)
Subject to amortization | $ | — |  |  | $ | 3,205,036 |  | $ | 2,893,010 |
Not subject to amortization | — |  |  | 132,141 |  | 124,869 |
Total capitalized costs | — |  |  | 3,337,177 |  | 3,017,879 |
Less accumulated depreciation, depletion and amortization | — |  |  | 1,752,566 |  | 1,562,116 |
Net capitalized costs | $ | — |  |  | $ | 1,584,611 |  | $ | 1,455,763 |
* Excludes assets held for sale.
Capital expenditures, including those not subject to amortization, related to oil and natural gas producing activities were as follows:
Years ended December 31, | 2015 |  | * | 2014 |  | ** | 2013 |  | **
| (In thousands) |
Acquisitions: |  |  |  |  |  |  |  |  |
Proved properties | $ | — |  |  | $ | 87,919 |  |  | $ | 1,817 |  |
Unproved properties | — |  |  | 138,683 |  |  | 4,608 |  |
Exploration | — |  |  | 16,879 |  |  | 26,975 |  |
Development | — |  |  | 331,400 |  |  | 355,421 |  |
Total capital expenditures | $ | — |  |  | $ | 574,881 |  |  | $ | 388,821 |  |
* No wells were drilled in 2015. ** 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 of $(9.0) million and $(10.7) million for the years ended December 31, 2014 and 2013, respectively.
The preceding table excludes proceeds from the sales of oil and natural gas properties of $246.6 million and $83.6 million for the years ended December 31, 2014 and 2013, respectively. The following reflects the results of operations from the Company's oil and natural gas producing activities included in discontinued operations, excluding corporate overhead and financing costs:
Years ended December 31, | 2015 |  | 2014 |  | 2013 |
|  | (In thousands) |  |
Income (loss) from discontinued operations | $ | (772,385 | ) | $ | 111,998 |  | $ | 110,191 |
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, 2015, 2014 and 2013, 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. 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 changes in the Company's estimated quantities of proved oil, NGL and natural gas reserves for the year ended December 31, 2015, were as follows:
| Oil (MBbls) |  | NGL (MBbls) |  | Natural Gas (MMcf) |  | Total (MBOE) |
Proved developed and undeveloped reserves: |  |  |  |
Balance at beginning of year | 43,918 |  | 7,187 |  | 245,011 |  | 91,940 |
Production | (3,286 | ) | (393 | ) | (16,747 | ) | (6,471 | )
Extensions and discoveries | 744 |  | 29 |  | 681 |  | 888 |
Improved recovery | — |  | — |  | — |  | — |
Purchases of proved reserves | — |  | — |  | — |  | — |
Sales of proved reserves | (16,474 | ) | (6,864 | ) | (202,560 | ) | (57,097 | )
Revisions of previous estimates | (12,215 | ) | 252 |  | (23,854 | ) | (15,939 | )
Balance at end of year | 12,687 |  | 211 |  | 2,531 |  | 13,321 |
Significant changes in proved reserves for the year ended December 31, 2015, include:
• | Sales of proved reserves of (57.1) MMBOE, primarily due to the Company's decision to sell Fidelity and exit the exploration and production business
• | Revisions of previous estimates of (15.9) MMBOE, largely the result of lower commodity prices
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:
• | 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 following table summarizes the breakdown of the Company's proved reserves between proved developed and PUD reserves at December 31:
| 2015 |  | 2014 |  | 2013 |
Proved developed reserves: |  |  |
Oil (MBbls) | 11,380 |  | 30,130 |  | 31,394 |
NGL (MBbls) | 144 |  | 4,217 |  | 5,322 |
Natural Gas (MMcf) | 2,033 |  | 184,437 |  | 176,546 |
Total (MBOE) | 11,865 |  | 65,086 |  | 66,140 |
PUD reserves: |  |  |
Oil (MBbls) | 1,307 |  | 13,788 |  | 9,625 |
NGL (MBbls) | 67 |  | 2,970 |  | 1,280 |
Natural Gas (MMcf) | 498 |  | 60,574 |  | 21,899 |
Total (MBOE) | 1,456 |  | 26,854 |  | 14,555 |
Total proved reserves: |  |  |
Oil (MBbls) | 12,687 |  | 43,918 |  | 41,019 |
NGL (MBbls) | 211 |  | 7,187 |  | 6,602 |
Natural Gas (MMcf) | 2,531 |  | 245,011 |  | 198,445 |
Total (MBOE) | 13,321 |  | 91,940 |  | 80,695 |
As of December 31, 2015, the Company had 1.5 MMBOE of PUD reserves, which is a decrease of 25.4 MMBOE from December 31, 2014. The decrease relates to the various asset sales during 2015 and certain PUD reserves becoming uneconomic due to lower commodity prices. At December 31, 2015, the Company did not have any PUD locations that remained undeveloped for five years of more. 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 |
| (In thousands)
Future cash inflows | $ | 5,185,500 |  | $ | 4,507,000 |
Future production costs | 1,856,900 |  | 1,734,800 |
Future development costs | 570,200 |  | 403,000 |
Future net cash flows before income taxes | 2,758,400 |  | 2,369,200 |
Future income tax expense | 686,100 |  | 545,200 |
Future net cash flows | 2,072,300 |  | 1,824,000 |
10% annual discount for estimated timing of cash flows | 997,400 |  | 810,000 |
Discounted future net cash flows relating to proved oil, NGL and natural gas reserves | $ | 1,074,900 |  | $ | 1,014,000 |
Note: | Standardized measure not applicable in 2015 as the remaining oil and natural gas properties are held for sale and subject to fair value impairment.
The following are the sources of change in the standardized measure of discounted future net cash flows by year:
| 2014 |  | 2013 |
| (In thousands)
Beginning of year | $ | 1,014,000 |  | $ | 883,400 |
Net revenues from production | (368,900 | ) | (398,000 | )
Net change in sales prices and production costs related to future production | 86,300 |  | 162,200 |
Extensions and discoveries, net of future production-related costs | 231,900 |  | 366,500 |
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 | )
Changes in estimated future development costs | 65,100 |  | 6,700 |
Development costs incurred during the current year | 104,600 |  | 141,500 |
Accretion of discount | 109,400 |  | 94,600 |
Net change in income taxes | (33,400 | ) | (141,400 | )
Revisions of previous estimates | (16,300 | ) | (55,800 | )
Other | (2,300 | ) | (7,900 | )
Net change | 60,900 |  | 130,600 |
End of year | $ | 1,074,900 |  | $ | 1,014,000 |
Note: | Standardized measure not applicable in 2015 as the remaining oil and natural gas properties are held for sale and subject to fair value impairment.
Historically, 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.

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