Part IV
Item 15.
Exhibits and Financial Statement Schedules
XTO ENERGY INC. Notes to Consolidated Financial Statements
15. Supplementary Financial Information for Oil and Gas Producing Activities (Unaudited)
All of our operations are directly related to oil and gas producing activities located in the United States.
Costs Incurred Related to Oil and Gas Producing Activities
The following table summarizes costs incurred whether such costs are capitalized or expensed for financial reporting purposes:
(in millions) |
2007 |
2006 |
2005 |
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| Acquisitions: | ||||||
| Proved properties | $ | 3,197 | $ | 561 | $ | 1,710 |
| Unproved properties — acquisitions of proved properties (a) | 260 | 83 | 185 | |||
| Unproved properties — other | 571 | 142 | 87 | |||
| Development (b) | 2,529 | 2,022 | 1,341 | |||
| Exploration | 257 | 123 | 52 | |||
| Asset retirement obligation accrued upon: | ||||||
| Acquisition | 58 | 7 | 24 | |||
| Development (c) | 68 | 64 | 29 | |||
| Total Costs Incurred | $ | 6,940 | $ | 3,002 | $ | 3,428 |
(a) Represents a portion of the allocated purchase price of unproved properties acquired as part of the acquisition of proved properties (Note 13). (b) Includes capitalized interest of $30 million in 2007, $18 million in 2006 and $6 million in 2005. (c) Includes revisions of $39 million in 2007, $36 million in 2006 and $16 million in 2005. |
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Proved Reserves
Our proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors. Proved reserves exclude volumes deliverable to others under production payments or retained interests.
Standardized Measure
The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of year-end prices for oil and gas and year-end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Year-end prices are not adjusted for the effect of hedge derivatives. Discounted future net cash flows are calculated using a 10% rate. Estimated future income taxes are calculated by applying year-end statutory rates to future pre-tax net cash flows, less the tax basis of related assets and applicable tax credits.
Estimated well abandonment costs, net of salvage values, are deducted from the standardized measure using year-end costs and discounted at the 10% rate. As required by SFAS No. 143, such abandonment costs are recorded as a liability on the consolidated balance sheet, using estimated values as of the projected abandonment date and discounted using a risk-adjusted rate at the time the well is drilled or acquired (Note 5).
The standardized measure does not represent management’s estimate of our future cash flows or the value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, year-end prices used to determine the standardized measure are influenced by seasonal demand and other factors and may not be the most representative in estimating future revenues or reserve data.
Proved Reserves
(in millions) |
Gas (Mcf) |
Natural Gas |
Oil (Bbls) |
Natural Gas |
| December 31, 2004 | 4,714.5 | 38.5 | 152.5 | 5,860.3 |
| Revisions | 4.0 | 5.3 | 12.1 | 108.5 |
| Extensions, additions and discoveries | 986.6 | 4.9 | 34.2 | 1,221.2 |
| Production | (377.1) | (3.8) | (14.3) | (485.5) |
| Purchases in place | 803.4 | 2.8 | 31.1 | 1,007.1 |
| Sales in place | (45.8) | (0.3) | (6.9) | (89.4) |
| December 31, 2005 | 6,085.6 | 47.4 | 208.7 | 7,622.2 |
| Revisions | (94.9) | 1.8 | 0.1 | (83.2) |
| Extensions, additions and discoveries | 1,416.8 | 4.0 | 20.3 | 1,562.6 |
| Production | (433.0) | (4.4) | (16.4) | (557.6) |
| Purchases in place | 157.9 | 4.2 | 3.3 | 202.9 |
| Sales in place (a) | (188.2) | – | (1.6) | (198.3) |
| December 31, 2006 | 6,944.2 | 53.0 | 214.4 | 8,548.6 |
| Revisions | (46.3) | 10.2 | 15.5 | 108.2 |
| Extensions, additions and discoveries | 1,797.5 | 5.8 | 18.4 | 1,942.5 |
| Production | (532.1) | (4.9) | (17.2) | (664.8) |
| Purchases in place | 1,278.8 | 2.7 | 11.3 | 1,362.7 |
| Sales in place | (1.0) | – | (1.2) | (8.2) |
| December 31, 2007 | 9,441.1 | 66.8 | 241.2 | 11,289.0 |
(a) Includes effect of distribution of Hugoton Royalty Trust units (Note 9). |
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The additions to our proved reserves from extensions, additions and discoveries in the last three years are due to the success of our development drilling program. See a summary of our drilling activity over the last three years in Part I, Items 1 and 2, Business and Properties — Exploration and Production Data — Drilling Activity.
Proved Developed Reserves
(in millions) |
Gas (Mcf) |
Natural Gas |
Oil (Bbls) |
Natural Gas |
| December 31, 2004 | 3,252.7 | 30.0 | 134.4 | 4,239.1 |
| December 31, 2005 | 4,033.1 | 36.5 | 168.5 | 5,262.9 |
| December 31, 2006 | 4,481.6 | 40.1 | 167.3 | 5,725.9 |
| December 31, 2007 | 6,031.5 | 52.9 | 184.8 | 7,457.7 |
Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Reserves
December 31 |
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(in millions) |
2007 |
2006 |
2005 |
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| Future cash inflows | $ | 86,080 | $ | 51,477 | $ | 69,732 |
| Future costs: | ||||||
| Production | (22,066) | (14,958) | (15,660) | |||
| Development | (6,065) | (4,260) | (3,175) | |||
| Future income tax | (18,423) | (10,251) | (16,823) | |||
| Future net cash flows | 39,526 | 22,008 | 34,074 | |||
| 10% annual discount | (19,988) | (11,180) | (16,980) | |||
| Standardized measure | $ | 19,538 | $ | 10,828 | $ | 17,094 |
Changes in Standardized Measure of Discounted Future Net Cash Flows
(in millions) |
2007 |
2006 |
2005 |
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| Standardized measure, January 1 | $ | 10,828 | $ | 17,094 | $ | 8,402 |
| Revisions: | ||||||
| Prices and costs | 7,958 | (10,687) | 8,506 | |||
| Quantity estimates | 1,868 | 960 | 708 | |||
| Accretion of discount | 970 | 1,511 | 741 | |||
| Future development costs | (3,082) | (2,479) | (2,167) | |||
| Income tax | (3,749) | 4,090 | (4,550) | |||
| Production rates and other | – | 3 | (2) | |||
| Net revisions | 3,965 | (6,602) | 3,236 | |||
| Extensions, additions and discoveries | 3,541 | 2,248 | 3,723 | |||
| Production | (4,359) | (3,629) | (2,744) | |||
| Development costs | 2,299 | 1,917 | 1,128 | |||
| Purchases in place (a) | 3,286 | 396 | 3,527 | |||
| Sales in place (b) | (22) | (596) | (178) | |||
| Net change | 8,710 | (6,266) | 8,692 | |||
| Standardized measure, December 31 | $ | 19,538 (c) | $ | 10,828 (d) | $ | 17,094 (e) |
(a) Generally based on the year-end present value (at year-end prices and costs) plus the cash flow received from such properties during the year, rather than the estimated present value at the date of acquisition. (b) Generally based on beginning of the year present value (at beginning of year prices and costs) less the cash flow received from such properties during the year, rather than the estimated present value at the date of sale. Included in 2006 is the effect of distribution of Hugoton Royalty Trust units (Note 9). (c) The December 31, 2007 standardized measure includes a reduction of $43 million ($68 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2007 includes a liability of $453 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions as required by SFAS No. 143, as described above. (d) The December 31, 2006 standardized measure includes a reduction of $29 million ($46 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2006 includes a liability of $307 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions as required by SFAS No. 143, as described above. (e) The December 31, 2005 standardized measure includes a reduction of $22 million ($34 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2005 includes a liability of $223 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions as required by SFAS No. 143, as described above. |
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Price and cost revisions are primarily the net result of changes in year-end prices, based on beginning of year reserve estimates. Quantity estimate revisions are primarily the result of the extended economic life of proved reserves and proved undeveloped reserve additions attributable to increased development activity.
Year-end average realized gas prices used in the estimation of proved reserves and calculation of the standardized measure were $6.39 for 2007, $5.46 for 2006, $9.26 for 2005 and $5.69 for 2004. Year-end average realized natural gas liquids prices were $60.24 for 2007, $31.96 for 2006, $36.33 for 2005 and $28.24 for 2004. Year-end average realized oil prices were $91.19 for 2007, $55.47 for 2006, $57.02 for 2005 and $41.03 for 2004.