| Supplemental Oil and Gas Disclosures-unaudited |
21. Supplemental Oil and Gas Disclosures—UNAUDITED
Geographic Area of Operation
All of our proved reserves are located within the United States, with a majority of those reserves located in the Gulf of Mexico and a minority located in Texas. Therefore, the following disclosures about our costs incurred, results of operations and proved reserves are on a total-company basis.
Capitalized Costs
Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions):
|
|
December 31, |
|
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
Net capitalized cost: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and natural gas properties and equipment |
|
$ |
7,207.1 |
|
|
$ |
6,551.5 |
|
|
$ |
5,775.4 |
|
Unproved oil and natural gas properties and equipment |
|
|
132.0 |
|
|
|
143.0 |
|
|
|
183.6 |
|
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities |
|
|
(5,069.2 |
) |
|
|
(4,640.8 |
) |
|
|
(4,307.1 |
) |
Net capitalized costs related to producing activities |
|
$ |
2,269.9 |
|
|
$ |
2,053.7 |
|
|
$ |
1,651.9 |
|
Costs Not Subject To Amortization
Costs not subject to amortization relate to unproved properties which are excluded from amortizable capital costs until it is determined that proved reserves can be assigned to such properties or until such time as the Company has made an evaluation that impairment has occurred. Subject to industry conditions, evaluation of most of these properties is expected to be completed within one to five years. The following table provides a summary of costs that are not being amortized as of December 31, 2013, by the year in which the costs were incurred (in millions):
|
|
Total |
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
|
Prior to
2011 |
|
Costs excluded by year incurred: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs |
|
$ |
87.3 |
|
|
$ |
9.2 |
|
|
$ |
8.7 |
|
|
$ |
50.1 |
|
|
$ |
19.3 |
|
Capitalized interest not subject to amortization |
|
|
29.3 |
|
|
|
8.4 |
|
|
|
7.4 |
|
|
|
5.1 |
|
|
|
8.4 |
|
Total costs not subject to amortization |
|
$ |
116.6 |
|
|
$ |
17.6 |
|
|
$ |
16.1 |
|
|
$ |
55.2 |
|
|
$ |
27.7 |
|
Costs Incurred In Oil and Gas Property Acquisition, Exploration and Development Activities
The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions):
|
|
Year Ended December 31, |
|
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
Costs incurred (1): |
|
|
|
|
|
|
|
|
|
|
|
|
Proved property acquisitions |
|
$ |
96.9 |
|
|
$ |
239.8 |
|
|
$ |
369.9 |
|
Exploration (2) (3) |
|
|
215.3 |
|
|
|
151.3 |
|
|
|
92.7 |
|
Development |
|
|
352.9 |
|
|
|
363.7 |
|
|
|
203.7 |
|
Unproved property acquisitions (4) |
|
|
26.3 |
|
|
|
26.5 |
|
|
|
95.1 |
|
Total costs incurred in oil and gas property acquisition, exploration and development activities |
|
$ |
691.4 |
|
|
$ |
781.3 |
|
|
$ |
761.4 |
|
(1) |
Includes net additions to our ARO of $50.6 million, $86.9 million and $32.8 million during 2013, 2012 and 2011, respectively, associated with acquisitions, liabilities incurred and revisions of estimates. Refer to Note 5. |
(2) |
Includes seismic costs of $8.9 million, $6.2 million and $8.0 million incurred during 2013, 2012 and 2011, respectively. |
(3) |
Includes geological and geophysical costs charged to expense of $5.9 million, $6.2 million and $6.8 million during 2013, 2012 and 2011, respectively. |
(4) |
The amounts for unproved property acquisitions include capitalized interest associated with properties classified as unproved as of the end of the period. |
Depreciation, depletion, amortization and accretion expense
The following table presents our depreciation, depletion, amortization and accretion expense per thousand cubic feet equivalent (“Mcfe”) of products sold.
|
|
Year Ended December 31, |
|
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
Depreciation, depletion, amortization and accretion per Mcfe |
|
$ |
4.18 |
|
|
$ |
3.47 |
|
|
$ |
3.24 |
|
Oil and Natural Gas Reserve Information
There are numerous uncertainties in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve information represent estimates only and are inherently imprecise and may be subject to substantial revisions as additional information such as reservoir performance, additional drilling, technological advancements and other factors become available. Decreases in the prices of oil, NGLs and natural gas could have an adverse effect on the carrying value of our proved reserves, reserve volumes and our revenues, profitability and cash flow. We are not the operator with respect to approximately 9% of our proved developed non-producing reserves, so we may not be in a position to control the timing of all development activities.
The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, NGLs and natural gas reserves. All of the reserves are located in the Unites States and the majority of the reserves are located in the Gulf of Mexico. These reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. Estimated reserves for the periods presented are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB.
|
|
|
|
|
|
|
|
|
|
|
Total Equivalent Reserves |
|
|
|
Oil
(MMBbls) |
|
|
NGLs
(MMBbls) |
|
|
Natural Gas
(Bcf) |
|
|
Oil
Equivalent
(MMBoe) (1) |
|
|
Natural Gas
Equivalent
(Bcfe) (1) |
|
Proved reserves as of December 31, 2010 |
|
|
34.0 |
|
|
|
4.2 |
|
|
|
256.3 |
|
|
|
80.9 |
|
|
|
485.4 |
|
Revisions of previous estimates (2) |
|
|
0.8 |
|
|
|
5.5 |
|
|
|
13.5 |
|
|
|
8.6 |
|
|
|
51.1 |
|
Extensions and discoveries (3) |
|
|
2.0 |
|
|
|
0.4 |
|
|
|
17.7 |
|
|
|
5.3 |
|
|
|
32.0 |
|
Purchase of minerals in place (4) |
|
|
20.7 |
|
|
|
8.9 |
|
|
|
55.9 |
|
|
|
39.0 |
|
|
|
234.1 |
|
Production |
|
|
(6.1 |
) |
|
|
(1.9 |
) |
|
|
(53.7 |
) |
|
|
(16.9 |
) |
|
|
(101.5 |
) |
Proved reserves as of December 31, 2011 |
|
|
51.4 |
|
|
|
17.1 |
|
|
|
289.7 |
|
|
|
116.9 |
|
|
|
701.1 |
|
Revisions of previous estimates (5) |
|
|
(1.1 |
) |
|
|
(2.6 |
) |
|
|
(4.8 |
) |
|
|
(4.6 |
) |
|
|
(27.5 |
) |
Extensions and discoveries (6) |
|
|
8.2 |
|
|
|
2.6 |
|
|
|
29.6 |
|
|
|
15.7 |
|
|
|
94.5 |
|
Purchase of minerals in place (7) |
|
|
2.5 |
|
|
|
0.2 |
|
|
|
25.5 |
|
|
|
7.0 |
|
|
|
42.0 |
|
Sales of reserves (8) |
|
|
(0.2 |
) |
|
|
— |
|
|
|
(1.1 |
) |
|
|
(0.4 |
) |
|
|
(2.2 |
) |
Production |
|
|
(6.0 |
) |
|
|
(2.1 |
) |
|
|
(53.8 |
) |
|
|
(17.1 |
) |
|
|
(102.8 |
) |
Proved reserves as of December 31, 2012 |
|
|
54.8 |
|
|
|
15.2 |
|
|
|
285.1 |
|
|
|
117.5 |
|
|
|
705.1 |
|
Revisions of previous estimates (9) |
|
|
(4.3 |
) |
|
|
0.2 |
|
|
|
2.1 |
|
|
|
(3.8 |
) |
|
|
(22.8 |
) |
Extensions and discoveries (10) |
|
|
13.9 |
|
|
|
2.6 |
|
|
|
22.0 |
|
|
|
20.2 |
|
|
|
121.0 |
|
Purchase of minerals in place (11) |
|
|
1.5 |
|
|
|
— |
|
|
|
4.4 |
|
|
|
2.3 |
|
|
|
13.7 |
|
Sales of reserves (12) |
|
|
(0.4 |
) |
|
|
— |
|
|
|
(0.4 |
) |
|
|
(0.5 |
) |
|
|
(3.2 |
) |
Production |
|
|
(7.0 |
) |
|
|
(2.1 |
) |
|
|
(53.3 |
) |
|
|
(18.0 |
) |
|
|
(107.9 |
) |
Proved reserves as of December 31, 2013 |
|
|
58.5 |
|
|
|
15.9 |
|
|
|
259.9 |
|
|
|
117.7 |
|
|
|
705.9 |
|
Year-end proved developed reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013 |
|
|
36.2 |
|
|
|
11.1 |
|
|
|
232.7 |
|
|
|
86.1 |
|
|
|
516.1 |
|
2012 |
|
|
35.3 |
|
|
|
11.0 |
|
|
|
243.5 |
|
|
|
86.9 |
|
|
|
521.2 |
|
2011 |
|
|
23.4 |
|
|
|
11.0 |
|
|
|
251.4 |
|
|
|
76.4 |
|
|
|
458.2 |
|
Year-end proved undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013 |
|
|
22.3 |
|
|
|
4.8 |
|
|
|
27.2 |
|
|
|
31.6 |
|
|
|
189.8 |
|
2012 |
|
|
19.5 |
|
|
|
4.2 |
|
|
|
41.6 |
|
|
|
30.6 |
|
|
|
183.9 |
|
2011 |
|
|
28.0 |
|
|
|
6.1 |
|
|
|
38.3 |
|
|
|
40.5 |
|
|
|
242.9 |
|
(1) |
The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for oil, NGLs and natural gas may differ significantly. |
(2) |
Includes revision of 6.3 Bcfe due to an increase in average prices; 16.5 Bcfe for a change in NGLs marketing arrangements; 11.3 Bcfe increase due to additional compression at our Tahoe field that increases production and ultimate recoveries; and 10.6 Bcfe at our Fairway field for revisions to reserve estimates from the acquisition date to year end. |
(3) |
Includes discoveries of 13.9 Bcfe at our Main Pass 98 field and 8.0 Bcfe at our Ship Shoal 349/359 field and extensions of 3.7 Bcfe at our Main Pass 108 field. |
(4) |
Primarily due to the acquisition of the Opal Properties and the Fairway Properties. |
(5) |
Includes downward revisions due to price of 8.0 Bcfe and negative performance revisions of 17.9 Bcfe at our Spraberry field. |
(6) |
Includes extensions and discoveries of 69.5 Bcfe at our Spraberry field and extensions and discoveries of 16.2 Bcfe at our High Island 21/22 field. |
(7) |
Due to the acquisition of the Newfield Properties. |
(8) |
Due to the sale of our interest in the South Timbalier 41 field. |
(9) |
Includes upward revision due to price of 11.3 Bcfe; negative revisions of 29.6 Bcfe at our Spraberry field for performance and technical changes, 13.9 Bcfe at our High Island 21/22 field for performance, 7.9 Bcfe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 4.3 Bcfe at our Main Pass 98 field, 4.0 Bcfe at our South Timbalier 314, 3.5 Bcfe at our Main Pass 108 field and 3.2 at our South Timbalier 176 field. |
(10) |
Includes extensions and discoveries of 75.4 Bcfe at our Spraberry field, 25.3 Bcfe at our Ship Shoal 349/359 field and 11.5 Bcfe at our Mississippi Canyon 698 field. |
(11) |
Primarily due to the acquisition of the Callon Properties. |
(12) |
Primarily due to the sales of our non-working interests in the Green Canyon 60 field, the Green Canyon 19 field and the West Delta area block 29. |
Volume measurements: |
|
|
Mcf – thousand cubic feet |
|
Bbl - barrel |
Bcf – billion cubic feet |
|
MMBbls - million barrels for crude oil, condensate or NGLs |
Bcfe – billion cubic feet equivalent |
|
MMBoe – million barrels of oil equivalent |
Standardized Measure of Discounted Future Net Cash Flows
The following presents the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves together with changes therein. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the oil realized price. Then, this ratio is applied to the oil price using FASB/SEC guidance. The average commodity prices weighted by field production related to the proved reserves are as follows:
|
|
December 31, |
|
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
|
2010 |
|
Oil – per barrel |
|
$ |
99.65 |
|
|
$ |
98.13 |
|
|
$ |
97.36 |
|
|
$ |
76.28 |
|
NGLs – per barrel |
|
|
35.21 |
|
|
|
47.30 |
|
|
|
51.30 |
|
|
|
44.92 |
|
Natural gas – per Mcf |
|
|
3.80 |
|
|
|
2.77 |
|
|
|
4.11 |
|
|
|
4.57 |
|
Future production, development costs and ARO are based on costs in effect at the end of each of the respective years with no escalations. Estimated future net cash flows, net of future income taxes, have been discounted to their present values based on a 10% annual discount rate.
The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of our oil and natural gas reserves. These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in 2014 or later years and the risks inherent in reserve estimates. The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions):
|
|
Year Ended December 31, |
|
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
Standardized Measure of Discounted Future Net Cash Flows |
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
|
$ |
7,376.7 |
|
|
$ |
6,888.4 |
|
|
$ |
7,077.2 |
|
Future costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(2,142.8 |
) |
|
|
(1,858.3 |
) |
|
|
(1,862.5 |
) |
Development |
|
|
(1,001.4 |
) |
|
|
(655.4 |
) |
|
|
(543.0 |
) |
Dismantlement and abandonment |
|
|
(441.6 |
) |
|
|
(508.0 |
) |
|
|
(513.6 |
) |
Income taxes |
|
|
(986.9 |
) |
|
|
(1,002.1 |
) |
|
|
(1,126.6 |
) |
Future net cash inflows before 10% discount |
|
|
2,804.0 |
|
|
|
2,864.6 |
|
|
|
3,031.5 |
|
10% annual discount factor |
|
|
(1,129.4 |
) |
|
|
(1,018.2 |
) |
|
|
(1,025.1 |
) |
Total |
|
$ |
1,674.6 |
|
|
$ |
1,846.4 |
|
|
$ |
2,006.4 |
|
|
|
Year Ended December 31, |
|
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
Changes in Standardized Measure |
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure, beginning of year |
|
$ |
1,846.4 |
|
|
$ |
2,006.4 |
|
|
$ |
1,179.1 |
|
Increases (decreases): |
|
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas produced, net of production costs |
|
|
(686.1 |
) |
|
|
(620.4 |
) |
|
|
(729.6 |
) |
Net changes in price, net of future production costs |
|
|
(65.2 |
) |
|
|
(224.3 |
) |
|
|
634.2 |
|
Extensions and discoveries, net of future production and development costs |
|
|
393.8 |
|
|
|
181.9 |
|
|
|
219.9 |
|
Changes in estimated future development costs |
|
|
(91.1 |
) |
|
|
(103.3 |
) |
|
|
(4.6 |
) |
Previously estimated development costs incurred |
|
|
262.1 |
|
|
|
332.9 |
|
|
|
173.9 |
|
Revisions of quantity estimates |
|
|
(91.6 |
) |
|
|
(128.1 |
) |
|
|
205.0 |
|
Accretion of discount |
|
|
202.2 |
|
|
|
231.1 |
|
|
|
135.8 |
|
Net change in income taxes |
|
|
56.6 |
|
|
|
99.7 |
|
|
|
(398.2 |
) |
Purchases of reserves in-place |
|
|
79.6 |
|
|
|
270.2 |
|
|
|
483.3 |
|
Sales of reserves in-place |
|
|
(53.1 |
) |
|
|
(16.1 |
) |
|
|
— |
|
Changes in production rates due to timing and other |
|
|
(179.0 |
) |
|
|
(183.6 |
) |
|
|
107.6 |
|
Net increase (decrease) in standardized measure |
|
|
(171.8 |
) |
|
|
(160.0 |
) |
|
|
827.3 |
|
Standardized measure, end of year |
|
$ |
1,674.6 |
|
|
$ |
1,846.4 |
|
|
$ |
2,006.4 |
|
|