Supplemental Oil and Gas Disclosures-unaudited (Tables)
|
12 Months Ended |
Dec. 31, 2015 |
|---|
| Extractive Industries [Abstract] |
|
| Capitalized Costs Related to Oil and Natural Gas |
Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions):
|
|
December 31,
|
|
|
|
2015
|
|
|
2014
|
|
|
2013
|
|
|
Net capitalized cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and natural gas properties and equipment
|
$
|
7,882.3
|
|
|
$
|
7,924.2
|
|
|
$
|
7,207.1
|
|
|
Unproved oil and natural gas properties and equipment
|
|
20.2
|
|
|
|
121.5
|
|
|
|
132.0
|
|
|
Accumulated depreciation, depletion and amortization (1)
related to oil, NGLs and natural gas activities
|
|
(6,916.2
|
)
|
|
|
(5,557.6
|
)
|
|
|
(5,069.2
|
)
|
|
Net capitalized costs related to producing activities
|
$
|
986.3
|
|
|
$
|
2,488.1
|
|
|
$
|
2,269.9
|
|
|
|
(1)
|
Includes ceiling test write-down in 2015.
|
|
| Capitalized 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, 2015, by the year in which the costs were incurred (in millions):
|
|
Total
|
|
|
2015
|
|
|
2014
|
|
|
2013
|
|
|
Prior to
2013
|
|
|
Costs excluded by year incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs
|
$
|
13.9
|
|
|
$
|
—
|
|
|
$
|
0.5
|
|
|
$
|
4.9
|
|
|
$
|
8.5
|
|
|
Capitalized interest not subject to amortization
|
|
4.7
|
|
|
|
1.5
|
|
|
|
1.2
|
|
|
|
0.9
|
|
|
|
1.1
|
|
|
Total costs not subject to amortization
|
$
|
18.6
|
|
|
$
|
1.5
|
|
|
$
|
1.7
|
|
|
$
|
5.8
|
|
|
$
|
9.6
|
|
|
| Cost 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,
|
|
|
|
2015
|
|
|
2014
|
|
|
2013
|
|
|
Costs incurred: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties acquisitions
|
$
|
15.6
|
|
|
$
|
111.5
|
|
|
$
|
96.9
|
|
|
Exploration (2) (3)
|
|
152.4
|
|
|
|
411.1
|
|
|
|
215.3
|
|
|
Development
|
|
65.5
|
|
|
|
198.7
|
|
|
|
352.9
|
|
|
Unproved properties acquisitions (4)
|
|
0.1
|
|
|
|
3.1
|
|
|
|
26.3
|
|
|
Total costs incurred in oil and gas property acquisition,
exploration and development activities
|
$
|
233.6
|
|
|
$
|
724.4
|
|
|
$
|
691.4
|
|
|
|
(1)
|
Includes net reductions from capitalized ARO of $0.4 million in 2015 and net additions from capitalized ARO of $88.0 million and $50.6 million during 2014 and 2013, respectively, associated with acquisitions, liabilities incurred, divestitures and revisions of estimates.
|
|
|
(2)
|
Includes seismic costs of $3.2 million, $9.0 million and $8.9 million incurred during 2015, 2014 and 2013, respectively.
|
|
|
(3)
|
Includes geological and geophysical costs charged to expense of $5.7 million, $7.3 million and $5.9 million during 2015, 2014 and 2013, respectively.
|
|
|
(4)
|
The amounts for unproved property acquisitions include capitalized interest associated with unproved properties acquired during the period.
|
|
| Schedule of Depreciation, Depletion, Amortization and Accretion Expense |
The following table presents our depreciation, depletion, amortization and accretion expense per barrel equivalent (“Boe”) of products sold.
|
|
Year Ended December 31,
|
|
|
|
2015
|
|
|
2014
|
|
|
2013
|
|
|
Depreciation, depletion, amortization and accretion per Boe
|
$
|
23.11
|
|
|
$
|
28.98
|
|
|
$
|
25.10
|
|
|
| Schedule of Oil and Natural Gas Information |
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 with all located in state and federal waters in the Gulf of Mexico. The reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. In addition to other criteria, estimated reserves are assessed for economic viability 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. The prices used do not purport, nor should it be interpreted, to present the current market prices related to our estimated oil and natural gas reserves. Actual future prices and costs may differ materially from those used in determining our proved reserves for the periods presented. The prices used are presented in the section below entitled “Standardized Measure of Discounted Future Net Cash Flows”.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Energy Equivalent Reserves (1)
|
|
|
|
Oil
(MMBbls)
|
|
|
NGLs
(MMBbls)
|
|
|
Natural Gas
(Bcf)
|
|
|
Oil
Equivalent
(MMBoe)
|
|
|
Natural Gas
Equivalent
(Bcfe)
|
|
|
Proved reserves as of Dec. 31, 2012
|
|
54.8
|
|
|
|
15.2
|
|
|
|
285.1
|
|
|
|
117.5
|
|
|
|
705.1
|
|
|
Revisions of previous estimates (2)
|
|
(4.3
|
)
|
|
|
0.2
|
|
|
|
2.1
|
|
|
|
(3.8
|
)
|
|
|
(22.8
|
)
|
|
Extensions and discoveries (3)
|
|
13.9
|
|
|
|
2.6
|
|
|
|
22.0
|
|
|
|
20.2
|
|
|
|
121.0
|
|
|
Purchase of minerals in place (4)
|
|
1.5
|
|
|
|
—
|
|
|
|
4.4
|
|
|
|
2.3
|
|
|
|
13.7
|
|
|
Sales of reserves (5)
|
|
(0.4
|
)
|
|
|
—
|
|
|
|
(0.4
|
)
|
|
|
(0.5
|
)
|
|
|
(3.2
|
)
|
|
Production
|
|
(7.0
|
)
|
|
|
(2.1
|
)
|
|
|
(53.3
|
)
|
|
|
(18.0
|
)
|
|
|
(107.9
|
)
|
|
Proved reserves as of Dec. 31, 2013
|
|
58.5
|
|
|
|
15.9
|
|
|
|
259.9
|
|
|
|
117.7
|
|
|
|
705.9
|
|
|
Revisions of previous estimates (6)
|
|
1.6
|
|
|
|
0.1
|
|
|
|
14.3
|
|
|
|
4.1
|
|
|
|
25.3
|
|
|
Extensions and discoveries (7)
|
|
7.3
|
|
|
|
0.7
|
|
|
|
10.1
|
|
|
|
9.7
|
|
|
|
58.1
|
|
|
Purchase of minerals in place (8)
|
|
1.5
|
|
|
|
1.2
|
|
|
|
20.7
|
|
|
|
6.1
|
|
|
|
36.5
|
|
|
Production
|
|
(7.2
|
)
|
|
|
(2.1
|
)
|
|
|
(50.1
|
)
|
|
|
(17.6
|
)
|
|
|
(105.8
|
)
|
|
Proved reserves as of Dec. 31, 2014
|
|
61.7
|
|
|
|
15.8
|
|
|
|
254.9
|
|
|
|
120.0
|
|
|
|
720.0
|
|
|
Revisions of previous estimates (9)
|
|
4.8
|
|
|
|
(0.9
|
)
|
|
|
4.9
|
|
|
|
4.7
|
|
|
|
28.0
|
|
|
Revisions related to sold properties (10)
|
|
(12.1
|
)
|
|
|
(4.8
|
)
|
|
|
(2.9
|
)
|
|
|
(17.4
|
)
|
|
|
(104.3
|
)
|
|
Extensions and discoveries (11)
|
|
2.4
|
|
|
|
0.2
|
|
|
|
8.8
|
|
|
|
4.1
|
|
|
|
24.4
|
|
|
Purchase of minerals in place (12)
|
|
—
|
|
|
|
—
|
|
|
|
6.1
|
|
|
|
1.0
|
|
|
|
6.1
|
|
|
Sales of reserves (13)
|
|
(13.5
|
)
|
|
|
(2.1
|
)
|
|
|
(20.2
|
)
|
|
|
(19.0
|
)
|
|
|
(113.8
|
)
|
|
Production
|
|
(7.8
|
)
|
|
|
(1.6
|
)
|
|
|
(46.2
|
)
|
|
|
(17.0
|
)
|
|
|
(102.3
|
)
|
|
Proved reserves as of Dec. 31, 2015
|
|
35.5
|
|
|
|
6.6
|
|
|
|
205.4
|
|
|
|
76.4
|
|
|
|
458.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-end proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
29.4
|
|
|
|
6.4
|
|
|
|
198.5
|
|
|
|
69.0
|
|
|
|
413.5
|
|
|
2014
|
|
35.7
|
|
|
|
10.7
|
|
|
|
221.1
|
|
|
|
83.3
|
|
|
|
499.7
|
|
|
2013
|
|
36.2
|
|
|
|
11.1
|
|
|
|
232.7
|
|
|
|
86.1
|
|
|
|
516.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-end proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 (14)
|
|
6.1
|
|
|
|
0.2
|
|
|
|
6.9
|
|
|
|
7.4
|
|
|
|
44.6
|
|
|
2014
|
|
26.0
|
|
|
|
5.1
|
|
|
|
33.8
|
|
|
|
36.7
|
|
|
|
220.3
|
|
|
2013
|
|
22.3
|
|
|
|
4.8
|
|
|
|
27.2
|
|
|
|
31.6
|
|
|
|
189.8
|
|
|
Volume measurements:
|
|
|
|
Bbl – barrel
|
|
Mcf – thousand cubic feet
|
|
MMBbls – million barrels for crude oil, condensate or NGLs
|
|
Bcf – billion cubic feet
|
|
MMBoe – million barrels of oil equivalent
|
|
Bcfe – billion cubic feet of gas equivalent
|
|
(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 barrel 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 crude oil, NGLs and natural gas may differ significantly.
|
|
(2)
|
Includes upward revision due to price of 1.9 MMBoe; negative revisions of 4.9 MMBoe at our Yellow Rose field for performance and technical changes, 2.3 MMBoe at our High Island 21/22 field for performance, 1.3 MMBoe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 0.7 MMBoe at our Main Pass 98 field, 0.7 MMBoe at our South Timbalier 314, 0.6 MMBoe at our Main Pass 108 field and 0.5 MMBoe our South Timbalier 176 field.
|
|
(3)
|
Includes extensions and discoveries of 12.6 MMBoe at our Yellow Rose field, 4.2 MMBoe at our Ship Shoal 349 field and 1.9 MMBoe at our Mississippi Canyon 698 field.
|
|
(4)
|
Primarily due to the acquisition of the Callon Properties.
|
|
(5)
|
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.
|
|
(6)
|
Includes upwards revisions due to price of 0.3 MMBoe; positive revisions of 2.4 MMBoe at our Fairway Field, 1.2 MMBoe at our Mississippi Canyon 800 field and 6.4 MMBoe at various fields; and negative revisions of 3.9 MMBoe at our Yellow Rose field and 2.4 MMBoe at various other fields.
|
|
(7)
|
Includes extensions and discoveries of 4.1 MMBoe at our Yellow Rose field and 4.1 MMBoe at our Mississippi Canyon 782 field.
|
|
(8)
|
Primarily due to acquiring additional ownership in the Fairway Field and acquisition of the Woodside Properties.
|
|
(9)
|
Includes upwards revisions of 7.4 MMBoe at the Ship Shoal 349 field (Mahogany), 1.9 MMBoe at our Brazo A-133 field, 1.3 MMBoe at out Atwater 575 field, 1.3 MMBoe at out Mississippi Canyon 243 field (Matterhorn), 1.1 MMBoe at our Fairway Field, partially offset by downward revisions due to price of 10.7 MMBoe. The revision for price excludes the Yellow Rose field sold during 2015.
|
|
(10)
|
Revisions related to the Yellow Rose field during 2015, which were primarily due to price reductions, up to the date of the sale in October 2015.
|
|
(11)
|
Primarily due to increases at Ewing Bank 910.
|
|
(12)
|
Primarily due to purchase of additional interest at Brazos A-133.
|
|
(13)
|
Related primarily to the sale of the Yellow Rose field in October 2015, which had estimated reserves at the date of sale of 19.0 MMBoe.
|
|
(14)
|
We believe that we will be able to develop all but 1.2 MMBoe of the reserves classified as proved undeveloped (“PUDs”), or approximately 16%, out of the total of 7.4 MMBoe classified as PUDs at December 31, 2015, within five years from the date such reserves were initially recorded. The exception is at the Mississippi Canyon 243 field (Matterhorn) where the field is being developed using a single floating tension leg platform requiring an extended sequential development plan. The platform cannot support a rig that would allow additional wells to be drilled, but can support a rig to allow sidetracking of wells. A portion of the PUDs in this field were originally recorded in our reserves as of December 31, 2010. The development of these PUDs will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, a well is expected to be drilled to develop the Mississippi Canyon 243 field (Matterhorn) PUDs in 2020.
|
|
| Schedule of Prices Weighted by Field Production Related to Proved Reserves |
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 crude oil realized price. Then, this ratio is applied to the crude oil price using FASB/SEC guidance. The average commodity prices weighted by field production and after adjustments related to the proved reserves are as follows:
|
|
December 31,
|
|
|
|
2015
|
|
|
2014
|
|
|
2013
|
|
|
2012
|
|
|
Oil - per barrel
|
$
|
46.94
|
|
|
$
|
91.12
|
|
|
$
|
99.65
|
|
|
$
|
98.13
|
|
|
NGLs per barrel
|
|
17.60
|
|
|
|
34.63
|
|
|
|
35.21
|
|
|
|
47.30
|
|
|
Natural gas per Mcf
|
|
2.50
|
|
|
|
4.27
|
|
|
|
3.80
|
|
|
|
2.77
|
|
|
| Standardized Measure of Discounted Future Net Cash Flow |
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 2016 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,
|
|
|
|
2015
|
|
|
2014
|
|
|
2013
|
|
|
Standardized Measure of Discounted Future Net Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
$
|
2,296.7
|
|
|
$
|
7,258.5
|
|
|
$
|
7,376.7
|
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
(840.1
|
)
|
|
|
(2,224.5
|
)
|
|
|
(2,142.8
|
)
|
|
Development
|
|
(161.4
|
)
|
|
|
(922.0
|
)
|
|
|
(1,001.4
|
)
|
|
Dismantlement and abandonment
|
|
(471.8
|
)
|
|
|
(475.4
|
)
|
|
|
(441.6
|
)
|
|
Income taxes (1)
|
|
—
|
|
|
|
(948.4
|
)
|
|
|
(986.9
|
)
|
|
Future net cash inflows before 10% discount
|
|
823.4
|
|
|
|
2,688.2
|
|
|
|
2,804.0
|
|
|
10% annual discount factor
|
|
(209.5
|
)
|
|
|
(985.4
|
)
|
|
|
(1,129.4
|
)
|
|
Total
|
$
|
613.9
|
|
|
$
|
1,702.8
|
|
|
$
|
1,674.6
|
|
|
|
(1)
|
No future income taxes were estimated to be paid in 2015 as our present tax position has sufficient tax basis and net operating loss carrying forwards to offset any future taxes. State income taxes were disregarded due to immateriality.
|
|
| Schedule of Changes In Standardized Measure |
|
|
Year Ended December 31,
|
|
|
|
2015
|
|
|
2014
|
|
|
2013
|
|
|
Changes in Standardized Measure
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure, beginning of year
|
$
|
1,702.8
|
|
|
$
|
1,674.6
|
|
|
$
|
1,846.4
|
|
|
Increases (decreases):
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas produced, net of production
costs
|
|
(289.1
|
)
|
|
|
(650.9
|
)
|
|
|
(686.1
|
)
|
|
Net changes in price, net of future production costs
|
|
(1,455.6
|
)
|
|
|
(278.6
|
)
|
|
|
(65.2
|
)
|
|
Extensions and discoveries, net of future production and
development costs
|
|
65.3
|
|
|
|
309.6
|
|
|
|
393.8
|
|
|
Changes in estimated future development costs
|
|
(8.5
|
)
|
|
|
(56.4
|
)
|
|
|
(91.1
|
)
|
|
Previously estimated development costs incurred
|
|
158.9
|
|
|
|
263.1
|
|
|
|
262.1
|
|
|
Revisions of quantity estimates
|
|
137.9
|
|
|
|
118.6
|
|
|
|
(91.6
|
)
|
|
Accretion of discount
|
|
150.6
|
|
|
|
180.6
|
|
|
|
202.2
|
|
|
Net change in income taxes
|
|
600.8
|
|
|
|
(11.4
|
)
|
|
|
56.6
|
|
|
Purchases of reserves in-place
|
|
6.0
|
|
|
|
86.7
|
|
|
|
79.6
|
|
|
Sales of reserves in-place
|
|
(401.4
|
)
|
|
|
—
|
|
|
|
(53.1
|
)
|
|
Changes in production rates due to timing and other
|
|
(53.8
|
)
|
|
|
66.9
|
|
|
|
(179.0
|
)
|
|
Net increase (decrease) in standardized measure
|
|
(1,088.9
|
)
|
|
|
28.2
|
|
|
|
(171.8
|
)
|
|
Standardized measure, end of year
|
$
|
613.9
|
|
|
$
|
1,702.8
|
|
|
$
|
1,674.6
|
|
|