| Supplemental Oil and Gas Disclosures-UNAUDITED |
20. Supplemental Oil and Gas Disclosures—UNAUDITED
Geographic Area of Operation
All of our proved reserves are located within the United States in the Gulf of Mexico. 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,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
Net capitalized cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and natural gas properties and equipment
|
$
|
8,102.0
|
|
|
$
|
7,932.5
|
|
|
$
|
7,882.3
|
|
|
Unproved oil and natural gas properties and equipment
|
|
—
|
|
|
|
—
|
|
|
|
20.2
|
|
|
Accumulated depreciation, depletion and amortization (1)
related to oil, NGLs and natural gas activities
|
|
(7,525.0
|
)
|
|
|
(7,387.8
|
)
|
|
|
(6,916.2
|
)
|
|
Net capitalized costs related to producing activities
|
$
|
577.0
|
|
|
$
|
544.7
|
|
|
$
|
986.3
|
|
|
|
(1)
|
Includes ceiling test write-down in 2016 and 2015.
|
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,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
Costs incurred: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties acquisitions
|
$
|
1.1
|
|
|
$
|
1.3
|
|
|
$
|
15.6
|
|
|
Exploration (2) (3)
|
|
62.0
|
|
|
|
4.8
|
|
|
|
152.4
|
|
|
Development
|
|
92.5
|
|
|
|
56.9
|
|
|
|
65.5
|
|
|
Unproved properties acquisitions
|
|
—
|
|
|
|
0.5
|
|
|
|
0.1
|
|
|
Total costs incurred in oil and gas property acquisition,
exploration and development activities
|
$
|
155.6
|
|
|
$
|
63.5
|
|
|
$
|
233.6
|
|
|
|
(1)
|
Includes net additions from capitalized ARO of $21.3 million in 2017, net additions from capitalized ARO of $10.8 million in 2016, and net reductions from capitalized ARO of $0.4 million during 2015. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates.
|
|
|
(2)
|
Includes seismic costs of $0.5 million, $0.2 million and $3.2 million incurred during 2017, 2016 and 2015, respectively.
|
|
|
(3)
|
Includes geological and geophysical costs charged to expense of $4.2 million, $4.1 million and $5.7 million during 2017, 2016 and 2015, respectively.
|
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,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
Depreciation, depletion, amortization and accretion per Boe
|
$
|
10.68
|
|
|
$
|
13.77
|
|
|
$
|
23.11
|
|
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 represents 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 25% of our proved developed non-producing reserves as of December 31, 2017 so we may not be in a position to control the timing of all development activities. We are the operator for all of our proved undeveloped reserves as of December 31, 2017. In prior years, we were not the operator of all proved undeveloped reserves.
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, 2014
|
|
61.7
|
|
|
|
15.8
|
|
|
|
254.9
|
|
|
|
120.0
|
|
|
|
720.0
|
|
|
Revisions of previous estimates (2)
|
|
4.8
|
|
|
|
(0.9
|
)
|
|
|
4.9
|
|
|
|
4.7
|
|
|
|
28.0
|
|
|
Revisions related to sold properties (3)
|
|
(12.1
|
)
|
|
|
(4.8
|
)
|
|
|
(2.9
|
)
|
|
|
(17.4
|
)
|
|
|
(104.3
|
)
|
|
Extensions and discoveries (4)
|
|
2.4
|
|
|
|
0.2
|
|
|
|
8.8
|
|
|
|
4.1
|
|
|
|
24.4
|
|
|
Purchase of minerals in place (5)
|
|
—
|
|
|
|
—
|
|
|
|
6.1
|
|
|
|
1.0
|
|
|
|
6.1
|
|
|
Sales of reserves (6)
|
|
(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
|
|
|
Revisions of previous estimates (7)
|
|
4.6
|
|
|
|
3.1
|
|
|
|
32.1
|
|
|
|
13.0
|
|
|
|
78.1
|
|
|
Production
|
|
(7.2
|
)
|
|
|
(1.5
|
)
|
|
|
(39.7
|
)
|
|
|
(15.4
|
)
|
|
|
(92.2
|
)
|
|
Proved reserves as of Dec. 31, 2016
|
|
32.9
|
|
|
|
8.2
|
|
|
|
197.8
|
|
|
|
74.0
|
|
|
|
444.0
|
|
|
Revisions of previous estimates (8)
|
|
4.5
|
|
|
|
0.7
|
|
|
|
25.8
|
|
|
|
9.6
|
|
|
|
57.4
|
|
|
Extensions and discoveries (9)
|
|
4.1
|
|
|
|
0.3
|
|
|
|
5.4
|
|
|
|
5.2
|
|
|
|
31.3
|
|
|
Production
|
|
(7.1
|
)
|
|
|
(1.4
|
)
|
|
|
(36.8
|
)
|
|
|
(14.6
|
)
|
|
|
(87.4
|
)
|
|
Proved reserves as of Dec. 31, 2017
|
|
34.4
|
|
|
|
7.8
|
|
|
|
192.2
|
|
|
|
74.2
|
|
|
|
445.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-end proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
26.1
|
|
|
|
7.2
|
|
|
|
173.5
|
|
|
|
62.2
|
|
|
|
373.3
|
|
|
2016
|
|
26.6
|
|
|
|
7.6
|
|
|
|
183.1
|
|
|
|
64.7
|
|
|
|
388.2
|
|
|
2015
|
|
29.4
|
|
|
|
6.4
|
|
|
|
198.5
|
|
|
|
69.0
|
|
|
|
413.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-end proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 (10)
|
|
8.3
|
|
|
|
0.6
|
|
|
|
18.7
|
|
|
|
12.0
|
|
|
|
72.0
|
|
|
2016
|
|
6.3
|
|
|
|
0.6
|
|
|
|
14.7
|
|
|
|
9.3
|
|
|
|
55.8
|
|
|
2015
|
|
6.1
|
|
|
|
0.2
|
|
|
|
6.9
|
|
|
|
7.4
|
|
|
|
44.6
|
|
|
Volume measurements:
|
|
|
|
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 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.
|
|
(3)
|
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.
|
|
(4)
|
Primarily due to increases at our Ewing Bank 910 field.
|
|
(5)
|
Primarily due to purchase of additional interest at our Brazos A-133 field.
|
|
(6)
|
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.
|
|
(7)
|
Primarily related to upward revisions of 14.2 MMBoe, which included upward revisions of 3.8 MMBoe at our Viosca Knoll 823 (Tahoe/SE Tahoe) field, 1.5 MMBoe at our Fairway field, 1.3 MMBoe at our Mississippi Canyon 782 (Dantzler) field, and 1.2 MMBoe at our Main Pass 108 field. Partially offsetting were decreases for price revisions of 1.2 MMBoe.
|
|
(8)
|
Primarily related to upward revisions of 6.2 MMBoe, which included upwards revisions of 1.1 MMBoe at our Mississippi Canyon 698 (Big Bend) field, 1.0 MMBoe at our Fairway field, 0.8 MMBoe at our Ewing Bank 910 field and 0.8 MMBoe at our Viosca Knoll 783 (Virgo) field. Additionally, increases of 3.4 MMBoe were due to price revisions.
|
|
(9)
|
Primarily related to extensions and discoveries at our Ship Shoal 349 (Mahogany) field of 3.5 MMBoe and at our Main Pass 286 field of 1.5 MMBoe.
|
|
(10)
|
We believe that we will be able to develop all but 1.8 MMBoe (approximately 15%) of the total of 12.0 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2017, within five years from the date such reserves were initially recorded. The lone exceptions are 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. Two sidetrack PUD locations in this field will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, these PUD locations are expected to be developed in 2023.
|
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 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,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
Oil - per barrel
|
$
|
46.58
|
|
|
$
|
36.28
|
|
|
$
|
46.94
|
|
|
$
|
91.12
|
|
|
NGLs per barrel
|
|
22.65
|
|
|
|
16.82
|
|
|
|
17.60
|
|
|
|
34.63
|
|
|
Natural gas per Mcf
|
|
2.86
|
|
|
|
2.47
|
|
|
|
2.50
|
|
|
|
4.27
|
|
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 2017 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,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
Standardized Measure of Discounted Future Net Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
$
|
2,328.8
|
|
|
$
|
1,818.4
|
|
|
$
|
2,296.7
|
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
(813.8
|
)
|
|
|
(691.5
|
)
|
|
|
(840.1
|
)
|
|
Development
|
|
(157.4
|
)
|
|
|
(141.1
|
)
|
|
|
(161.4
|
)
|
|
Dismantlement and abandonment
|
|
(361.9
|
)
|
|
|
(427.7
|
)
|
|
|
(471.8
|
)
|
|
Income taxes (1)
|
|
(74.8
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Future net cash inflows before 10% discount
|
|
920.9
|
|
|
|
558.1
|
|
|
|
823.4
|
|
|
10% annual discount factor
|
|
(180.3
|
)
|
|
|
(79.8
|
)
|
|
|
(209.5
|
)
|
|
Total
|
$
|
740.6
|
|
|
$
|
478.3
|
|
|
$
|
613.9
|
|
|
|
(1)
|
No future income taxes were estimated for 2016 and 2015 as our tax position had sufficient tax basis to offset estimated future taxes. State income taxes were disregarded due to immateriality.
|
The change in 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,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
Changes in Standardized Measure
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure, beginning of year
|
$
|
478.3
|
|
|
$
|
613.9
|
|
|
$
|
1,702.8
|
|
|
Increases (decreases):
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas produced, net of production
costs
|
|
(315.3
|
)
|
|
|
(218.6
|
)
|
|
|
(289.1
|
)
|
|
Net changes in price, net of future production costs
|
|
288.0
|
|
|
|
(275.2
|
)
|
|
|
(1,455.6
|
)
|
|
Extensions and discoveries, net of future production and
development costs
|
|
119.3
|
|
|
|
—
|
|
|
|
65.3
|
|
|
Changes in estimated future development costs
|
|
(38.9
|
)
|
|
|
(32.5
|
)
|
|
|
(8.5
|
)
|
|
Previously estimated development costs incurred
|
|
102.8
|
|
|
|
114.5
|
|
|
|
158.9
|
|
|
Revisions of quantity estimates
|
|
106.4
|
|
|
|
190.1
|
|
|
|
137.9
|
|
|
Accretion of discount
|
|
30.2
|
|
|
|
52.6
|
|
|
|
150.6
|
|
|
Net change in income taxes
|
|
(54.7
|
)
|
|
|
—
|
|
|
|
600.8
|
|
|
Purchases of reserves in-place
|
|
—
|
|
|
|
—
|
|
|
|
6.0
|
|
|
Sales of reserves in-place
|
|
—
|
|
|
|
—
|
|
|
|
(401.4
|
)
|
|
Changes in production rates due to timing and other
|
|
24.5
|
|
|
|
33.5
|
|
|
|
(53.8
|
)
|
|
Net increase (decrease) in standardized measure
|
|
262.3
|
|
|
|
(135.6
|
)
|
|
|
(1,088.9
|
)
|
|
Standardized measure, end of year
|
$
|
740.6
|
|
|
$
|
478.3
|
|
|
$
|
613.9
|
|
|