Supplemental Oil and Gas Disclosures-unaudited (Tables)
|
12 Months Ended |
Dec. 31, 2018 |
|---|
| 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,
|
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|
Net capitalized cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and natural gas properties and equipment
|
$
|
8,169.9
|
|
|
$
|
8,102.0
|
|
|
$
|
7,932.5
|
|
|
Accumulated depreciation, depletion and amortization
related to oil, NGLs and natural gas activities
|
|
(7,665.1
|
)
|
|
|
(7,525.0
|
)
|
|
|
(7,387.8
|
)
|
|
Net capitalized costs related to producing activities
|
$
|
504.8
|
|
|
$
|
577.0
|
|
|
$
|
544.7
|
|
|
| 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,
|
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|
Costs incurred: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties acquisitions
|
$
|
24.1
|
|
|
$
|
1.1
|
|
|
$
|
1.3
|
|
|
Exploration (2) (3)
|
|
49.9
|
|
|
|
62.0
|
|
|
|
4.8
|
|
|
Development
|
|
56.2
|
|
|
|
92.5
|
|
|
|
56.9
|
|
|
Unproved properties acquisitions
|
|
—
|
|
|
|
—
|
|
|
|
0.5
|
|
|
Total costs incurred in oil and gas property acquisition,
exploration and development activities
|
$
|
130.2
|
|
|
$
|
155.6
|
|
|
$
|
63.5
|
|
|
|
(1)
|
Includes net additions from capitalized ARO of $20.3 million, $21.3 million and $10.8 million during 2018, 2017 and 2016, respectively. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates.
|
|
|
(2)
|
Includes seismic costs of $1.5 million, $0.5 million and $0.2 million incurred during 2018, 2017 and 2016, respectively.
|
|
|
(3)
|
Includes geological and geophysical costs charged to expense of $5.4 million, $4.2 million and $4.1 million during 2018, 2017 and 2016, respectively.
|
|
| 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,
|
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|
Depreciation, depletion, amortization and accretion per Boe
|
$
|
11.24
|
|
|
$
|
10.68
|
|
|
$
|
13.77
|
|
|
| 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, 2015
|
|
35.5
|
|
|
|
6.6
|
|
|
|
205.4
|
|
|
|
76.4
|
|
|
|
458.1
|
|
|
Revisions of previous estimates (2)
|
|
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 (3)
|
|
4.5
|
|
|
|
0.7
|
|
|
|
25.8
|
|
|
|
9.6
|
|
|
|
57.4
|
|
|
Extensions and discoveries (4)
|
|
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
|
|
|
Revisions of previous estimates (5)
|
|
11.6
|
|
|
|
2.8
|
|
|
|
40.4
|
|
|
|
21.1
|
|
|
|
126.7
|
|
|
Extensions and discoveries (6)
|
|
0.5
|
|
|
|
0.3
|
|
|
|
7.7
|
|
|
|
2.1
|
|
|
|
12.6
|
|
|
Purchase of minerals in place (7)
|
|
1.5
|
|
|
|
0.4
|
|
|
|
9.4
|
|
|
|
3.4
|
|
|
|
20.7
|
|
|
Sales of minerals in place (8)
|
|
(2.2
|
)
|
|
|
(0.2
|
)
|
|
|
(7.2
|
)
|
|
|
(3.5
|
)
|
|
|
(21.2
|
)
|
|
Production
|
|
(6.7
|
)
|
|
|
(1.3
|
)
|
|
|
(32.0
|
)
|
|
|
(13.3
|
)
|
|
|
(80.0
|
)
|
|
Proved reserves as of Dec. 31, 2018
|
|
39.1
|
|
|
|
9.8
|
|
|
|
210.5
|
|
|
|
84.0
|
|
|
|
504.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-end proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
31.5
|
|
|
|
7.8
|
|
|
|
166.8
|
|
|
|
67.0
|
|
|
|
402.2
|
|
|
2017
|
|
26.1
|
|
|
|
7.2
|
|
|
|
173.5
|
|
|
|
62.2
|
|
|
|
373.3
|
|
|
2016
|
|
26.6
|
|
|
|
7.6
|
|
|
|
183.1
|
|
|
|
64.7
|
|
|
|
388.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-end proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018 (9)
|
|
7.6
|
|
|
|
2.0
|
|
|
|
43.7
|
|
|
|
17.0
|
|
|
|
101.9
|
|
|
2017
|
|
8.3
|
|
|
|
0.6
|
|
|
|
18.7
|
|
|
|
12.0
|
|
|
|
72.0
|
|
|
2016
|
|
6.3
|
|
|
|
0.6
|
|
|
|
14.7
|
|
|
|
9.3
|
|
|
|
55.8
|
|
|
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)
|
Primarily related to upward revisions of 14.2 MMBoe, which included upward revisions of 3.8 MMBoe at our Virgo 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.
|
|
(3)
|
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 (Tahoe/SE Tahoe) field. Additionally, increases of 3.4 MMBoe were due to price revisions.
|
|
(4)
|
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.
|
|
(5)
|
Primarily related to upward revisions of 13.8 MMBoe at our Mahogany field and of 5.4 MMBoe at our Ship Shoal 028 field. Additionally, increases of 2.3 MMBoe were due to price revisions.
|
|
(6)
|
Primarily related to extensions and discoveries of 1.3 MMBoe at our Virgo field and 0.7 MMBoe at our Ewing Bank 910 field.
|
|
(7)
|
Primarily related to our Ship Shoal 028 field and our Green Canyon 859 field (Heidelberg).
|
|
(8)
|
Primarily related to conveyance of interest in properties related to the JV Drilling Program.
|
|
(9)
|
We believe that we will be able to develop all but 1.8 MMBoe (approximately 11%) of the total of 17.0 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2018, within five years from the date such reserves were initially recorded. The lone exceptions are at the Mississippi Canyon 243 field (Matterhorn) and Virgo deepwater fields where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability. Two sidetrack PUD locations, one in each 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 2021 and 2022, respectively.
|
|
| 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,
|
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
Oil - per barrel
|
$
|
65.21
|
|
|
$
|
46.58
|
|
|
$
|
36.28
|
|
|
$
|
46.94
|
|
|
NGLs per barrel
|
|
29.73
|
|
|
|
22.65
|
|
|
|
16.82
|
|
|
|
17.60
|
|
|
Natural gas per Mcf
|
|
3.13
|
|
|
|
2.86
|
|
|
|
2.47
|
|
|
|
2.50
|
|
|
| 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 2019 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,
|
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|
Standardized Measure of Discounted Future Net Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
$
|
3,500.9
|
|
|
$
|
2,328.8
|
|
|
$
|
1,818.4
|
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
(958.5
|
)
|
|
|
(813.8
|
)
|
|
|
(691.5
|
)
|
|
Development
|
|
(272.4
|
)
|
|
|
(157.4
|
)
|
|
|
(141.1
|
)
|
|
Dismantlement and abandonment
|
|
(355.9
|
)
|
|
|
(361.9
|
)
|
|
|
(427.7
|
)
|
|
Income taxes (1)
|
|
(293.9
|
)
|
|
|
(74.8
|
)
|
|
|
—
|
|
|
Future net cash inflows before 10% discount
|
|
1,620.2
|
|
|
|
920.9
|
|
|
|
558.1
|
|
|
10% annual discount factor
|
|
(553.2
|
)
|
|
|
(180.3
|
)
|
|
|
(79.8
|
)
|
|
Total
|
$
|
1,067.0
|
|
|
$
|
740.6
|
|
|
$
|
478.3
|
|
|
|
(1)
|
No future income taxes were estimated for 2016 as our tax position had sufficient tax basis to offset estimated future taxes. State income taxes were disregarded due to immateriality.
|
|
| Schedule of Changes In Standardized Measure |
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,
|
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|
Changes in Standardized Measure
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure, beginning of year
|
$
|
740.6
|
|
|
$
|
478.3
|
|
|
$
|
613.9
|
|
|
Increases (decreases):
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas produced, net of production
costs
|
|
(398.1
|
)
|
|
|
(315.3
|
)
|
|
|
(218.6
|
)
|
|
Net changes in price, net of future production costs
|
|
571.5
|
|
|
|
288.0
|
|
|
|
(275.2
|
)
|
|
Extensions and discoveries, net of future production and
development costs
|
|
53.6
|
|
|
|
119.3
|
|
|
|
—
|
|
|
Changes in estimated future development costs
|
|
(114.7
|
)
|
|
|
(38.9
|
)
|
|
|
(32.5
|
)
|
|
Previously estimated development costs incurred
|
|
48.4
|
|
|
|
102.8
|
|
|
|
114.5
|
|
|
Revisions of quantity estimates
|
|
307.6
|
|
|
|
106.4
|
|
|
|
190.1
|
|
|
Accretion of discount
|
|
50.5
|
|
|
|
30.2
|
|
|
|
52.6
|
|
|
Net change in income taxes
|
|
(133.4
|
)
|
|
|
(54.7
|
)
|
|
|
—
|
|
|
Purchases of reserves in-place
|
|
27.8
|
|
|
|
—
|
|
|
|
—
|
|
|
Sales of reserves in-place
|
|
(54.1
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Changes in production rates due to timing and other
|
|
(32.7
|
)
|
|
|
24.5
|
|
|
|
33.5
|
|
|
Net increase (decrease) in standardized measure
|
|
326.4
|
|
|
|
262.3
|
|
|
|
(135.6
|
)
|
|
Standardized measure, end of year
|
$
|
1,067.0
|
|
|
$
|
740.6
|
|
|
$
|
478.3
|
|
|