Annual report pursuant to Section 13 and 15(d)

Note 20 - Supplemental Oil and Gas Disclosures - Unaudited

v3.19.3.a.u2
Note 20 - Supplemental Oil and Gas Disclosures - Unaudited
 12 Months Ended
Dec. 31, 2019
Notes to Financial Statements  
Oil and Gas Exploration and Production Industries Disclosures [Text Block]
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,
  
   
2019
    
2018
    
2017
  
Net capitalized cost:
      
 
      
 
      
 
Proved oil and natural gas properties and equipment
   $
8,532.2
     $
8,169.9
     $
8,102.0
  
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities
    
(7,793.3
 )    
(7,665.1
 )    
(7,525.0
 )
Net capitalized costs related to producing activities
   $
738.9
     $
504.8
     $
577.0
  
 
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,
  
   
2019
    
2018
    
2017
  
Costs incurred: (1)
      
 
      
 
      
 
Proved properties acquisitions
   $
223.8
     $
24.1
     $
1.1
  
Exploration (2) (3)
    
30.6
      
49.9
      
62.0
  
Development
    
114.5
      
56.2
      
92.5
  
Total costs incurred in oil and gas property acquisition, exploration and development activities
   $
368.9
     $
130.2
     $
155.6
  
 
 
(
1
)
Includes net additions from capitalized ARO of
$37.5
 million,
$20.3
million and
$21.3
million during
2019,
2018
and 
2017,
 respectively.  These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates.
 
(
2
)
Includes seismic costs of
$7.8
 million,
$1.5
million and 
$0.5
million incurred during
2019,
2018
and 
2017,
respectively.
 
(
3
)
Includes geological and geophysical costs charged to expense of
$5.7
 million,
$5.4
million and 
$4.2
million during
2019,
2018
 and
2017,
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,
  
   
2019
    
2018
    
2017
  
Depreciation, depletion, amortization and accretion per Boe
   $
10.01
     $
11.24
     $
10.68
  
 
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
10.7%
of our proved developed non-producing reserves as of
December 31, 2019 
so we
may
not
be in a position to control the timing of all development activities.  We are the operator for substantially all of our proved undeveloped reserves as of
December 31, 2019.  
In prior years, we were
not
the operator of substantially 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 United 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, 2016
    
32.9
    
8.2
    
197.8
    
74.0
    
444.0
  
Revisions of previous estimates (2)
    
4.5
    
0.7
    
25.8
    
9.6
    
57.4
  
Extensions and discoveries (3)
    
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 (4)
    
11.6
    
2.8
    
40.4
    
21.1
    
126.7
  
Extensions and discoveries (5)
    
0.5
    
0.3
    
7.7
    
2.1
    
12.6
  
Purchase of minerals in place (6)
    
1.5
    
0.4
    
9.4
    
3.4
    
20.7
  
Sales of minerals in place (7)
    
(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
  
Revisions of previous estimates (8)
    
1.4
    
(1.5
 )  
(16.9
 )  
(3.0
 )  
(18.2
 )
Extensions and discoveries (9)
    
0.9
    
0.1
    
1.2
    
1.1
    
6.7
  
Purchase of minerals in place (10)
    
3.1
    
17.4
    
417.6
    
90.1
    
540.9
  
Production
    
(6.7
 )  
(1.3
 )  
(41.3
 )  
(14.8
 )  
(89.0
 )
Proved reserves as of Dec. 31, 2019
    
37.8
    
24.5
    
571.1
    
157.4
    
944.5
  
                                 
Year-end proved developed reserves:
                                
2019
    
28.0
    
21.7
    
504.9
    
133.8
    
802.9
  
2018
    
31.5
    
7.8
    
166.8
    
67.0
    
402.2
  
2017
    
26.1
    
7.2
    
173.5
    
62.2
    
373.3
  
                                 
Year-end proved undeveloped reserves:
                                
2019 (11)    
9.8
    
2.8
    
66.2
    
23.6
    
141.6
  
2018
    
7.6
    
2.0
    
43.7
    
17.0
    
101.9
  
2017
    
8.3
    
0.6
    
18.7
    
12.0
    
72.0
  
 
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 at our Mississippi Canyon
698
(Big Bend) field, our Fairway field, our Ewing Bank
910
field and our Viosca Knoll
783
(Tahoe/SE Tahoe) field.  Additionally, increases of
3.4
MMBoe were due to price revisions.
 
(
3
)
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.
 
(
4
)
Primarily related to upward revisions at our Mahogany field and our Ship Shoal
028
field.  Additionally, increases of
2.3
MMBoe were due to price revisions.
 
(
5
)
Primarily related to extensions and discoveries of
1.3
MMBoe at our Viosca Knoll
823
(Virgo) field and
0.7
MMBoe at our Ewing Bank
910
field.
 
(
6
)
Primarily related to our Ship Shoal
028
field and our Green Canyon
859
field (Heidelberg).
 
(
7
)
Primarily related to conveyance of interest in properties related to the JV Drilling Program.
 
(
8
)
Increases primarily related to upward revisions to our Ship Shoal
028
field and our Main Pass
108
field.  Decreases of
10.0
 MMBoe were due to price revisions for all proved reserves, which include estimated price revisions of the purchase of minerals in place from the date of purchase to
December 31, 2019.
 
(
9
)
Primarily related to extensions and discoveries of
0.9
 MMBoe at our Mississippi Canyon
800
(Gladden) field.
 
(
10
)
Primarily related to the Mobile Bay Properties and Magnolia acquisitions
 
(
11
)
We believe that we will be able to develop all but
2.5
 MMBoe (approximately
11%
) of the total of
23.6
 MMBoe reserves classified as proved undeveloped (“PUDs”) at
December 31, 2019,
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
each at Matterhorn and Virgo, will be delayed until an existing well is depleted and available to sidetrack.  We also plan to recomplete and convert an existing producer at Matterhorn to water injection for improved recovery following depletion of existing well.  Based on the latest reserve report, these PUD locations are expected to be developed in
2021
and
2022.
 
 
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,
  
   
2019
    
2018
    
2017
    
2016
  
Oil - per barrel
   $
58.11
     $
65.21
     $
46.58
     $
36.28
  
NGLs per barrel
    
18.72
      
29.73
      
22.65
      
16.82
  
Natural gas per Mcf
    
2.63
      
3.13
      
2.86
      
2.47
  
 
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
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,
  
   
2019
    
2018
    
2017
  
Standardized Measure of Discounted Future Net Cash Flows
      
 
      
 
      
 
Future cash inflows
   $
4,153.8
     $
3,500.9
     $
2,328.8
  
Future costs:
                        
Production
    
(1,901.1
 )    
(958.5
 )    
(813.8
 )
Development
    
(297.3
 )    
(272.4
 )    
(157.4
 )
Dismantlement and abandonment
    
(497.4
 )    
(355.9
 )    
(361.9
 )
Income taxes
    
(170.5
 )    
(293.9
 )    
(74.8
 )
Future net cash inflows before 10% discount
    
1,287.5
      
1,620.2
      
920.9
  
10% annual discount factor
    
(300.6
 )    
(553.2
 )    
(180.3
 )
Total
   $
986.9
     $
1,067.0
     $
740.6
  
 
 
 
  
 
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,
  
   
2019
    
2018
    
2017
  
Changes in Standardized Measure
      
 
      
 
      
 
Standardized measure, beginning of year
   $
1,067.0
     $
740.6
     $
478.3
  
Increases (decreases):
                        
Sales and transfers of oil and gas produced, net of production costs    
(315.8
 )    
(398.1
 )    
(315.3
 )
Net changes in price, net of future production costs    
(376.4
 )    
571.5
      
288.0
  
Extensions and discoveries, net of future production and development costs    
27.0
      
53.6
      
119.3
  
Changes in estimated future development costs    
(6.0
 )    
(114.7
 )    
(38.9
 )
Previously estimated development costs incurred    
19.3
      
48.4
      
102.8
  
Revisions of quantity estimates    
116.4
      
307.6
      
106.4
  
Accretion of discount    
107.4
      
50.5
      
30.2
  
Net change in income taxes    
62.9
      
(133.4
 )    
(54.7
 )
Purchases of reserves in-place    
298.3
      
27.8
      
—
  
Sales of reserves in-place    
—
      
(54.1
 )    
—
  
Changes in production rates due to timing and other    
(13.2
 )    
(32.7
 )    
24.5
  
Net (decrease) increase
    
(80.1
 )    
326.4
      
262.3
  
Standardized measure, end of year
   $
986.9
     $
1,067.0
     $
740.6