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Note 17 - Supplemental Oil and Gas Disclosures (Unaudited)
 12 Months Ended
Dec. 31, 2020
Notes to Financial Statements  
Oil and Gas Exploration and Production Industries Disclosures [Text Block]
Note
17
–
Supplemental Oil and Gas Disclosures (Unaudited)
 
Net Capitalized Costs
 
The following table reflects the capitalized costs of natural gas and oil properties and the related accumulated depletion (in thousands):
 
   
Successor
    
Predecessors
  
   
December 31,
2020
    
December 31,
2019
  
   
(in thousands)
 
Proved properties
   $
367,372
     $
178,835
  
Unproved properties
    
152,741
      
227,525
  
Total capitalized costs
    
520,113
      
406,360
  
Less: accumulated depletion
    
(17,477
 )    
(1,566
 )
Net capitalized costs
   $
502,636
     $
404,794
  
 
Cost Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
 
The following table reflects costs incurred in oil, natural gas and NGL property acquisition, development and exploratory activities (in thousands):
 
   
Year Ended December 31, 2020
   
 
 
 
   
Successor
   
Predecessors
 
   
 
August 22, 2020 through
December 31, 2020
   
January 1, 2020 through
August 21, 2020
   
Year Ended
December 31, 2019
 
Acquisition costs:
                        
Proved properties
   $
-
     $
585
     $
4,635
  
Unproved properties
    
1,181
      
2,753
      
6,288
  
Total acquisition costs
    
1,181
      
3,338
      
10,923
  
Exploration costs
    
52,837
      
48,801
      
59,349
  
Development costs
    
11,757
      
863
      
54
  
Oil and gas expenditures
    
65,775
      
53,002
      
70,326
  
Asset retirement obligations, net
    
(105
 )    
98
      
316
  
Total costs incurred
   $
65,670
     $
53,100
     $
70,642
  
 
Results of Operations for Oil, Natural Gas and NGL Producing Activities
 
The following table reflects the Partnership's results of operations for oil, natural gas and natural gas liquids producing activities (in thousands):
 
   
Year Ended December 31, 2020
   
 
 
 
   
Successor
   
Predecessors
 
   
August 22, 2020
through
December 31, 2020
   
January 1, 2020
through August 21, 2020
   
Year Ended
December 31,
2019
 
Oil, NGL and natural gas sales
   $
16,400
     $
8,223
     $
8,115
  
Lease operating expenses
    
2,653
      
4,870
      
3,372
  
Production and ad valorem taxes
    
886
      
566
      
449
  
Exploration and abandonment expense
    
5,032
      
4
      
2,850
  
Depletion, depreciation and amortization expense
    
9,877
      
6,385
      
4,269
  
Accretion of discount on asset retirement obligations
    
51
      
89
      
72
  
Results of operations from oil and gas production activities
   $
(2,099
 )   $
(3,691
 )   $
(2,897
 )
 
Oil, Natural Gas and NGL Reserves
 
Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the
12
-month unweighted average of the
first
day of the month spot prices prior to the end of the reporting period. These prices as of
December 31, 2020
and
2019
were
$39.57
and
$55.69
per barrel for crude oil and
$1.985
and
$2.578
per MMBtu for natural gas, respectively. The estimated realized prices used in computing the Company's reserves as of
December 31, 2020
were as follows: (i) oil -
$38.08
per barrel, (ii) natural gas - (
$1.304
) per Mcf, and (iii) NGL -
$12.27
per barrel. The estimated realized prices used in computing the Partnership's reserves as of
December 31, 2019
were as follows: (i) oil -
$50.57
per barrel, (ii) natural gas -
$0.10
per Mcf, and (iii) NGL -
$21.17
per barrel. All prices are net of adjustments for regional basis differentials, treating costs, transportation, gas shrinkage, gas heating vale (BTU content) and/or crude quality and gravity adjustments.
 
The proved reserve estimates as of
December 31, 2020
and
2019
were prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), independent reserve engineers, and reflect the Company's current development plans. All estimates of proved reserves are determined according to the rules prescribed by the SEC in existence at the time estimates were made. These rules require that the standard of “reasonable certainty” be applied to proved reserve estimates, which is defined as having a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than
not,
and, as more technical and economic data becomes available, a positive or upward revision or
no
revision is much more likely than a negative or downward revision. Estimates are subject to revision based upon a number of factors, including many factors beyond the Company's control, such as reservoir performance, prices, economic conditions, and government restrictions. In addition, results of drilling, testing, and production subsequent to the date of an estimate
may
justify revision of that estimate.
 
Reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Estimating quantities of proved oil and natural gas reserves is a complex process that involves significant interpretations and assumptions and cannot be measured in an exact manner. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical and engineering data. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based upon, economic factors, such as oil and natural gas prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. In addition, due to the lack of substantial, if any, production data, there are greater uncertainties in estimating PUD reserves, proved developed non-producing reserves and proved developed reserves that are early in their production life. As a result, the Company's reserve estimates are inherently imprecise.
 
The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from oil and natural gas properties the Company owns declines as reserves are depleted. Except to the extent the Company conducts successful exploration and development activities or acquires additional properties containing proved reserves, or both, the Company's proved reserves will decline as reserves are produced.
 
The following table reflects changes in proved reserves during the periods indicated:
 
   
Crude Oil (MBbl)
   
Natural Gas (MMcf)
   
NGL (MBbl)
   
Total (MBoe)
 
Predecessors
 
 
 
 
  
 
 
 
  
 
 
 
  
 
 
 
Proved Reserves at January 1, 2019
    
2,914
      
809
      
222
      
3,271
  
Contribution from HighPeak II
    
973
      
569
      
78
      
1,146
  
Extensions and discoveries
    
5,413
      
2,528
      
759
      
6,593
  
Revisions of previous estimates
    
217
      
887
      
290
      
655
  
Production
    
(145
 )    
(139
 )    
-
      
(168
 )
Proved Reserves at December 31, 2019
    
9,372
      
4,654
      
1,349
      
11,497
  
Purchase of minerals in place
    
44
      
36
      
-
      
50
  
Extensions and discoveries
    
1,008
      
252
      
67
      
1,117
  
Revisions of previous estimates
    
(1,555
 )    
(1,144
 )    
(374
 )    
(2,120
 )
Production
    
(236
 )    
(87
 )    
(20
 )    
(270
 )
Proved Reserves at August 21, 2020
    
8,633
      
3,711
      
1,022
      
10,274
  
                                 
Successor
 
 
 
 
  
 
 
 
  
 
 
 
  
 
 
 
Proved Reserves at August 22, 2020
    
8,633
      
3,711
      
1,022
      
10,274
  
Extensions and discoveries
    
11,977
      
5,215
      
1,433
      
14,279
  
Revisions of previous estimates
    
(1,180
 )    
(875
 )    
(277
 )    
(1,603
 )
Production
    
(398
 )    
(112
 )    
(18
 )    
(435
 )
Proved Reserves at December 31, 2020
    
19,032
      
7,939
      
2,160
      
22,515
  
 
At
December 31, 2020,
the Company had approximately
22,515
MBoe of proved reserves. Effective
August 21, 2020,
the HighPeak business combination included estimated proved reserves totaling
10,274
MBoe. For the period from
August 22, 2020
to
December 31, 2020,
extensions and discoveries increased proved reserves by
14,279
MBoe as a result of: (i) drilling
3
gross (
3.0
net) exploratory wells that were on production as of
December 31, 2020, (
ii)
9
gross (
8.9
net) exploratory wells that were in the final stages of completion as of
December 31, 2020,
and (iii) the addition of
15
gross (
12.4
net) PUDs. Downward revisions of previous estimates of
1,603
MBoe for the period from
August 22, 2020
to
December 31, 2020
were primarily the result of: (i) negative revisions of
1,112
MBoe due to technical revisions attributable to decreased well performance and adjustments to our PUD estimates, (ii) negative revisions of
409
MBoe related to PUDs removed from the development program, (iii) negative revisions of approximately
98
MBoe primarily due to decreases in oil, natural gas and NGL prices and increased price differentials, (iv) partially offset by positive revisions of approximately
16
MBoe related to decreased forecasted operating expenses. The net increase in proved reserves was partially offset by
435
MBoe in production during the period from
August 22, 2020
to
December 31, 2020.
The Company's current development plan reflects allocation of capital with a focus on efficiencies, recoveries and rates of return.
 
At
August 21, 2020,
the Company had approximately
10,274
MBoe of proved reserves. During the period from
January 1, 2020
to
August 21, 2020,
the Company acquired interests in
three
(
3
) producing vertical wells near its area of operation which included estimated proved reserves totaling
50
MBoe. For the period from
January 1, 2020
to
August 21, 2020,
extensions and discoveries increased proved reserves by
1,117
MBoe as a result of: (i) drilling
3
gross (
3.0
net) exploratory wells that were on production as of
August 21, 2020.
Revisions of previous estimates of
2,120
MBoe for the period from
January 1, 2020
to
August 21, 2020
were primarily the result of: (i) negative revisions totaling approximately
1,975
MBoe due to technical revisions attributable to decreased well performance of offset horizontal wells resulting in lessoned projected performance and adjustments to PUD estimates, (ii) negative revisions of approximately
173
MBoe primarily due to decreases in oil, natural gas and NGL prices and increased price differentials, and (iii) partially offset by positive revisions of
28
 MBoe due to decreased forecasted operating expenses. Adding to the net decrease in proved reserves was
270
MBoe in production during the period from
January 1,
20202
to
August 21, 2020.
 
At
December 31, 2019,
the Predecessors had approximately
11,497
MBoe of proved reserves. Effective
October 1, 2019,
the contribution of a subsidiary to the Predecessors by HighPeak II included estimated proved reserves totaling
1,146
MBoe. For the year ended
December 31, 2019,
extensions and discoveries increased proved reserves by
6,593
MBoe as a result of: (i) drilling or participating in the drilling of
2
gross (
1.8
net) exploratory wells that were on production as of
December 31, 2019, (
ii)
5
gross (
5.0
net) exploratory wells that were being drilled or pending completion as of
December 31, 2019,
and (iii) the addition of
13
gross (
4.4
net) PUDs. Revisions of previous estimates of
655
MBoe for the year ended
December 31, 2019
were primarily the result of: (i) negative revisions totaling approximately
80
MBoe due to reductions in pricing and increases in pricing differentials, (ii) negative revisions of approximately
54
MBoe primarily due to increased forecasted operating expenses, and (iii) positive revisions of
789
MBoe due to improvements in well performance attributable to improved well performance of offset horizontal wells resulting in improved projected performance of these PUDs. The net increase in proved reserves was offset by
168
MBoe in production during the year ended
December 31, 2019.
 
The following table sets forth the Partnership's estimated quantities of proved developed and proved undeveloped oil, natural gas and natural gas liquid reserves:
 
   
Successor
December 31, 2020
   
Predecessors
December 31, 2019
 
Proved Developed Reserves
(1)
                
Oil (MBbl)
    
8,730
      
4,091
  
Natural gas (MMcf)
    
3,572
      
1,952
  
Natural gas liquids (MBbl)
    
957
      
548
  
Total (MBoe)
    
10,282
      
4,964
  
Proved Undeveloped Reserves
                
Oil (MBbl)
    
10,302
      
5,281
  
Natural gas (MMcf)
    
4,367
      
2,702
  
Natural gas liquids (MBbl)
    
1,203
      
801
  
Total (MBoe)
    
12,233
      
6,533
  
Total Proved Reserves
                
Oil (MBbl)
    
19,032
      
9,372
  
Natural gas (MMcf)
    
7,939
      
4,654
  
Natural gas liquids (MBbl)
    
2,160
      
1,349
  
Total (MBoe)
    
22,515
      
11,497
  
 
 
(
1
)
As of
December 31, 2020
and
2019,
proved developed reserves includes proved developed non-producing reserves of
4,517
and
3,101
MBbl of crude oil,
1,912
and
1,454
MMcf of natural gas and
517
and
447
MBbl of natural gas liquids, respectively.
 
Standardized Measure of Discounted Future Net Cash Flows
 
The following table reflects the Partnership's standardized measure of discounted future net cash flows relating from its proved crude oil, natural gas and natural gas liquids reserves (in thousands):
 
   
Successor
December 31,
2020
   
Predecessors
December 31,
2019
 
Future cash inflows
   $
740,859
     $
502,961
  
Future production costs
    
(217,025
 )    
(127,897
 )
Future development costs
    
(117,887
 )    
(78,360
 )
Future income tax expense
    
(25,824
 )    
(2,640
 )
Future net cash flows
    
380,123
      
294,064
  
Discount to present value at 10% annual rate
    
(157,931
 )    
(154,043
 )
Standardized measure of discounted future net cash flows
   $
222,192
     $
140,021
  
 
 
(
1
)
 
Effective beginning on
August 22, 2020
and as of
December 31, 2020,
the Company is treated as a corporation for U.S. federal income tax purposes. Accordingly, “future income tax expense” above includes estimates of future federal income taxes and margin / franchise taxes in Texas that
may
be incurred by the Company. As of
December 31, 2019,
the Predecessors were each treated as a partnership for U.S. federal income tax purposes. Accordingly, federal taxable income and losses were reported on the income tax returns of the Predecessor's partners. The Predecessors were subject to margin / franchise taxes in Texas, which is reflected as “Future income tax expense”.
 
The following table reflects the principal changes in the standardized measure of discounted future net cash flows attributable to the Partnership's proved reserves (in thousands):
 
   
Year Ended
December 31,
2020 (2)
   
Year Ended
December 31,
2019 (2)
 
Standardized measure of discounted future net cash flows, beginning of year
   $
140,021
     $
31,118
  
Contribution of HighPeak II to Predecessors
    
-
      
10,488
  
Sales of oil and natural gas, net of production costs
    
(15,648
 )    
(4,294
 )
Extensions and discoveries, net of future development costs
    
172,478
      
85,626
  
Net changes in prices and production costs
    
(50,728
 )    
(6,755
 )
Changes in estimated future development costs
    
6,466
      
9,483
  
Purchases of minerals in place
    
600
      
14
  
Revisions of previous quantity estimates
    
(41,646
 )    
8,232
  
Accretion of discount
    
14,134
      
3,165
  
Net changes in income taxes
(1)
    
(10,675
 )    
(857
 )
Net changes in timing of production and other
    
7,190
      
3,801
  
Standardized measure of discounted future net cash flows, end of year
   $
222,192
     $
140,021
  
 
 
(
1
)
 
Effective with the HighPeak business combination that closed on
August 21, 2020,
the oil and gas properties became owned by HighPeak Energy, which is treated as a corporation for U.S. federal income tax purposes. As such, the “Net change in income taxes” in the table above for the year ended
December 31, 2020
reflects the change in tax status applicable to the operations of the oil and gas properties. Prior to the HighPeak business combination, the Predecessors were each treated as a partnership for U.S. federal income tax purposes. Accordingly, federal taxable income and losses relating to the operation of the oil and gas properties were reported on the income tax returns of the Predecessors' partners. The Predecessors were subject to margin / franchise taxes in Texas, which is reflected as “Net change in income taxes” in the table above for the year ended
December 31, 2019.
 
(
2
)
The year ended
December 31, 2020
in the table above reflects the change in standardized measure from that of HPK LP, our Predecessor, as of
December 31, 2019
to that of the Company as of
December 31, 2020
and amounts are combined for the period from
January 1, 2020
to
August 21, 2020
of HPK LP and from
August 22, 2020
to
December 31, 2020
of the Company. There was
no
third
-party reserve report prepared as of
August 21, 2020
from which to compute a standardized measure from as of that date. The year ended
December 31, 2019
in the table above reflects the change in standardized measure from that of HighPeak I, HPK LP's Predecessor, as of
December 31, 2018
to that of HPK LP as of
December 31, 2019
and amounts are combined for the period from
January 1, 2019
to
September 30, 2019
of HighPeak I and from
October 1, 2019
to
December 31, 2019
of HPK LP. There was
no
third
-party reserve report prepared for HighPeak I as of
October 1, 2019
from which to compute a standardized measure from as of that date. We believe the table above accurately reflects the change in standardized measure for the Predecessors and Successor in a meaningful context.