|
Delaware
(State or other jurisdiction of
incorporation or organization) |
| |
06-6554331
(I.R.S. Employer
Identification No.) |
|
|
The Bank of New York Mellon
Trust Company, N.A., Trustee Global Corporate Trust 601 Travis Street, Floor 16 Houston, Texas
(Address of principal executive offices)
|
| |
77002
(Zip Code)
|
|
|
Title of each class
|
| |
Trading Symbol(s)
|
| |
Name of each exchange on which registered
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|
|
Units of Beneficial Interest
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| |
MVO
|
| |
New York Stock Exchange
|
|
| Large accelerated filer ☐ | | | Accelerated filer ☐ | | | Non-accelerated filer ☒ | | |
Smaller reporting company ☒
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|
| | | | | | | | | |
Emerging growth company ☐
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Page
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| | | | 1 | | | |
| | | | 2 | | | |
PART I
|
| | | | | | |
| | | | 6 | | | |
| | | | 29 | | | |
| | | | 41 | | | |
| | | | 41 | | | |
| | | | 43 | | | |
| | | | 43 | | | |
| | | | 43 | | | |
PART II
|
| | | | | | |
| | | | 44 | | | |
| | | | 44 | | | |
| | | | 44 | | | |
| | | | 48 | | | |
| | | | 49 | | | |
| | | | 60 | | | |
| | | | 60 | | | |
| | | | 60 | | | |
| | | | 61 | | | |
PART III
|
| | | | | | |
| | | | 62 | | | |
| | | | 62 | | | |
| | | | 62 | | | |
| | | | 63 | | | |
| | | | 64 | | | |
PART IV
|
| | | | | | |
| | | | 65 | | | |
| | | | 66 | | | |
| | | | 67 | | |
| | |
Oil
(MBbls) |
| |
Natural gas
(MMcf) |
| |
Natural gas
liquids (MBbls) |
| |
Oil
equivalents (MBoe) |
| ||||||||||||
Proved Developed
|
| | | | 1,069 | | | | | | 35 | | | | | | — | | | | | | 1,075 | | |
Proved Undeveloped
|
| | | | 14 | | | | | | — | | | | | | — | | | | | | 14 | | |
Total Proved
|
| | | | 1,083 | | | | | | 35 | | | | | | — | | | | | | 1,089 | | |
| | |
Oil
(MBbls) |
| |
Natural Gas
(MMcf) |
| |
Natural Gas
Liquids (MBbls) |
| |
Oil
Equivalents (MBoe) |
| ||||||||||||
Proved Reserves: | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance, December 31, 2020
|
| | | | 1,801 | | | | | | 18 | | | | | | 1 | | | | | | 1,805 | | |
Revisions of previous estimates
|
| | | | 662 | | | | | | 102 | | | | | | (1) | | | | | | 677 | | |
Production
|
| | | | (515) | | | | | | (33) | | | | | | — | | | | | | (520) | | |
Balance, December 31, 2021
|
| | | | 1,948 | | | | | | 87 | | | | | | — | | | | | | 1,962 | | |
Revisions of previous estimates
|
| | | | 95 | | | | | | 11 | | | | | | — | | | | | | 97 | | |
Production
|
| | | | (494) | | | | | | (25) | | | | | | — | | | | | | (498) | | |
Balance, December 31, 2022
|
| | | | 1,549 | | | | | | 73 | | | | | | — | | | | | | 1,561 | | |
Revisions of previous estimates
|
| | | | 18 | | | | | | (14) | | | | | | — | | | | | | 16 | | |
Production
|
| | | | (484) | | | | | | (24) | | | | | | — | | | | | | (488) | | |
Balance, December 31, 2023
|
| | | | 1,083 | | | | | | 35 | | | | | | — | | | | | | 1,089 | | |
Proved Developed Reserves: | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance, December 31, 2020
|
| | | | 1,641 | | | | | | 18 | | | | | | 1 | | | | | | 1,645 | | |
Balance, December 31, 2021
|
| | | | 1,861 | | | | | | 87 | | | | | | — | | | | | | 1,875 | | |
| | |
Oil
(MBbls) |
| |
Natural Gas
(MMcf) |
| |
Natural Gas
Liquids (MBbls) |
| |
Oil
Equivalents (MBoe) |
| ||||||||||||
Balance, December 31, 2022
|
| | | | 1,493 | | | | | | 73 | | | | | | — | | | | | | 1,505 | | |
Balance, December 31, 2023
|
| | | | 1,069 | | | | | | 35 | | | | | | — | | | | | | 1,075 | | |
Proved Undeveloped Reserves: | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance, December 31, 2020
|
| | | | 160 | | | | | | — | | | | | | — | | | | | | 160 | | |
Proved undeveloped reserves converted to proved developed reserves by drilling
|
| | | | (69) | | | | | | — | | | | | | — | | | | | | (69) | | |
Additional proved undeveloped reserves added during 2021
|
| | | | 10 | | | | | | — | | | | | | — | | | | | | 10 | | |
Proved undeveloped reserves removed from drilling plan
|
| | | | (14) | | | | | | — | | | | | | — | | | | | | (14) | | |
Revisions of previous estimates
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Balance, December 31, 2021
|
| | | | 87 | | | | | | — | | | | | | — | | | | | | 87 | | |
Proved undeveloped reserves converted to proved developed reserves by drilling
|
| | | | (31) | | | | | | — | | | | | | — | | | | | | (31) | | |
Additional proved undeveloped reserves added during 2022
|
| | | | 27 | | | | | | — | | | | | | — | | | | | | 27 | | |
Proved undeveloped reserves removed from drilling plan
|
| | | | (25) | | | | | | — | | | | | | — | | | | | | (25) | | |
Revisions of previous estimates
|
| | | | (1) | | | | | | — | | | | | | — | | | | | | (1) | | |
Balance, December 31, 2022
|
| | | | 57 | | | | | | — | | | | | | — | | | | | | 57 | | |
Proved undeveloped reserves converted to proved developed reserves by drilling
|
| | | | (18) | | | | | | — | | | | | | — | | | | | | (18) | | |
Additional proved undeveloped reserves added during 2023
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Proved undeveloped reserves removed from drilling plan
|
| | | | (22) | | | | | | — | | | | | | — | | | | | | (22) | | |
Revisions of previous estimates
|
| | | | (3) | | | | | | — | | | | | | — | | | | | | (3) | | |
Balance, December 31, 2023
|
| | | | 14 | | | | | | — | | | | | | — | | | | | | 14 | | |
|
| | |
Proved
Developed Producing |
| |
Proved
Developed Non-Producing |
| |
Proved
Undeveloped |
| |
Total
Proved |
| ||||||||||||
| | |
(dollars in thousands)
|
| |||||||||||||||||||||
Net Reserves | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil (MBbl)
|
| | | | 1,330.0 | | | | | | 6.9 | | | | | | 17.4 | | | | | | 1,354.3 | | |
Gas (MMcf)
|
| | | | 44.0 | | | | | | 0.0 | | | | | | 0.0 | | | | | | 44.0 | | |
NGL (MBbl)
|
| | | | 0.2 | | | | | | 0.0 | | | | | | 0.0 | | | | | | 0.2 | | |
| | |
Proved
Developed Producing |
| |
Proved
Developed Non-Producing |
| |
Proved
Undeveloped |
| |
Total
Proved |
| ||||||||||||
| | |
(dollars in thousands)
|
| |||||||||||||||||||||
Revenue | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil
|
| | | $ | 98,045.9 | | | | | $ | 511.6 | | | | | $ | 1,282.7 | | | | | $ | 99,840.2 | | |
Gas
|
| | | | 105.8 | | | | | | 0.0 | | | | | | 0.0 | | | | | | 105.8 | | |
NGL
|
| | | | 6.9 | | | | | | 0.0 | | | | | | 0.0 | | | | | | 6.9 | | |
Severance Taxes
|
| | | | 580.4 | | | | | | 23.1 | | | | | | 58.0 | | | | | | 661.6 | | |
Ad Valorem Taxes
|
| | | | 2,300.9 | | | | | | 30.7 | | | | | | 77.0 | | | | | | 2,408.5 | | |
Operating Expenses
|
| | | | 46,176.9 | | | | | | 19.2 | | | | | | 187.0 | | | | | | 46,383.1 | | |
Future Development Costs
|
| | | | 0.0 | | | | | | 250.0 | | | | | | 340.0 | | | | | | 590.0 | | |
80% NPI Net Operating Income(1)
|
| | | $ | 39,280.4 | | | | | $ | 150.8 | | | | | $ | 496.6 | | | | | $ | 39,927.8 | | |
80% Net Profits Interest (NPI)(2)
|
| | | $ | 35,199.8 | | | | | $ | 123.2 | | | | | $ | 427.9 | | | | | $ | 35,750.9 | | |
| | |
Gross
|
| |
Net
|
| ||||||
| | |
(acres)
|
| |||||||||
Developed Acreage: | | | | | | | | | | | | | |
El Dorado Area
|
| | | | 15,165 | | | | | | 15,153 | | |
Northwest Kansas Area
|
| | | | 11,165 | | | | | | 11,120 | | |
Other
|
| | | | 20,030 | | | | | | 16,382 | | |
Total
|
| | | | 46,360 | | | | | | 42,655 | | |
Undeveloped Acreage:
|
| | | | — | | | | | | — | | |
| | |
Operated
Wells |
| |
Non-Operated
Wells |
| |
Total
|
| |||||||||||||||||||||||||||
| | |
Gross
|
| |
Net
|
| |
Gross
|
| |
Net
|
| |
Gross
|
| |
Net
|
| ||||||||||||||||||
Oil
|
| | | | 781 | | | | | | 765 | | | | | | 64 | | | | | | 9 | | | | | | 845 | | | | | | 775 | | |
Natural gas
|
| | | | 3 | | | | | | 2 | | | | | | 1 | | | | | | — | | | | | | 4 | | | | | | 2 | | |
Total
|
| | | | 784 | | | | | | 767 | | | | | | 65 | | | | | | 9 | | | | | | 849 | | | | | | 777 | | |
| | |
Year Ended December 31,
|
| |||||||||||||||||||||||||||||||||
| | |
2021
|
| |
2022
|
| |
2023
|
| |||||||||||||||||||||||||||
| | |
Gross
|
| |
Net
|
| |
Gross
|
| |
Net
|
| |
Gross
|
| |
Net
|
| ||||||||||||||||||
Completed: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil wells
|
| | | | 1 | | | | | | 1 | | | | | | 1 | | | | | | 1 | | | | | | — | | | | | | — | | |
Natural gas wells
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Non-productive
|
| | | | 1 | | | | | | 1 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total
|
| | | | 2 | | | | | | 2 | | | | | | 1 | | | | | | 1 | | | | | | — | | | | | | — | | |
| | |
Year Ended December 31,
|
| |||||||||||||||
| | |
2021
|
| |
2022
|
| |
2023
|
| |||||||||
Sales prices: | | | | | | | | | | | | | | | | | | | |
Oil (per Bbl)
|
| | | $ | 61.31 | | | | | $ | 89.97 | | | | | $ | 73.85 | | |
Natural gas (per Mcf)
|
| | | $ | 2.85 | | | | | $ | 5.98 | | | | | $ | 3.09 | | |
Lease operating expense (per Boe)
|
| | | $ | 20.45 | | | | | $ | 22.67 | | | | | $ | 24.02 | | |
Lease maintenance (per Boe)
|
| | | $ | 3.57 | | | | | $ | 4.95 | | | | | $ | 3.95 | | |
Lease overhead (per Boe)
|
| | | $ | 5.01 | | | | | $ | 5.41 | | | | | $ | 5.80 | | |
Production and property taxes (per Boe)
|
| | | $ | 1.38 | | | | | $ | 1.64 | | | | | $ | 1.88 | | |
| | |
December 31,
|
| |||||||||
| | |
2022
|
| |
2023
|
| ||||||
ASSETS
|
| | | | | | | | | | | | |
Cash and cash equivalents
|
| | | $ | 1,036,214 | | | | | $ | 1,263,932 | | |
Investment in net profits interest
|
| | | | 50,383,675 | | | | | | 50,383,675 | | |
Accumulated amortization
|
| | | | (44,536,335) | | | | | | (46,191,522) | | |
Total assets
|
| | | $ | 6,883,554 | | | | | $ | 5,456,085 | | |
TRUST CORPUS
|
| | | | | | | | | | | | |
Trust corpus, 11,500,000 Trust Units issued and outstanding at December 31, 2022 and 2023
|
| | | $ | 6,883,554 | | | | | $ | 5,456,085 | | |
| | |
Year ended December 31,
|
| |||||||||||||||
| | |
2021
|
| |
2022
|
| |
2023
|
| |||||||||
Income from net profits interest
|
| | | $ | 12,078,886 | | | | | $ | 27,204,590 | | | | | $ | 18,068,559 | | |
Cash on hand used (withheld) for Trust expenses
|
| | | | 207,425 | | | | | | (739,068) | | | | | | (227,718) | | |
General and administrative expense(1)
|
| | | | (958,811) | | | | | | (935,522) | | | | | | (1,050,841) | | |
Distributable income
|
| | | $ | 11,327,500 | | | | | $ | 25,530,000 | | | | | $ | 16,790,000 | | |
Distributions per Trust Unit (11,500,000 Trust Units issued and outstanding for 2021, 2022 and 2023)
|
| | | $ | 0.985 | | | | | $ | 2.220 | | | | | $ | 1.460 | | |
| | |
Year ended December 31,
|
| |||||||||||||||
| | |
2021
|
| |
2022
|
| |
2023
|
| |||||||||
Trust corpus, beginning of year
|
| | | $ | 10,583,308 | | | | | $ | 7,909,468 | | | | | $ | 6,883,554 | | |
Income from net profits interest
|
| | | | 12,078,886 | | | | | | 27,204,590 | | | | | | 18,068,559 | | |
Cash distributions
|
| | | | (11,327,500) | | | | | | (25,530,000) | | | | | | (16,790,000) | | |
Trust expenses
|
| | | | (958,811) | | | | | | (935,522) | | | | | | (1,050,841) | | |
Amortization of net profits interest
|
| | | | (2,466,415) | | | | | | (1,764,982) | | | | | | (1,655,187) | | |
Trust corpus, end of year
|
| | | $ | 7,909,468 | | | | | $ | 6,883,554 | | | | | $ | 5,456,085 | | |
|
Oil and gas properties
|
| | | $ | 96,210,819 | | |
|
Accumulated depreciation and depletion
|
| | | | (40,468,762) | | |
|
Hedge asset
|
| | | | 7,237,537 | | |
|
Net property value to be conveyed
|
| | | | 62,979,594 | | |
|
Times 80% net profits interest to Trust
|
| | | $ | 50,383,675 | | |
| | |
Year ended December 31,
|
| |||||||||||||||
| | |
2021
|
| |
2022
|
| |
2023
|
| |||||||||
Excess of revenues over direct operating expenses and lease equipment and development costs(1)
|
| | | $ | 15,098,607 | | | | | $ | 34,005,736 | | | | | $ | 22,585,699 | | |
Times net profits interest over the term of the Trust
|
| | | | 80% | | | | | | 80% | | | | | | 80% | | |
Income from net profits interest before reserve adjustments
|
| | | | 12,078,886 | | | | | | 27,204,590 | | | | | | 18,068,559 | | |
MV Partners reserve for future capital expenditures(2)
|
| | | | — | | | | | | — | | | | | | — | | |
Income from net profits interest(3)
|
| | | $ | 12,078,886 | | | | | $ | 27,204,590 | | | | | $ | 18,068,559 | | |
Date paid
|
| |
Period covered
|
| |
Distribution
per unit |
| |
Reserve
released (established)(1) |
| ||||||
January 25, 2021
|
| |
October 1, 2020 through December 31, 2020
|
| | | $ | 0.110 | | | | | | — | | |
April 23, 2021
|
| | January 1, 2021 through March 31, 2021 | | | | $ | 0.210 | | | | | | — | | |
July 23, 2021
|
| | April 1, 2021 through June 30, 2021 | | | | $ | 0.300 | | | | | | — | | |
October 25, 2021
|
| | July 1, 2021 through September 30, 2021 | | | | $ | 0.365 | | | | | | — | | |
January 25, 2022
|
| |
October 1, 2021 through December 31, 2021
|
| | | $ | 0.410 | | | | | | — | | |
April 25, 2022
|
| | January 1, 2022 through March 31, 2022 | | | | $ | 0.425 | | | | | | — | | |
July 25, 2022
|
| | April 1, 2022 through June 30, 2022 | | | | $ | 0.700 | | | | | | — | | |
October 25, 2022
|
| | July 1, 2022 through September 30, 2022 | | | | $ | 0.685 | | | | | | — | | |
January 25, 2023
|
| |
October 1, 2022 through December 31, 2022
|
| | | $ | 0.410 | | | | | | — | | |
April 25, 2023
|
| | January 1, 2023 through March 31, 2023 | | | | $ | 0.345 | | | | | | — | | |
July 25, 2023
|
| | April 1, 2023 through June 30, 2023 | | | | $ | 0.325 | | | | | | — | | |
October 25, 2023
|
| | July 1, 2023 through September 30, 2023 | | | | $ | 0.380 | | | | | | — | | |
| | |
Oil (Bbls)
|
| |
Gas (Mcf)
|
| |
NGL (Bbls)
|
| |
Total (Boe)
|
| ||||||||||||
Proved reserves | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2020
|
| | | | 1,800,942 | | | | | | 18,396 | | | | | | 654 | | | | | | 1,804,434 | | |
Revisions of previous estimates
|
| | | | 661,281 | | | | | | 101,055 | | | | | | (247)) | | | | | | 677,963 | | |
Production
|
| | | | (514,745) | | | | | | (32,916) | | | | | | (88) | | | | | | (520,289) | | |
Balance at December 31, 2021
|
| | | | 1,947,478 | | | | | | 86,535 | | | | | | 319 | | | | | | 1,962,108 | | |
Revisions of previous estimates
|
| | | | 95,494 | | | | | | 11,867 | | | | | | 28 | | | | | | 97,490 | | |
Production
|
| | | | (493,642) | | | | | | (25,461) | | | | | | (87) | | | | | | (497,942) | | |
Balance at December 31, 2022
|
| | | | 1,549,330 | | | | | | 72,941 | | | | | | 260 | | | | | | 1,561,656 | | |
Revisions of previous estimates
|
| | | | 18,556 | | | | | | (13,839) | | | | | | (49) | | | | | | 16,218 | | |
Production
|
| | | | (484,433) | | | | | | (23,929) | | | | | | (34) | | | | | | (488,444) | | |
Balance at December 31, 2023
|
| | | | 1,083,453 | | | | | | 35,173 | | | | | | 177 | | | | | | 1,089,430 | | |
Proved developed reserves | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2020
|
| | | | 1,641,394 | | | | | | 18,396 | | | | | | 654 | | | | | | 1,644,886 | | |
December 31, 2021
|
| | | | 1,860,861 | | | | | | 86,535 | | | | | | 319 | | | | | | 1,875,491 | | |
December 31, 2022
|
| | | | 1,492,741 | | | | | | 72,941 | | | | | | 260 | | | | | | 1,505,067 | | |
December 31, 2023
|
| | | | 1,069,533 | | | | | | 35,173 | | | | | | 177 | | | | | | 1,075,510 | | |
Proved undeveloped reserves | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2020
|
| | | | 159,548 | | | | | | — | | | | | | — | | | | | | 159,548 | | |
Proved undeveloped reserves converted to proved developed reserves by drilling
|
| | | | (68,621) | | | | | | — | | | | | | — | | | | | | (68,621) | | |
Additional proved undeveloped reserves added during 2021
|
| | | | 9,981 | | | | | | — | | | | | | — | | | | | | 9,981 | | |
Proved undeveloped reserves removed from drilling
plan |
| | | | (14,294) | | | | | | — | | | | | | — | | | | | | (14,294) | | |
Revisions of previous estimates
|
| | | | 3 | | | | | | — | | | | | | — | | | | | | 3 | | |
December 31, 2021
|
| | | | 86,617 | | | | | | — | | | | | | — | | | | | | 86,617 | | |
Proved undeveloped reserves converted to proved developed reserves by drilling
|
| | | | (31,444) | | | | | | — | | | | | | — | | | | | | (31,444) | | |
Additional proved undeveloped reserves added during 2022
|
| | | | 26,746 | | | | | | — | | | | | | — | | | | | | 26,746 | | |
Proved undeveloped reserves removed from
drilling plan |
| | | | (25,304) | | | | | | — | | | | | | — | | | | | | (25,304) | | |
Revisions of previous estimates
|
| | | | (26) | | | | | | — | | | | | | — | | | | | | (26) | | |
December 31, 2022
|
| | | | 56,589 | | | | | | — | | | | | | — | | | | | | 56,589 | | |
Proved undeveloped reserves converted to proved developed reserves by drilling
|
| | | | (17,513) | | | | | | — | | | | | | — | | | | | | (17,513) | | |
Additional proved undeveloped reserves added during 2023
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Proved undeveloped reserves removed from drilling
plan |
| | | | (21,859) | | | | | | — | | | | | | — | | | | | | (21,859) | | |
Revisions of previous estimates
|
| | | | (3,297) | | | | | | — | | | | | | — | | | | | | (3,297) | | |
December 31, 2023
|
| | | | 13,920 | | | | | | — | | | | | | — | | | | | | 13,920 | | |
| | |
2021
|
| |
2022
|
| |
2023
|
| |||||||||
Future cash inflows
|
| | | $ | 121,119,425 | | | | | $ | 138,608,602 | | | | | $ | 79,962,266 | | |
Future costs | | | | | | | | | | | | | | | | | | | |
Production
|
| | | | (65,037,972) | | | | | | (56,930,542) | | | | | | (39,562,496) | | |
Development
|
| | | | (1,442,500) | | | | | | (1,047,713) | | | | | | (472,000) | | |
Future net cash flows
|
| | | | 54,638,953 | | | | | | 80,630,347 | | | | | | 39,927,770 | | |
Less 10% discount factor
|
| | | | (9,376,987) | | | | | | (11,418,520) | | | | | | (4,176,829) | | |
Standardized measure of discounted future net cash flows
|
| | | $ | 45,261,966 | | | | | $ | 69,211,827 | | | | | $ | 35,750,941 | | |
| | |
2021
|
| |
2022
|
| |
2023
|
| |||||||||
Standardized measure at beginning of year
|
| | | $ | 12,821,162 | | | | | $ | 45,261,966 | | | | | $ | 69,211,827 | | |
Net proceeds to the Trust
|
| | | | (12,078,886) | | | | | | (27,204,589) | | | | | | (18,068,560) | | |
Net changes in price and production costs
|
| | | | 28,017,592 | | | | | | 39,987,484 | | | | | | (21,474,622) | | |
Changes in estimated future development costs
|
| | | | (289,926) | | | | | | (124,022) | | | | | | 334,663 | | |
Development costs incurred during the year
|
| | | | 1,002,600 | | | | | | 454,500 | | | | | | 188,000 | | |
Revisions of quantity estimates
|
| | | | 15,737,944 | | | | | | 4,463,154 | | | | | | 723,212 | | |
Accretion of discount
|
| | | | 1,282,116 | | | | | | 4,526,197 | | | | | | 6,921,183 | | |
Changes in production rates, timing and other(1)
|
| | | | (1,230,636) | | | | | | 1,847,137 | | | | | | (2,084,762) | | |
Standardized measure at end of year
|
| | | $ | 45,261,966 | | | | | $ | 69,211,827 | | | | | $ | 35,750,941 | | |
| | |
2021
|
| |
2022
|
| |
2023
|
| |||||||||
Oil (per Bbl)
|
| | | $ | 62.06 | | | | | $ | 89.17 | | | | | $ | 73.72 | | |
Gas (per Mcf)
|
| | | $ | 2.91 | | | | | $ | 6.10 | | | | | $ | 2.41 | | |
NGL (per Bbl)
|
| | | $ | 21.23 | | | | | $ | 37.47 | | | | | $ | 31.29 | | |
Beneficial Owner
|
| |
Trust Units
Beneficially Owned |
| |
Percent of
Class(1) |
| ||||||
MV Energy, LLC(2)
|
| | | | 2,875,000 | | | | | | 25.0% | | |
VAP-I, LLC(2)
|
| | | | 1,437,500 | | | | | | 12.5% | | |
Robert J. Raymond(3)
|
| | | | 1,016,114 | | | | | | 8.8% | | |
| | |
2022
|
| |
2023
|
| ||||||
Audit fees
|
| | | $ | 237,771 | | | | | $ | 256,172 | | |
Audit-related fees
|
| | | | — | | | | | | — | | |
Tax fees
|
| | | | — | | | | | | — | | |
All other fees
|
| | | | — | | | | | | — | | |
Total fees
|
| | | $ | 237,771 | | | | | $ | 256,172 | | |
| | |
Page in this
Form 10-K |
| |||
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)
|
| | | | 49 | | |
Statements of Assets and Trust Corpus
|
| | | | 50 | | |
Statements of Distributable Income
|
| | | | 50 | | |
Statements of Changes in Trust Corpus
|
| | | | 50 | | |
Notes to Financial Statements
|
| | | | 51 | | |
Exhibit 31.1
CERTIFICATION
I, Elaina C. Rodgers, certify that:
1. | I have reviewed this annual report on Form 10-K of MV Oil Trust, for which The Bank of New York Mellon Trust Company, N.A. acts as Trustee; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this report; |
4. | I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 15(e)), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and I have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared; and |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors: |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report information; and |
(b) | Any fraud, whether or not material, that involves any persons who have a significant role in the registrant’s internal control over financial reporting. |
In giving the foregoing certifications in paragraphs 4 and 5, I have relied to the extent I consider reasonable on information provided to me by MV Partners, LLC.
Date: March 20, 2024
/s/ Elaina C. Rodgers | |
Elaina C. Rodgers | |
Vice President | |
The Bank of New York Mellon Trust Company, N.A., | |
Trustee for MV Oil Trust |
Exhibit 32.1
March 20, 2024
Via EDGAR
Securities and Exchange Commission
Judiciary Plaza
450 Fifth Street, N.W.
Washington, D.C. 20549
Re: | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
Ladies and Gentlemen:
In connection with the Annual Report of MV Oil Trust (the “Trust”) on Form 10-K for the year ended December 31, 2023 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:
(1) | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust. |
The above certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and is not being filed as part of the Report or as a separate disclosure document.
The Bank of New York Mellon Trust Company, N.A. | ||
Trustee for MV Oil Trust | ||
By: | /s/ Elaina C. Rodgers | |
Elaina C. Rodgers | ||
Vice President |
Exhibit 97.1
MV OIL TRUST
The Bank of New York Mellon Trust Company, N.A., as Trustee
CLAWBACK POLICY
Purpose
The purpose of this Clawback Policy (the “Policy”) of MV Oil Trust (the “Trust”) is to provide for the recoupment of Erroneously Awarded Compensation from Covered Executives in the event of an Accounting Restatement. This Policy is designed to comply with Section 10D of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), Rule 10D-1 promulgated under the Exchange Act, and Section 303A.14 of the New York Stock Exchange Listed Company Manual (collectively, the “Clawback Listing Standards”).
The Amended and Restated Trust Agreement dated as of January 24, 2007 (as amended to date, the “Trust Agreement”) that governs the Trust currently does not authorize the payment of Incentive-Based Compensation to the Trustee or any officers or employees of the Trustee; this Policy therefore shall be applicable to any Incentive-Based Compensation that may be paid pursuant to authority granted under a future amendment to the Trust Agreement.
Unless otherwise defined in this Policy, capitalized terms shall have the meaning ascribed to such terms in the section entitled “Definitions” below.
Definitions
As used in this Policy, the following capitalized terms shall have the meanings set forth below.
“Accounting Restatement” means an accounting restatement of the Trust’s financial statements due to the Trust’s material noncompliance with any financial reporting requirement under the securities laws, including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements (i.e., a “Big R” restatement), or to correct an error that is not material to the previously issued financial statements, but that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period (i.e., a “little r” restatement).
“Accounting Restatement Date” means the earlier to occur of (i) the date the Trustee concludes, or reasonably should have concluded, that the Trust is required to prepare an Accounting Restatement and (ii) the date a court, regulator, or other legally authorized body directs the Trust to prepare an Accounting Restatement.
“Applicable Period” means, with respect to any Accounting Restatement, the three completed fiscal years immediately preceding the Accounting Restatement Date, as well as any transition period (that results from a change in the Trust’s fiscal year) within or immediately following those three completed fiscal years (except that a transition period that comprises a period of at least nine months shall count as a completed fiscal year).
“Commission” means the U.S. Securities and Exchange Commission.
“Covered Executives” means any current and former officers and employees of the Trustee who perform or performed, as applicable, significant policy-making functions for the Trust, as determined by the Trustee in accordance with the definition in Section 10D of the Exchange Act and the Clawback Listing Standards.
“Erroneously Awarded Compensation” means, in the event of an Accounting Restatement, the amount of Incentive-Based Compensation previously received that exceeds the amount of Incentive-Based Compensation that otherwise would have been received had it been determined based on the restated amounts in such Accounting Restatement, and must be computed without regard to any taxes paid by the relevant Covered Executive.
“Financial Reporting Measure” means any measure that is determined and presented in accordance with the accounting principles used in preparing the Trust’s financial statements and any measure that is derived wholly or in part from such measure. A Financial Reporting Measure is not required to be presented within the Trust’s financial statements or included in a filing with the Commission to qualify as a “Financial Reporting Measure.”
“Incentive-Based Compensation” means any compensation paid by the Trust that is granted, earned, or vested based wholly or in part upon the attainment of a Financial Reporting Measure. Incentive-Based Compensation is deemed “received” for purposes of this Policy in the Trust’s fiscal period during which the Financial Reporting Measure specified in the Incentive-Based Compensation award is attained, even if the payment or grant of such Incentive-Based Compensation occurs after the end of that period.
Administration
This Policy shall be administered by The Bank of New York Mellon Trust Company, N.A., as trustee (the “Trustee”) of the Trust. Any determinations made by the Trustee shall be final and binding on all affected individuals.
Application of This Policy
This Policy applies to all Incentive-Based Compensation received by a person: (a) after beginning service as a Covered Executive; (b) who served as a Covered Executive at any time during the performance period for such Incentive-Based Compensation; (c) while the Trust had a listed class of securities on a national securities exchange; and (d) during the Applicable Period. For the avoidance of doubt, Incentive-Based Compensation that is subject to both a Financial Reporting Measure vesting condition and a service-based vesting condition shall be considered received when the relevant Financial Reporting Measure is achieved, even if the Incentive-Based Compensation continues to be subject to the service-based vesting condition.
For the avoidance of doubt, this Policy is intended to apply only to Incentive-Based Compensation paid by or on behalf of the Trust out of proceeds received by the Trust pursuant to the terms of the Trust Agreement and the Conveyance of Net Profits Interest dated as of January 24, 2007, as amended to date. This Policy shall not apply to any compensation paid by The Bank of New York Mellon Trust Company, N.A., in its own capacity and not in its capacity as Trustee of the Trust, to any directors, officers or employees of The Bank of New York Mellon Trust Company, N.A. or any of its subsidiaries.
2
Recovery of Erroneously Awarded Compensation
In the event of an Accounting Restatement, the Trust must recover Erroneously Awarded Compensation reasonably promptly, in amounts determined pursuant to this Policy. The Trust’s obligation to recover Erroneously Awarded Compensation is not dependent on the filing of restated financial statements. Recovery under this Policy with respect to a Covered Executive shall not require the finding of any misconduct by such Covered Executive or such Covered Executive being found responsible for the accounting error leading to an Accounting Restatement. In the event of an Accounting Restatement, the method for recouping Erroneously Awarded Compensation shall be determined by the Trustee in its sole and absolute discretion, to the extent permitted under the Clawback Listing Standards and in compliance with (or pursuant to an exemption from the application of) Section 409A of the U.S. Internal Revenue Code of 1986, as amended. Recovery may include, without limitation, (i) reimbursement of all or a portion of any incentive compensation award, (ii) cancellation of incentive compensation awards and (iii) any other method authorized by applicable law or contract.
Prohibition on Indemnification and Insurance Reimbursement
The Trust shall not indemnify any Covered Executives against the loss of any Erroneously Awarded Compensation. Further, the Trust is prohibited from paying or reimbursing a Covered Executive for the cost of purchasing insurance to cover any such loss. The Trust is also prohibited from entering into any agreement or arrangement whereby this Policy would not apply or fail to be enforced against a Covered Executive.
Interpretation
The Trustee is authorized to interpret and construe this Policy and to make all determinations necessary, appropriate, or advisable for the administration of this Policy. It is intended that this Policy be interpreted in a manner that is consistent with the requirements of Section 10D of the Exchange Act, any applicable rules or standards adopted by the Commission, and the Clawback Listing Standards.
Required Policy-Related Disclosure and Filings
The Trust shall file all disclosures with respect to this Policy in accordance with the requirements of the federal securities laws, including disclosures required in Commission filings. A copy of this Policy and any amendments hereto shall be filed as an exhibit to the Trust’s Annual Report on Form 10-K.
Effective Date
This Policy shall be effective as of December 1, 2023 (the “Effective Date”) and shall apply to Incentive-Based Compensation that is received by Covered Executives on or after October 2, 2023, even if such Incentive-Based Compensation was approved, awarded, or granted to Covered Executives prior to such date.
3
Amendment; Termination
The Trustee may amend this Policy from time to time in its discretion and shall amend this Policy as it deems necessary to reflect final regulations adopted by the Commission under Section 10D of the Exchange Act and to comply with the Clawback Listing Standards and any other rules or standards adopted by a national securities exchange on which the Trust’s securities are listed. The Trustee may terminate this Policy at any time; provided, that the termination of this Policy would not cause the Trust to violate any federal securities laws, or rules promulgated by the Commission or the Clawback Listing Standards.
Other Recoupment Rights
Any right of recoupment under this Policy is in addition to, and not in lieu of, any other remedies or rights of recoupment that may be available to the Trust pursuant to the terms of any similar policy in any employment agreement, equity award agreement, or similar agreement and any other legal remedies available to the Trust.
Relationship to Other Plans and Agreements
The Trustee intends that this Policy will be applied to the fullest extent of the law. The Trustee may require that any employment agreement, equity award agreement, or similar agreement entered into on or after the Effective Date shall, as a condition to the grant of any benefit thereunder, require a Covered Executive to agree to abide by the terms of this Policy. In the event of any inconsistency between the terms of the Policy and the terms of any employment agreement, equity award agreement, or similar agreement under which Incentive-Based Compensation has been granted, awarded, earned or paid to a Covered Executive, whether or not deferred, the terms of the Policy shall govern.
Impracticability
The Trustee shall recover any excess Incentive-Based Compensation in accordance with this Policy unless such recovery would be impracticable, as determined by the Trustee in accordance with Rule 10D-1 of the Exchange Act and the listing standards of the national securities exchange on which the Trust’s securities are listed.
Successors
This Policy shall be binding and enforceable against all Covered Executives and their beneficiaries, heirs, executors, administrators or other legal representatives.
4
Exhibit 99.1
Cawley, Gillespie & Associates, Inc.
petroleum consultants
6500 RIVER PLACE BLVD, BLDG 3, SUITE 200 | 306 WEST SEVENTH STREET, SUITE 302 | 1000 LOUISIANA STREET, SUITE 1900 | ||
AUSTIN, TEXAS 78730 | FORT WORTH, TEXAS 76102 | HOUSTON, TEXAS 77002 | ||
512-249-7000 | 817- 336-2461 | 713-651-9944 | ||
www.cgaus.com |
March 16, 2024
Bank of New York Mellon Trust Company, N.A.
as Trustee of MV Oil Trust
Attn: Elaina C. Rodgers
919 Congress Avenue
Austin, Texas 78701
Re: | Evaluation Summary | Pursuant to the Guidelines of the | |
MV Oil Trust Net Profits Interests | Securities and Exchange Commission for | ||
Total Proved Reserves | Reporting Corporate Reserves and | ||
Certain Oil and Gas Assets – KS & CO | Future Net Revenue | ||
As of December 31, 2023 |
Ladies and Gentlemen:
As requested, this report was prepared on March 16, 2024 for MV Oil Trust (“Trust”) for the purpose of submitting our estimates of total proved reserves and forecasts of economics attributable to the Trust term net profits interests. We evaluated 100% of the Company’s reserves, which are associated with certain oil and gas properties in Kansas and Colorado. This evaluation, effective December 31, 2023, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). A composite summary of the proved reserves is presented below:
Proved | Proved | |||||||||||||||||||
Developed | Developed | Proved | Total | |||||||||||||||||
Producing | Non-Producing | Undeveloped | Proved | |||||||||||||||||
Net Reserves | ||||||||||||||||||||
Oil | - MBBL | 1,330.0 | 6.9 | 17.4 | 1,354.3 | |||||||||||||||
Gas | - MMCF | 44.0 | 0.0 | 0.0 | 44.0 | |||||||||||||||
NGL | - MBBL | 0.2 | 0.0 | 0.0 | 0.2 | |||||||||||||||
MBOE | - MBBL | 1,337.5 | 6.9 | 17.4 | 1,361.8 | |||||||||||||||
Revenue | ||||||||||||||||||||
Oil | - M$ | 98,045.9 | 511.6 | 1,282.7 | 99,840.2 | |||||||||||||||
Gas | - M$ | 105.8 | 0.0 | 0.0 | 105.8 | |||||||||||||||
NGL | - M$ | 6.9 | 0.0 | 0.0 | 6.9 | |||||||||||||||
Severance Taxes | - M$ | 580.4 | 23.1 | 58.0 | 661.6 | |||||||||||||||
Ad Valorem Taxes | - M$ | 2,300.9 | 30.7 | 77.0 | 2,408.5 | |||||||||||||||
Operating Expenses | - M$ | 46,176.9 | 19.2 | 187.0 | 46,383.1 | |||||||||||||||
Future Development Costs | - M$ | 0.0 | 250.0 | 340.0 | 590.0 | |||||||||||||||
Future Net Cash Flow | - M$ | 39,280.4 | 150.8 | 496.6 | 39,927.8 | |||||||||||||||
Discounted @ 10% | - M$ | 35,199.8 | 123.2 | 427.9 | 35,750.9 | |||||||||||||||
(Present Worth) |
Future revenue was calculated prior to deducting state production taxes and ad valorem taxes; however, future net cash flow was calculated after deducting these taxes, future development costs, and operating expenses, but before federal income taxes. Future net cash flow has been discounted at an annual rate of ten (10) percent, in accordance with SEC guidelines, to determine net present worth. Present worth indicates the time value of money and should not be construed as being fair market value.
The oil reserves include oil and condensate. Oil and natural gas liquid (“NGL”) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (“MCF”) at contract temperature and pressure base. Barrels of oil equivalent (“BOE”) is expressed as oil and NGL volumes in barrels plus gas volumes in Mcf divided by six (6) to convert to barrels. Our estimates include proved reserves only. Neither probable or possible reserves, nor interest in acreage beyond the location of proven reserves have been estimated.
Proved Developed reserves are the summation of the Proved Developed Producing and Proved Developed Non-Producing reserve estimates. Proved Developed reserves were estimated at 1,336.9 Mbbl oil, 44.0 MMcf gas and 0.2 Mbbl NGLs (or 1,344.4 MBOE). Of the Proved Developed reserves, 1,337.5 MBOE were attributed to producing zones in existing wells and 6.9 MBOE were attributed to zones in existing wells not producing.
Net Profits Calculations
The net profits interests entitle the Trust to receive 80% of the net proceeds from the sale of hydrocarbon production within the Company underlying properties. The net profits interests will terminate on the later to occur of (1) June 30, 2026, or (2) the time when 14.4 MMBOE have been produced from the underlying properties and sold, and the trust will soon thereafter wind up its affairs and terminate. For this report, it was estimated that the Trust would terminate June 30, 2026 based on the calculation that 14.4 MMBOE would be produced from the underlying properties and sold (which amount is the equivalent of 11.5 MMBOE in respect of the trust’s right to receive 80% of the net proceeds from the underlying properties pursuant to the net profits interest) by February 29, 2024. The cash flow tables in this report reflect the termination date of June 30, 2026.
Hydrocarbon Pricing
The base SEC oil and gas prices calculated for year end 2023 were $78.22/bbl and $2.637/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot market prices during 2023 and the base gas price is based upon Henry Hub spot market prices during 2023.
Oil price differentials were forecast at -$4.50 per BBL for all properties. Gas price and NGL price differentials varied by property. The base price differentials may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $73.72/BBL for oil, $2.406/MMBTU for gas, and $31.29/BBL for NGLs. All economic factors were held constant in accordance with SEC guidelines.
Economic Parameters
Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, lease operating expenses (LOE), workover expenses, overhead expenses, and future development costs were calculated and prepared by you and were thoroughly reviewed by us for accuracy and completeness. LOE (column 22) and overhead (COPAS, column 26) were determined at the well level using averages determined from historical lease operating statements. Workover Expenses (column 25) were applied to cover the annual costs for recurring well work and wellbore abandonment. All economic parameters, including expenses and future development costs, were held constant (not escalated) throughout the life of these properties.
Severance tax rates were applied at normal state percentages of oil, gas and NGL revenue, except for those Kansas producing properties that are severance tax exempt. Ad valorem taxes of 2.0% of total revenue were applied to each property as provided by your office. Oil and gas conservation tax rates were applied to all Kansas properties at current rates of $0.144 per BBL and $0.0205 per MCF, respectively.
Reserve Estimation Methods
The methods employed in estimating reserves are described in page two (2) of the Appendix. We evaluated 849 PDP properties for this report, most with monthly production data typically updated through 10/31/2023, as provided by the Company. Certain PDP properties consist of multiple-well leases. Reserves for PDP wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.
Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting PDNP and PUD reserves for the Company properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
SEC Conformance and Regulations
The reserve classifications and the economic considerations used herein for the SEC pricing scenario conform to the criteria of the SEC as defined in pages three (3) and four (4) of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
This evaluation includes four (4) PUD locations based in various fields throughout Kansas, which includes a mix of new drills, deepenings, workovers and recompletions. Certain PUD properties consist of multiple development locations. Each of the drilling locations proposed as part of the Company development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the Company has indicated they have intent to complete this development plan within the next five (5) years. Furthermore, the Company has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five (5) year development plan will be fully executed.
General Discussion
The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have been included as part of the workover expenses described previously.
Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. This evaluation was supervised by W. Todd Brooker, President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties or MV Partners, LLC or MV Oil Trust and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office. We consent to the filing of this report as an exhibit to the Annual Report on Form 10-K of MV Oil Trust for the year end December 31, 2023. This report, issued March 16, 2024, supersedes any prior CGA report for MV Oil Trust with an effective date of December 31, 2023.
Yours very truly, | |
W. Todd Brooker, P.E. | |
President | |
CAWLEY, GILLESPIE & ASSOCIATES, INC. | |
Texas Registered Engineering Firm (F-693) |
APPENDIX
Methods Employed in the Estimation of Reserves
The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:
Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.
Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.
Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.
Analogy. This method, which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method may also be applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained in this manner are generally considered to have a relatively low degree of accuracy.
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.
APPENDIX
Reserve Definitions and Classifications
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
“(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
“(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
“(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
“(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
“(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
“(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S-K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
“(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”
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