Item 2. Properties
Item 2.
Properties
The net overriding royalties conveyed to the Trust (the Royalties) include: (1) a 75% net overriding royalty carved out of
Southland Royaltys fee mineral interests in the Waddell Ranch in Crane County, Texas (the Waddell Ranch properties); and (2) a 95% net overriding royalty carved out of Southland Royaltys major producing royalty interests
in Texas (the Texas Royalty properties). The interests out of which the Trusts net overriding royalty interests were carved were in all cases less than 100%. The Trusts net overriding royalty interests represent burdens
against the properties in favor of the Trust without regard to ownership of the properties from which the overriding royalty interests were carved. The net overriding royalty for the Texas Royalty properties is subject to the provisions of the lease
agreements under which such royalties were created. References below to net wells and acres are to the interests of the owner of the Underlying Properties (from which the Royalties were carved) in the gross wells and acres.
A production index for oil and gas properties is the number of years derived by dividing remaining reserves by current production. The
production index for the Trust properties based on the reserve report prepared by independent petroleum engineers as of December 31, 2023, is approximately 15 years.
The following information under this Item 2 is based upon data and information, including audited computation statements, furnished to the
Trustee by Blackbeard, the owner of the Waddell Ranch properties, and Riverhill Energy, the owner of the Texas Royalty properties.
PRODUCING ACREAGE, WELLS AND DRILLING
Waddell Ranch Properties . The net profits/overriding royalty interest in the Waddell Ranch properties is the largest asset of the
Trust. The mineral interests in the Waddell Ranch, from which such net royalty interests are carved, vary from 37.5% (Trust net interest) to 50% (Trust net interest) in 78,715 gross (34,205 net) producing acres. A majority of the proved reserves are
attributable to six fields: Dune, Sand Hills (Judkins), Sand Hills (McKnight), Sand Hills (Tubb), University-Waddell (Devonian) and Waddell. At December 31, 2023, the Waddell Ranch properties contained 1,067 gross (499 net) productive oil wells
and 108 gross (51 net) productive gas wells.
As of April 1, 2020, Blackbeard Operating, LLC (Blackbeard) became operator
of record of the Waddell Ranch properties. All field, technical and accounting operations have been contracted by agreements between the working interest owners and Schlumberger Integrated Project Management (IPM) and Riverhill Capital
Corporation (Riverhill Capital), but remain under the direction of Blackbeard, as of December 31, 2023.
Six major fields
on the Waddell Ranch properties account for more than 80% of the total production. In the six fields, there are 12 producing zones ranging in depth from 2,800 to 10,600 feet. Most prolific of these zones are the Grayburg and San Andres, which
produce from depths between 2,800 and 3,400 feet. Also productive from the San Andres are the Sand Hills (Judkins) gas field and the Sand Hills (McKnight) oil field, the Dune (Grayburg/San Andres) oil field, and the Waddell (Grayburg/San Andres) oil
field.
The Dune and Waddell oil fields are productive from both the Grayburg and San Andres formations. The Sand Hills (Tubb) oil fields
produce from the Tubb formation at depths averaging 4,300 feet, and the University Waddell (Devonian) oil field is productive from the Devonian formation between 8,400 and 9,200 feet.
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The Waddell Ranch properties are mature producing properties, and all of the major oil
fields are currently being waterflooded for the purpose of facilitating enhanced recovery. Proved reserves and estimated future net revenues attributable to the properties are included in the reserve reports summarized below. The owner of the
Underlying Properties for Waddell Ranch does not own the full working interest in any of the tracts constituting the Waddell Ranch properties and, therefore, implementation of any development programs will require approvals of other working interest
holders as well as the owner of the Underlying Properties. In addition, implementation of any development programs will be dependent upon oil and gas prices currently being received and anticipated to be received in the future. There were 28.9 new
drill wells (net) completed on the Waddell Ranch properties during 2023. At December 31, 2023, there were 3 gross (1.1 net) drill wells and 5 gross (1.9 net) workover in progress on the Waddell Ranch properties. There were 46.1 net drill wells
completed on the Waddell Ranch properties during 2022. At December 31, 2022, there were 46.9 drill wells and 38.7 workover in progress on the Waddell Ranch properties. There were 79 gross (30 net) drill wells completed on the Waddell Ranch
properties during 2021. At December 31, 2021, there were 11 drill wells and 11 workover in progress on the Waddell Ranch properties.
Blackbeard has advised the Trustee that the total amount of capital expenditures for 2023 with regard to the Waddell Ranch properties totaled
$135 million (gross). Capital expenditures include the cost of remedial and maintenance activities. The amount spent on remedial and maintenance activities is approximately $19 million of the amount expended by Blackbeard in 2023.
Blackbeard has advised the Trustee that the capital expenditures budget for 2024 has not been finalized; however, Blackbeard provided the
Trustee with a preliminary capital expenditures budget of approximately $301 million (gross) and development plan reflecting the number of wells it expects to drill in 2024. Blackbeard has advised the Trustee there are expected to be 95 new drill
wells and 24 recompletions in 2024 as compared to 77 new drill wells (gross) and 142 recompletion (gross) in 2023
The Trustee has been
advised that, effective November 1, 2019, BROG sold its interests in the Waddell Ranch properties to Blackbeard. In conjunction with the transfer and assignment of the Waddell Ranch properties, BROG also assigned to Blackbeard all of its
rights, title and interest in and to the Net Overriding Royalty Conveyance (Permian Basin Royalty Trust - Waddell Ranch) dated November 1, 1980. BROG handled all operations and accounting on behalf of
Blackbeard until March 31, 2020.
Texas Royalty Properties . The Texas Royalty properties consist of royalty interests in
mature producing oil fields, such as Yates, Wasson, Sand Hills, East Texas, Kelly-Snyder, Panhandle Regular, N. Cowden, Todd, Keystone, Kermit, McElroy, Howard-Glasscock, Seminole and others located in 33 counties across Texas. The Texas Royalty
properties consist of approximately 125 separate royalty interests containing approximately 303,000 gross (approximately 51,000 net) producing acres. Approximately 39% of the future net revenues discounted at 10% attributable to Texas Royalty
properties are located in the Wasson and Yates fields. Detailed information concerning the number of wells on royalty properties is not generally available to the owners of royalty interests. Consequently, an accurate count of the number of wells
located on the Texas Royalty properties cannot readily be obtained.
In February 1997, BROG sold its interests in the Texas Royalty
properties that are subject to the Net Overriding Royalty Conveyance to the Trust dated effective November 1, 1980 (Texas Royalty Conveyance) to Riverhill Energy Corporation (Riverhill Energy), which was then a
wholly-owned subsidiary of Riverhill Capital and an affiliate of Coastal Management Corporation (CMC). The Trustee was informed by BROG that, as required by the Texas Royalty Conveyance, Riverhill Energy succeeded to all of the
requirements upon, and the responsibilities of BROG under, the Texas Royalty Conveyance with regard to the Texas Royalty properties. BROG and Riverhill Energy further advised the Trustee that all accounting operations pertaining to the Texas Royalty
properties were being performed by Riverhill Energy.
The Trustee has been advised that, effective April 1, 1998, Schlumberger
Technology Corporation (STC) acquired all of the shares of stock of Riverhill Capital. Prior to the acquisition by STC, CMC and Riverhill Energy were wholly-owned subsidiaries of Riverhill Capital. The Trustee has further been advised,
in accordance with the STC acquisition of Riverhill Capital, the shareholders of Riverhill Capital acquired ownership of all shares of stock of Riverhill Energy.
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Effective January 1, 2001 CMC merged into STC. Thus, the ownership in the Texas Royalty properties remained in Riverhill Energy.
The Trustee has been advised that as of May 1, 2000, the accounting operations pertaining to the Texas Royalty properties were
transferred from STC to Riverhill Energy.
Well Count and Acreage Summary . The following table shows as of December 31, 2023,
the gross and net producing wells and acres for the Blackbeard interests on the Waddell Ranch. The net wells and acres are determined by multiplying the gross wells or acres by the Blackbeard interests owners working interest in the wells or
acres as of December 31, 2023. Similar information is not available for the Riverhill Energy interests.
NUMBER OF WELLS
ACRES
Gross
Net
Gross
Net
Blackbeard Interests
1067
499
78,715
34,205
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OIL AND GAS PRODUCTION
The Trust recognizes production during the month in which the related distribution is received. Production of oil and gas attributable to the
Royalties and the Underlying Properties, the related average sales prices and the average production cost per unit of production attributable to the Underlying Properties for the three years ended December 31, 2023, excluding portions
attributable to the adjustments discussed below, were as follows:
Waddell Ranch
Properties
Texas Royalty
Properties
Total
2023
2022
2021
2023
2022
2021
2023
2022
2021
Royalties:
Production
Oil (barrels)
2,086,029
1,554,038
775,230
191,278
206,433
191,876
2,277,307
1,760,471
967,106
Gas (Mcf)
11,949,062
9,346,780
3,754,386
225,634
114,307
122,262
12,174,696
9,461,087
3,876,648
Underlying Properties:
Production
Oil (barrels)
2,781,372
2,072,051
1,033,640
213,525
225,514
215,710
2,994,897
2,297,565
1,249,350
Gas (Mcf)
15,932,082
12,462,373
5,005,848
251,846
124,670
137,578
16,183,928
12,587,044
5,143,426
Average Sales Price
Oil/barrel
$
76.71
$
94.38
$
64.17
$
76.91
$
91.64
$
59.34
$
76.72
$
94.11
$
63.34
Gas/Mcf
$
2.37
$
5.48
$
3.45
$
4.60
$
10.89
$
6.59
$
2.40
$
5.54
$
3.53
Average Production Cost Oil/Gas BOE
$
20.59
$
17.58
$
17.71
$
6.95
$
6.81
$
5.36
$
19.98
$
16.82
$
16.01
Since the oil and gas sales attributable to the Royalties are based on an allocation formula that is dependent
on such factors as price and cost (including capital expenditures), production amounts do not necessarily provide a meaningful comparison.
Waddell Ranch properties lease operating expense for 2023 was $80 million (gross). The lease operating expense increased from
$44 million (gross) in 2022 primarily because of increasing activity and facilities maintenance. Waddell Ranch lifting cost on a barrel of oil equivalent (BOE) basis was $20.59 bbl as compared to $17.58 in 2022 and $17.71 in 2021.
PRICING INFORMATION
Reference is made to the caption entitled Regulation for information as to federal regulation of prices of natural gas. The
following paragraphs provide information regarding sales of oil and gas from the Waddell Ranch properties. As a royalty owner, Riverhill Energy is not furnished detailed information regarding sales of oil and gas from the Texas Royalty properties.
Oil. The Trustee has been advised by the operator that the majority of oil from the Waddell Ranch is now pipeline connected
and sold under long term crude purchase agreements.
Gas. The trustee has been advised by the operator that the majority of
gas produced from Waddell Ranch properties is processed through Targa Resources Corporation Midway processing plant. Both residue gas and plant products are purchased by Targa who receives fees (gathering, compression, treating, processing) and a
percentage of the gas and liquids as compensation.
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OIL AND GAS RESERVES
The following are definitions adopted by the SEC and the Financial Accounting Standards Board which are applicable to terms used within this
Item:
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 produciblefrom a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulationsprior 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 the
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.
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.
Estimated future net revenues are computed by applying average prices during the 12-month
period prior to fiscal year-end determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month
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within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions to estimated future production of proved oil and gas reserves as of
the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, and assuming continuation of existing economic conditions. Estimated
future net revenues are sometimes referred to herein as estimated future net cash flows.
Present value of estimated future
net revenues is computed using the estimated future net revenues and a discount factor of 10%.
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.
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 17 CFR 210.4-10(a)(2), or by other evidence using reliable technology establishing reasonable certainty.
The process of estimating oil and gas reserves is complex and requires significant judgment. As a result, the Trustee has developed internal
policies and controls for estimating reserves. As described above, the Trust does not have information that would be available to a company with oil and gas operations because detailed information is not generally available to owners of royalty
interests. The Trustee gathers production information (which information is net to the Trusts interests in the Underlying Properties) and provides such information to Cawley, Gillespie & Associates, Inc., who extrapolates from such
information estimates of the reserves attributable to the Underlying Properties based on its expertise in the oil and gas fields where the Underlying Properties are situated, as well as publicly available information. The Trusts policies
regarding reserve estimates require proved reserves to be in compliance with the SEC definitions and guidance.
The independent petroleum
engineers reports as to the proved oil and gas reserves attributable to the Royalties conveyed to the Trust were prepared by Cawley, Gillespie & Associates, Inc. (CG&A). CG&A, whose firm registration number is F-693, was founded in 1961 and is nationally recognized in the evaluation of oil and natural gas properties. The technical person at CG&A primarily responsible for overseeing the reserves estimates with respect
to the Trust is Zane Meekins. Mr. Meekins has been a practicing petroleum engineering consultant since 1989 with over 36 years of practice experience in petroleum engineering, and is a registered professional engineer in the State of Texas
(License No. 71055). Mr. Meekins graduated from Texas A&M University in 1987, S umma Cum Laude , with a B.S. degree in Petroleum Engineering. Both CG&A and Mr. Meekins have indicated that they meet or exceed all
requirements set forth in Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
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Table of Contents
Cawley, Gillespie & Associates, Inc.s reports are attached as exhibits to
this Form 10-K. The following table presents a reconciliation of proved reserve quantities from January 1, 2021 through December 31, 2023 (in thousands):
Waddell Ranch
Properties
Texas Royalty
Properties
Total
Oil
(Bbls)
Gas
(Mcf)
Oil
(Bbls)
Gas
(Mcf)
Oil
(Bbls)
Gas
(Mcf)
January 1, 2021
1,470
4,800
2,980
1,598
4,450
6,398
Extensions, discoveries, and other additions
1,309
2,123
1,309
2,123
Revisions of previous estimates
1,982
6,611
(151
)
9
1,831
6,620
Production
(775
)
(3,754
)
(192
)
(122
)
(967
)
(3,877
)
December 31, 2021
3,986
9,780
2,637
1,485
6,623
11,264
Extensions, discoveries, and other additions
3,714
5,206
3,914
5,206
Revisions of previous estimates
2,747
18,778
229
(50
)
2,976
(18,728
)
Production
(1,554
)
(9,347
)
(206
)
(114
)
(1,760
)
(9,461
)
December 31, 2022
8,893
24,417
2,660
1,321
11,553
25,737
Extensions, discoveries, and other additions
4,504
8,064
4,504
8,064
Revisions of previous estimates
(2,137
)
5,084
20
2,052
(2,118
)
7,137
Production
(2,086
)
(11,949
)
(191
)
(226
)
(2,277
)
(12,175
)
December 31, 2023
9,174
25,616
2,489
3,147
11,662
28,763
Estimated quantities of proved reserves and net cash flow as of December 31, 2023 are as follows:
Waddell Ranch
Properties
Oil
(Mstb)
Gas
(Mcf)
Net Cash
Flow, M$
10% Disc.
Cash
Flow, M$
Proved Developed Producing
4,670
17,552
$
367,757
$
240,731
Proved Developed Non-Producing
77
302
$
6,126
$
2,748
Proved Developed
4,747
17,854
$
373,883
$
243,479
Proved Undeveloped
4,427
7,762
$
333,160
$
182,862
Total Proved
9,174
25,616
$
707,043
$
426,341
Texas Royalty
Properties
Oil
(Mstb)
Gas
(Mcf)
Net Cash
Flow, M$
10% Disc.
Cash
Flow, M$
Proved Developed Producing
2,489
3,147
$
190,372
$
82,208
Proved Developed
2,489
3,147
$
190,372
$
82,208
Total Proved
2,489
3,147
$
190,372
$
82,208
Total Waddell Ranch Plus Texas Royalty(1)
Properties
Oil
(Mstb)
Gas
(Mcf)
Net Cash
Flow, M$
10% Disc.
Cash
Flow, M$
Proved Developed Producing
7,158
20,698
$
558,128
$
322,938
Proved Developed Non-Producing
77
303
$
6,126
$
2,748
Proved Developed
7,235
21,001
$
564,254
$
325,686
Proved Undeveloped
4,427
7,762
$
333,160
$
182,862
Total Proved
11,662
28,763
$
897,414
$
508,548
(1)
Totals do not add due to rounding.
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Estimated quantities of proved undeveloped reserves of oil and gas on the Waddell Ranch
properties as of December 31, 2023 were calculated based on a preliminary development plan and budget provided by Blackbeard. Any change in the budget or development plan by Blackbeard could result in a change in the estimated quantities of
proved undeveloped reserves.
Estimated quantities of proved developed reserves of oil and gas as of the dates indicated were as follows
(in thousands):
Proved Developed Reserves:
Oil
(Barrels)
Gas
(Mcf)
January 1, 2021
4,450
6,398
December 31, 2021
6,623
11,264
December 31, 2022
11,553
25,737
December 31, 2023
11,662
28,763
The SEC requires supplemental disclosures for oil and gas producers based on a standardized measure of
discounted future net cash flows relating to proved oil and gas reserve quantities. Under this disclosure, future cash inflows are computed by applying the average prices during the 12-month period prior to
fiscal year-end, determined as an unweighted arithmetic average of the
first-day-of-the-month benchmark price for each month within such period, unless prices
are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are only considered to the extent provided by contractual arrangements in existence at year end. The standardized measure of discounted
future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows relating to proved oil and gas reserves.
Estimates of proved oil and gas reserves are by their very nature imprecise. Estimates of future net revenue attributable to proved reserves
are sensitive to the unpredictable prices of oil and gas and other variables.
The 2023, 2022 and 2021 change in the standardized measure
of discounted future net cash revenues related to future royalty income from proved reserves attributable to the Royalties discounted at 10% is as follows (in thousands):
Waddell Ranch
Properties
Texas Royalty
Properties
Total
2023
2022
2021
2023
2022
2021
2023
2022
2021
January 1
$
579,453
$
188,329
$
33,852
$
107,013
$
71,528
$
46,239
$
686,467
$
259,857
$
80,091
Extensions, discoveries, and other additions
185,611
201,239
51,245
185,611
201,239
51,245
Accretion of discount
57,945
18,883
3,385
10,701
7,153
4,624
68,646
25,896
8,009
Revisions of previous estimates and other
(382,674
)
206,142
99,847
(20,491
)
47,662
32,470
(403,165
)
253,804
132,317
Royalty income
(13,995
)
(35,089
)
(15,016
)
(19,329
)
(11,806
)
(29,011
)
(54,418
)
(11,806
)
December 31
$
426,341
$
579,453
$
188,329
$
82,208
$
107,014
$
71,527
$
508,548
$
686,468
$
259,856
Average oil and gas prices of $78.22 per barrel and $2.64 per Mcf were used to determine the estimated future
net revenues from the Waddell Ranch properties and the Texas Royalty properties, respectively, at December 31, 2023. The downward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties are primarily due
to weaker pricing for oil and gas pricing. The Texas Royalty properties are revised downward due to weaker pricing for oil.
Average oil
and gas prices of $93.67 per barrel and $6.36 per Mcf were used to determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties, respectively, at December 31, 2022. The upward revisions of both
reserves and discounted future net cash flows for the Waddell Ranch properties are primarily due to stronger pricing for oil and by stronger gas pricing. The Texas Royalty properties are revised upward due to stronger pricing for oil.
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Average oil and gas prices of $66.56 per barrel and $3.65 per Mcf were used to determine the
estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties, respectively, at December 31, 2021. The downward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties
are primarily due to stronger pricing for oil and by stronger gas pricing. The Texas Royalty properties are revised upward due to stronger pricing for oil.
The following presents estimated future net revenue and the present value of estimated future net revenue attributable to the Royalties, for
each of the years ended December 31, 2023, 2022 and 2021 (in thousands):
2023
2022
2021
Estimated
Future Net
Revenue
Present
Value at
10%
Estimated
Future Net
Revenue
Present
Value at
10%
Estimated Future
Net Revenue
Present
Value at
10%
Total Proved
Waddell Ranch properties
$
707,043
$
426,341
$
955,195
$
579,454
$
297,181
$
188,329
Texas Royalty properties
190,372
82,208
250,033
107,014
167,968
71,527
Total
$
897,415
$
508,549
$
1,205,228
$
686,468
$
465,149
$
259,856
Reserve quantities and revenues shown in the preceding tables for the Royalties were estimated from
projections of reserves and revenue attributable to the combined Blackbeard, River Hill Energy and Trust interests in the Waddell Ranch properties and Texas Royalty properties. Reserve quantities attributable to the Royalties were estimated by
allocating to the Royalties a portion of the total estimated net reserve quantities of the interests, based upon gross revenue less production taxes. Because the reserve quantities attributable to the Royalties are estimated using an allocation of
the reserves, any changes in prices or costs will result in changes in the estimated reserve quantities allocated to the Royalties. Therefore, the reserve quantities estimated will vary if different future price and cost assumptions occur.
Proved reserve quantities are estimates based on information available at the time of preparation and such estimates are subject to change as
additional information becomes available. The reserves actually recovered and the timing of production of those reserves may be substantially different from the original estimate. Moreover, the present values shown above should not be considered as
the market values of such oil and gas reserves or the costs that would be incurred to acquire equivalent reserves. A market value determination would include many additional factors.
Detailed information concerning the number of wells on royalty properties is not generally available to the owner of royalty interests.
Consequently, the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate account of the number of wells located on the above royalty properties, the number of exploratory or
development wells drilled on the above royalty properties during the periods presented by this report, or the number of wells in process or other present activities on the above royalty properties, and the Registrant cannot readily obtain such
information.
REGULATION
Many aspects of the production, pricing, transportation and marketing of crude oil and natural gas are regulated by federal and state
agencies. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on affected members of the industry.
Exploration and production operations are subject to various types of regulation at the federal, tribal, state and local levels. Such
regulation includes requiring permits for the drilling and production of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing
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wells, controlling and remediating pollution from exploration and production activities, proper handling and disposal of waste generated from exploration and production operations, the surface
use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. Natural gas and oil operations are also subject to various conservation laws and regulations that regulate the size of drilling and spacing
units or proration units and the density of wells which may be drilled and unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum allowable production from natural gas and oil wells, generally
prohibit the venting and regulate the flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of natural gas and oil that can be produced, potentially to
raise prices, and to limit the number of wells or the locations which can be drilled.
Federal Natural Gas Regulation
The Federal Energy Regulatory Commission (the FERC) is primarily responsible for federal regulation of natural gas. The interstate
transportation and sale for resale of natural gas is subject to federal governmental regulation, including regulation of transportation and storage tariffs and various other matters, by the FERC. On August 8, 2005, Congress enacted the Energy
Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct the FERC to facilitate market transparency in the market for sale or transportation of physical
natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or the FERC rules, regulations or orders thereunder. Wellhead sales of domestic natural gas
are not subject to regulation. Consequently, sales of natural gas may be made at market prices, subject to applicable contract provisions.
Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline
transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and the FERC from 1985 to the present that affect the economics of natural gas production, transportation,
and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject
to the FERCs jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the
natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas industry. The ultimate impact of the rules and regulations issued by the FERC since 1985 cannot be predicted. In addition, many aspects of
these regulatory developments have not become final but are still pending judicial decisions and final decisions by the FERC.
New
proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. The Trust cannot predict when or if any such proposals might become effective, or
their effect, if any, on the Trust. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. Crude oil prices are
affected by a variety of factors. Since domestic crude price controls were lifted in 1981, the principal factors influencing the prices received by producers of domestic crude oil have been the pricing and production of the members of the
Organization of Petroleum Export Countries (OPEC).
On December 19, 2007, President Bush signed into law the Energy
Independence & Security Act of 2007 (PL 110 140). The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in
contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder.
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State Regulation
The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining drilling permits, the
method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rates of production may be regulated and the maximum daily production allowables from both oil and gas wells may be
established on a market demand or conservation basis, or both.
Local Regulation
Drilling for and production and transportation of crude oil and natural gas are also regulated by local authorities. Local laws may include
land use regulations, permitting requirements, and noise and traffic ordinances. Such regulation could increase drilling and production costs or create delays in development and production of the Underlying Properties.
Environmental Regulation
Companies in
the oil and gas industry are subject to stringent and complex federal, tribal, state and local laws and regulations governing the health and safety aspects of oil and gas operations, the management and discharge of materials into the environment, or
otherwise relating to environmental protection. Those laws and regulations may impose numerous obligations that are applicable to the operations of the Underlying Properties, including the acquisition of a permit before conducting drilling,
production or underground injection activities; the restriction on the types, quantities and concentrations of materials that can be emitted or released into the environment; the limitation or prohibition of drilling or other construction or
operational activities on certain lands lying within wilderness, wetlands, endangered or threatened species habitat, and other sensitive environments or protected areas; the installation of emission monitoring and/or pollution control equipment; the
reporting of the types and quantities of various substances that are generated, stored, processed, released, or disposed of in connection with operation of the Underlying Properties; the remediation of pollution from current or former operations,
such as cleanup of releases, pit closure, removal of surface equipment and plugging of abandoned wells; the sourcing and disposal of water used in the drilling, fracturing and completion processes; the planning and preparedness for spill and
emergency response activities; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from operations including waste generation, air emissions,
water discharges and current and historical waste disposal practices. Failure to comply with these laws and regulations may result in the adverse modification, suspension or revocation of necessary permits, licenses and authorizations; the
requirement that additional pollution controls be installed; the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all
of the operations. Under certain environmental laws and regulations, the operators of the Underlying Properties could also be subject to joint and several, strict liability for the removal or remediation of previously released materials or property
contamination, in either case, whether at a drilling or other operations site or a waste disposal facility, regardless of whether the operators were responsible for the release or contamination or if the operations were in compliance with all
applicable laws at the time those actions were taken.
In addition, climate change is the subject of an important public policy debate and
the basis for new legislation proposed by the United States Congress and certain states. President Biden has set ambitious goals related to mitigating climate change, including at least a 50 per cent reduction from 2005 levels in economy-wide
net greenhouse gas pollution by 2030. Some states have also adopted climate change statutes and regulations. In response to the April 2007 U.S. Supreme Court decision in Massachusetts vs. EPA finding that greenhouse gases (GHGs)
are air pollutants under the Clean Air Act (CAA), the United States Environmental Protection Agency (the EPA) issued an Endangerment Finding under Section 202(a) of the CAA, concluding that GHG pollution
threatens the public health and welfare of future generations. Thereafter, EPA promulgated GHG monitoring and reporting regulations that, since 2011, have required annual reporting of carbon dioxide, methane and nitrous oxide emissions from certain
sources in the oil and natural gas industry sector, including in the onshore oil and natural gas production segment. The EPA indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG emission
limits. More recently, in August 2022, Congress passed the Inflation Reduction Act, which includes requirements to impose fees beginning in 2025 on methane emissions from oil and gas operations that are required to report their GHG emissions
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under the EPAs GHG Reporting Rule. EPAs proposed rule to implement the fee requirements, Waste Emissions Charge for Petroleum and Natural Gas Systems was published on
January 26, 2024, with comments due by March 11, 2024.
Pursuant to the CAA and state laws concerning the permitting of air
emissions, certain new and modified sources of air emissions are subject to air permitting authorizations for construction and operation, and sources of air emissions at the Underlying Properties are no exception to these requirements. In addition
to air permitting requirements, certain sources of emissions involved in oil and gas operations are subject to source-specific emission standards pursuant to CAA New Source Performance Standards (NSPS) and National Emissions Standards
for Hazardous Air Pollutants (NESHAPS). For example, on August 16, 2012, the EPA issued a final rule, known as NSPS Subpart OOOO, that established new source performance standards for volatile organic compounds (VOCs)
and sulfur dioxide, an air toxics standard for major sources of oil and natural gas production, and an air toxics standard for major sources of natural gas transmission and storage. The rule applied to certain oil and natural gas sources that were
constructed, modified, or reconstructed after August 23, 2011, and required that all hydraulically fractured or refractured natural gas wells be completed using reduced emission (green) completion technology, which significantly
reduces VOC emissions. Limiting emissions of VOCs also has the co-benefit of limiting methane, a GHG. In addition, these regulations also include requirements applicable to storage tanks and other equipment in
the affected oil and natural gas industry segments. On June 3, 2016, EPA promulgated NSPS Subpart OOOOa, establishing additional standards for the reduction of methane, VOCs, and other emissions from new and existing sources in the oil and gas
sector. Among other requirements, these new standards extended green completion requirements to new hydraulically fractured or refractured oil wells. Furthermore, in December 2023, EPA announced additional final NSPS OOOO program rules, referred to
as Subparts OOOOb and OOOOc, which once effective upon publication in the Federal Register, are expected to have a significant impact on the upstream and midstream oil and gas sectors from an operational cost perspective. The rules formally instate
methane emissions limitations from new, modified, and reconstructed sources; and will regulate existing sources for the first time under the NSPS Subpart OOOOc program by requiring states to implement plans that meet or exceed federally established
emission reduction guidelines for existing oil and natural gas facilities. Although the bulk of the 2012 and 2016 standards are currently in effect, future implementation and the ultimate scope of the VOC and methane emissions standards for the oil
and gas production, transmission, and storage industry segments are uncertain at this time as a result of ongoing rulemakings and ongoing and expected legal challenges. Changes in the U.S. presidential administration following the 2024 presidential
election could also affect the implementation of the NSPS Subpart OOOOb and OOOOc rules.
Congress and various states, including Texas,
have proposed or adopted legislation regulating or requiring disclosure of the chemicals in the hydraulic fracturing fluid that is used in the drilling operation. Texas requires oil and gas operators to disclose the chemicals on the Frac Focus
website. Hydraulic fracturing has historically been regulated by state oil and natural gas commissions. The EPA, however, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking
Water Act (the SDWA). The EPA has issued permitting guidance for oil and natural gas hydraulic fracturing activities using diesel fuels. Under the guidance, EPA defined the term diesel to include five categories of oils,
including some such as kerosene, that are not traditionally considered to be diesel.
The Federal Water Pollution Control Act, also known
as the Clean Water Act (CWA), and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States. The
discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state agency. The CWA also prohibits the discharge of dredge and fill material into regulated waters,
including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers (USACE). Whether CWA permitting is required depends upon whether and the extent to which Waters of the United States
(WOTUS) may be impacted by the planned activityfor example, construction of drilling pads, access roads, or pipelines. Rulemaking by EPA and the USACE to define WOTUS has been heavily litigated, resulting in the rule taking effect
at times in some states but not others and creating definitions that are more inclusive of certain waters effective in some states and those that are less inclusive effective in other states. EPA and USACEs WOTUS definition rulemaking
published in the Federal Register on January 18, 2023 (the January 2023 Rule) incorporated relatively permanent and significant nexus standards for determining jurisdiction over adjacent
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wetlands and additional waters, expanding the types of waters that could be considered WOTUS; however, this WOTUS definition was litigated and eventually amended on August 29, 2023, when EPA
and USACE issued a final rule to conform the WOTUS definition to the U.S. Supreme Courts May 25, 2023 decision in Sackett v. Environmental Protection Agency , which invalidated parts of the January 2023 Rule. With the August 2023
rulemaking, EPA and USACE implemented a narrower definition of WOTUS by, for example, removing interstate wetlands; redefining adjacent to mean having a continuous surface connection; and removing the
significant nexus standard from the provisions regarding tributaries, adjacent wetlands, and intrastate lakes and ponds. Regardless, the applicable WOTUS definition affects what CWA permitting or other regulatory obligations, such as
spill prevention, control, and countermeasure (SPCC) planning, may be triggered during development and operation of the Underlying Properties, and changes to the WOTUS definition could cause delays in development and/or increase the cost
of development and operation of the Underlying Properties.
SPCC regulations promulgated under the CWA and later amended by the Oil
Pollution Act of 1990 impose obligations and liabilities related to the prevention of oil spills and damages resulting from such spills into or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil
and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, must develop, implement, and maintain SPCC Plans. Federal and state regulatory agencies
can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as the superfund law,
imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the current or previous
owner and operator of a site where a hazardous substance has been disposed and persons who disposed or arranged for the disposal of a hazardous substance at a site, or transported or arranged for transport of a hazardous substance to a site for
disposal. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to the public health or the environment and to seek recovery from such responsible classes of persons of the costs of such an action.
From time to time, EPA may designate additional materials as hazardous substances under CERCLA, which could result in additional investigation and remediation at current Superfund sites, or reopener of Superfund sites that previously received
regulatory closure. For example, on August 26, 2022, EPA announced a proposal to designate as hazardous substances under CERCLA perfluorooctanoic acid (PFOA) and perfluorooctanesulfonic acid (PFOS), which have been
commonly used in a variety of industrial and consumer products. In the course of operations, the working interest owner and/or the operator of the Underlying Properties may have generated and may generate wastes that may fall within CERCLAs
definition of hazardous substances. The operator of the Underlying Properties or the working interest owners may be responsible under CERCLA for all or part of the costs to clean up sites at which such substances have been disposed.
Although the Trust is not the operator of any of the Underlying Properties, or the owner of any working interest, its ownership of royalty interests could cause it to be responsible for all or part of such costs to the extent CERCLA imposes
responsibility on such parties as owners.
The Underlying Properties have produced oil and/or gas for many years and, in
connection with that production, managed waste, such as drilling fluids and produced water, that is subject to regulation under environmental laws. Although the Trust has no knowledge of the procedures followed by the operators of the Underlying
Properties in this regard, hydrocarbons or other solid or hazardous wastes may have been or may be disposed or released on, under, or from the Underlying Properties by the current or previous operators or may have been disposed offsite of the
Underlying Properties. Federal, state and local laws and regulations applicable to oil and gas-related wastes and properties have become increasingly more stringent. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of investigatory, ongoing monitoring, or remedial obligations, and/or the issuance of injunctions limiting or preventing some or all of the
operations. Under these laws, removal or remediation of current releases of such materials or of previously disposed wastes or property contamination at a drill site or a waste disposal facility could be required by a governmental authority
regardless of whether the operators of the Underlying Properties were responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time those actions were taken.
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The federal Safe Drinking Water Act (SDWA) and the Underground Injection Control
(UIC) program promulgated under the SDWA and analogous state programs regulate the drilling and operation of salt water disposal and injection wells. EPA directly administers the UIC program in some states and in others administration is
delegated to the state. Permits must be obtained before drilling salt water disposal and injection wells, and casing integrity monitoring must be conducted periodically to ensure that the disposed waters are not leaking into groundwater. In
addition, because some states have become concerned that the injection or disposal of produced water could, under certain circumstances, trigger or contribute to earthquakes, they have adopted or are considering additional regulations regarding such
disposal methods. Changes in regulations or the inability to obtain permits for new disposal wells in the future may affect the ability of the operators of the Underlying Properties to dispose of produced water and ultimately increase the cost of
operation of the Underlying Properties or delay production schedules. For example, in 2014, the Railroad Commission of Texas (RRC) published a final rule governing permitting or re-permitting of
disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the
disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined
to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Furthermore, in response to a number of earthquakes in recent years in the Midland Basin,
in September 2021 the RRC announced that it will not issue any new saltwater disposal (SWD) well permits in an area known as the Gardendale Seismic Response Area (SRA), and will require existing SWD wells in that area to
reduce their maximum daily injection rate to 10,000 barrels per day per well. In December 2021, the RRC went on to suspend all well activity in deep formations in the Gardendale SRA, effectively terminating 33 disposal well permits. In October 2021
and January 2022, respectively, the RRC identified two additional SRAs: the Northern Culberson-Reeves (NCR) SRA and the Stanton SRA. Operators in the NCR and Stanton SRAs were required to develop and implement seismic response plans,
which include expanded data collection efforts, contingency responses for future seismicity, and scheduled checkpoint updates with RRC staff. Both the Gardendale and NCR SRAs were expanded in December 2022 in response to additional earthquakes in
the area and effective January 12, 2014, the RRC suspended all (totaling 23) deep disposal well permits in the NCR SRA. Such restrictions and requirements could limit the Underlying Properties oil and gas well exploration and production
activities or increase the cost of those activities if wastewater disposal options become limited.
In addition, several cases have in
recent years put a spotlight on the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that
decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. EPA has also brought attention to the reach of the CWAs jurisdiction in such
instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological
connections should be considered direct, and whether such discharges would be better addressed through other federal or state programs. In a statement issued by EPA in April 2019, the Agency concluded that the CWA should not be
interpreted to require permits for discharges of pollutants that reach surface waters via groundwater. However, in April 2020, the Supreme Court issued a ruling in the case, County of Maui, Hawaii v. Hawaii Wildlife Fund , holding that
discharges into groundwater may be regulated under the CWA if the discharge is the functional equivalent of a direct discharge into navigable waters. On November 20, 2023, EPA issued draft guidance outlining the factors that may be
considered when evaluating whether discharges through groundwater may be the functional equivalent of a direct discharge and subject to regulation under the CWA National Pollutant Discharge Elimination System permitting program and
describing the types of information that should be used in the determination. Comments on the draft guidance were due to the agency by December 27, 2023, and to date EPA has not yet finalized the guidance. If in the future CWA permitting is
required for saltwater injection wells as a result of the Supreme Courts ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund , the costs of permitting and compliance for injection well operations by the companies that operate
the Underlying Properties could increase.
Various state and federal statutes prohibit certain actions that adversely affect endangered or
threatened species and their habitat, migratory birds and their habitat, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Bald and Golden Eagle Protection Act, the CWA, and
CERCLA.
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The United States Fish and Wildlife Service (USFWS) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of threatened or
endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where takings of, or harm to,
species or damages to wetlands, habitat or natural resources occur or may occur, government entities or at times private parties may act to restrict or prevent oil and gas exploration or production activities or seek damages for harm to species,
habitat or natural resources resulting from drilling or construction or production activities, including, for example, for releases of oil, wastes, hazardous substances or other regulated materials, and may seek natural resources damages and, in
some cases, criminal penalties.
The Underlying Properties and operation thereof are subject to the requirements of the federal
Occupational Safety and Health Act (OSHA) and comparable state statutes. In addition to the OSHA hazard communication standard, the EPA community
right-to-know regulations under Title III of CERCLA, the general duty clause and Risk Management Planning regulations promulgated under section 112(r) of the Clean Air
Act, and similar state statutes may also require disclosure of information about hazardous materials used, produced or otherwise managed during operation of the Underlying Properties. Some of these laws also require the development of risk
management plans for certain facilities to prevent accidental releases of pollutants.
The Trustee is unable to predict the total impact
of the current and potential regulations upon the operators of the Underlying Properties, but it is possible that the operators of the Underlying Properties could face operational delays, increases in the operating costs to comply with climate
change or any other environmental legislation or regulation, or decreases in the completion of new oil and natural gas wells, each of which could reduce net proceeds payable to the Trust and Trust distributions.
Other Regulation
The petroleum industry
is also subject to compliance with various other federal, tribal, state, and local regulations and laws, including, but not limited to, occupational safety, resource conservation and equal employment opportunity. The Trustee does not believe that
compliance with these laws by the operating parties will have any material adverse effect on Unit holders.