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, 2022, 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 BROG, the former 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
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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, 2022, the Waddell Ranch properties contained 918 (net) productive oil wells and 111 (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, 2022.
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.
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 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. There were 16 gross (6 net) drill wells completed on the Waddell Ranch properties during 2020. At December 31, 2020, there were 4 drill wells and 3 workover
in progress on the Waddell Ranch properties.
Blackbeard has advised the Trustee that the total amount of capital expenditures for 2022 with regard
to the Waddell Ranch properties totaled $124 million (gross). Capital expenditures include the cost of remedial and maintenance activities. The amount spent on remedial and maintenance activities is approximately $89 million of the amount
expended by Blackbeard in 2022.
Blackbeard has advised the Trustee that the capital expenditures budget for 2023 totals approximately
$122 million net to the Trust, of which approximately $8.1 million (gross) is attributable to facilities. Accordingly, there is a 32% increase in capital expenditures for 2023 as compared with the 2022 capital expenditures. There
are expected to be 48.75 new drill wells and 45 recompletions in 2023 as compared to 46.88 new drill wells and 45.06 recompletion in 2022.
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
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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). At the time of such sale, Riverhill Capital was a privately owned Texas corporation with offices in Bryan and Midland, Texas.
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. 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. As of January 1, 2012, ConocoPhillips assumed all field, technical and accounting operations, on behalf of BROG, with regard to the Waddell Ranch properties. ConocoPhillips currently provides summary reporting of monthly
results for the Waddell Ranch properties.
Well Count and Acreage Summary . The following table shows as of
December 31, 2022, 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, 2022. Similar information is not available for the Riverhill Energy interests. There is no undeveloped acreage on the Waddell Ranch properties.
NUMBER OF WELLS
ACRES
Gross
Net
Gross
Net
Blackbeard Interests
1,029
351
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, 2022, excluding portions attributable to the
adjustments discussed below, were as follows:
Waddell Ranch Properties
Texas Royalty
Properties
Total
2022
2021
2020
2022
2021
2020
2022
2021
2020
Royalties:
Production
Oil (barrels)
1,5244,038
775,230
219,634
206,433
191,876
215,685
1,760,471
967,106
435,319
Gas (Mcf)
9,346,780
3,754,386
1,282,070
114,307
122,262
155,292
9,461,087
3,876,648
1,437,362
Underlying Properties:
Production
Oil (barrels)
2,072,051
1,033,640
583,386
225,514
215,710
247,755
2,297,565
1,249,350
831,141
Gas (Mcf)
12,462,373
5,005,848
3,341,590
124,670
137,578
178,925
12,587,044
5,143,426
3,520,515
Average Sales Price
Oil/barrel
$
94.38
$
64.17
$
39.02
$
91.64
$
59.34
$
40.74
$
94.11
$
63.34
$
39.51
Gas/Mcf
$
5.48
$
3.45
$
1.37
$
10.89
$
6.59
$
3.33
$
5.54
$
3.53
$
1.47
Average Production Cost Oil/Gas BOE
$
17.58
$
17.71
$
32.92
$
6.81
$
5.36
$
4.27
$
16.82
$
16.01
$
26.54
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 2022 was $44 million (gross). The lease operating expense increased from $23 million in 2021 primarily because of increasing activity and facilities maintenance. Waddell Ranch lifting cost on a barrel
of oil equivalent (BOE) basis was $17.58 bbl as compared to $17.71 in 2021 and $32.92 in 2020.
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 since June 2006, the oil from the Waddell Ranch has been marketed
by the operator by soliciting bids from third parties on an outright sale basis of production listed in bid packages.
Gas . The gas produced from the Waddell Ranch properties is processed through a natural gas processing plant and sold at
the tailgate of the plant. Plant products are marketed by Burlington Resources Trading Inc., an indirect subsidiary of BRI. The processor of the gas (Warren Petroleum Company, L.P.) receives 15% of the liquids and residue gas as a fee for gathering,
compression, treating and processing the gas.
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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 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 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 35 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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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, 2020 through December 31, 2022 (in thousands):
Waddell Ranch
Properties
Texas Royalty
Properties
Total
Oil
(Bbls)
Gas
(Mcf)
Oil
(Bbls)
Gas
(Mcf)
Oil
(Bbls)
Gas
(Mcf)
January 1, 2020
920
3,695
3,109
1,691
4,029
5,386
Extensions, discoveries, and other additions
615
1,327
615
1,327
Revisions of previous estimates
155
1,060
87
62
242
1,122
Production
(220
)
(1,282
)
(216
)
(155
)
(436
)
(1,437
)
December 31, 2020
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
Estimated quantities of proved reserves and net cash flow as of December 31, 2022 are as follows:
Waddell Ranch
Properties
Oil
(Mstb)
Gas
(Mcf)
Net Cash
Flow, M$
10% Disc.
Cash Flow,
M$
Proved Developed Producing
5,179
19,210
$
590,399
$
378,215
Proved Developed Non-Producing
183
685
$
20,882
$
10,852
Proved Developed
5,362
19,895
$
611,282
$
388,867
Proved Undeveloped
3,531
4,521
$
343,913
$
190,587
Total Proved
8,893
24,416
$
955,914
$
579,454
Texas Royalty
Properties
Oil
(Mstb)
Gas
(Mcf)
Net Cash
Flow, M$
10% Disc.
Cash Flow,
M$
Proved Developed Producing
2,660
1,321
$
250,033
$
107,013
Proved Developed
2,660
1,321
$
250,033
$
107,013
Total Proved
2,660
1,321
$
250,033
$
107,013
Total Waddell Ranch Plus Texas Royalty
Properties
Oil
(Mstb)
Gas
(Mcf)
Net Cash
Flow, M$
10% Disc.
Cash Flow,
M$
Proved Developed Producing
7,839
20,531
$
840,432
$
485,228
Proved Developed Non-Producing
183
685
$
20,882
$
10,652
Proved Developed
8,022
21,216
$
861,315
$
495,880
Proved Undeveloped
3,531
4,521
$
343,913
$
190,587
Total Proved
11,553
25,737
$
1,205,228
$
686,467
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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, 2020
4,029
5,386
December 31, 2020
4,450
6,398
December 31, 2021
6,623
11,264
December 31, 2022
11,553
25,737
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 2022, 2021 and 2020 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
2022
2021
2020
2022
2021
2020
2022
2021
2020
January 1
$
188,329
$
33,852
$
34,239
$
71,528
$
46,239
$
68,516
$
259,857
$
80,091
$
102,755
Extensions, discoveries, and other additions
201,239
51,245
10,240
201,239
51,245
10,240
Accretion of discount
18,883
3,385
3,424
7,153
4,624
6,852
25,896
8,009
10,276
Revisions of previous estimates and other
206,142
99,847
(11,039
)
47,662
32,470
(20,101
)
253,804
132,317
(31,140
)
Royalty income
(35,089
)
(3,012
)
(19,329
)
(11,806
)
(9,028
)
(54,418
)
(11,806
)
(12,040
)
December 31
$
579,453
$
188,329
$
33,852
$
107,014
$
71,527
$
46,239
$
686,468
$
259,856
$
80,091
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.
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 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.
Average oil and gas prices of $39.57 per barrel and $2.00 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, 2020. 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 by
weaker gas pricing. The Texas Royalty properties are revised downward due to weaker pricing for oil.
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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, 2022, 2021 and 2020 (in thousands):
2022
2021
2020
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
$
955,195
$
579,454
$
297,181
$
188,329
$
61,731
$
33,852
Texas Royalty properties
250,033
107,014
167,968
71,527
108,715
46,239
Total
$
1,205,228
$
686,468
$
465,149
$
259,856
$
170,446
$
80,091
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 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 or 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.
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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.
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.
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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 protected areas; the
installation of emission monitoring and/or pollution control equipment; the reporting of the types and quantities of various substances that are 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 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 under the EPAs GHG Reporting Rule.
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 will have the co-benefit of also limiting methane, a GHG. 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,
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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, EPA has also recently proposed to revise and add to the NSPS OOOO program rules, which, if adopted, could have a significant impact on the
upstream and midstream oil and gas sectors. The proposed rules would formally instate methane emissions limitations from new, modified, and reconstructed sources; and would regulate existing sources for the first time under the NSPS OOOO 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.
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 in 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 activity for 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. Most recently, EPA and USACEs WOTUS definition rulemaking
on December 30, 2022, incorporated relatively permanent and significant nexus standards for determining jurisdiction over adjacent wetlands and additional waters. This WOTUS definition will become effective
March 20, 2023. 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 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
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regulatory closure. For example, on August 26, 2022, EPA announced a proposal to designate as hazardous substances 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.
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 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 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. And in October 2021 and January 2022, respectively, the RRC identified two additional SRAs: the Northern
Culberson-Reeves SRA and the Stanton SRA. Operators in the Northern Culberson-Reeves 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 Northern Culberson-Reeves SRAs were expanded in December 2022 in response to additional earthquakes in the area. 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.
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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 January 14, 2021, EPA issued guidance on the ruling that emphasized discharges to groundwater are not necessarily the functional equivalent of a
direct discharge based solely on proximity to jurisdictional waters, although EPA rescinded that guidance on September 16, 2021. 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. 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.
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Item 3.
Legal Proceedings
There are no material pending legal proceedings to which the Trust is a party or of which any of its property is the subject.
Item 4.
Mine Safety Disclosures
This Item is not applicable to the Trust.
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PART II
Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.