Hugoton Royalty Trust
2023
Annual Report and
Form 10-K
Glossary of Terms
Bbl
Bcf
BOE
Mcf
Barrel (of oil)
Billion cubic feet (of natural gas)
Barrel of oil equivalent
Thousand cubic feet (of natural gas)
MMBtu
One million British Thermal Units, a common energy measurement
net proceeds
Gross proceeds received by XTO Energy from sale of production from
the underlying properties, less applicable costs, as defined in the net
profits interest conveyances.
net profits income
Net proceeds multiplied by the net profits percentage of 80%, which is
paid to the Trust by XTO Energy. “Net profits income” is referred to as
“royalty income” for income tax purposes.
net profits interest
An interest in an oil and gas property measured by net profits from the
sale of production, rather than a specific portion of production. The
following defined net profits interests were conveyed to the Trust from the
underlying properties:
80% net profits interests – interests that entitle the Trust to receive 80% of
the net proceeds from the underlying properties.
underlying properties XTO Energy’s interest in certain oil and gas properties from which the
net profits interests were conveyed. The underlying properties include
working interests in predominantly gas-producing properties located in
Kansas, Oklahoma and Wyoming.
working interest
An operating interest in an oil and gas property that provides the owner
a specified share of production that is subject to all production expense
and development costs.
Selected Financial Data
2023
Years Ended December 31,
Net Profits Income ..................... $ 11,467,914
Distributable Income ................. 11,096,520
0.277413
Distributable Income per Unit ..
0.277413
Distributions per Unit.................
344,048
Total Assets at Year End ...........
2021
$ 19,544,398
16,585,039
0.414626
0.414626
2,834,360
$
2021
0
0
0.000000
0.000000
660,000
$
2020
0
0
0.000000
0.000000
0
$
2019
369,458
0
0.000000
0.000000
605,646
The Trust
Hugoton Royalty Trust was created
on December 1, 1998 when XTO
Energy Inc. conveyed 80% net profits
interests in certain predominantly
gas-producing properties located in
Kansas, Oklahoma and Wyoming to
the Trust. The net profits interests
are the only assets of the Trust, other
Net profits income received by the Trust
on the last business day of each month is
calculated and paid by XTO Energy based on
net proceeds received from the underlying
properties in the prior month. Distributions,
as calculated by the Trustee, are paid to
month-end unitholders of record within ten
business days.
than cash held for Trust expenses and for
distribution to unitholders.
Summary
The Trust was created to collect and
distribute to unitholders monthly net
profits income related to the 80%
net profits interests. Such net profits
income is calculated as 80% of the
net proceeds received from certain
working interests in predominantly
gas-producing properties in Kansas,
Oklahoma and Wyoming. Net proceeds from
properties in each state are calculated by
deducting production expense, development
costs and overhead from revenues. If
monthly costs exceed revenues from the
underlying properties in any state, such
excess costs must be recovered, with
accrued interest, from future net proceeds
of that state and cannot reduce net profits
income from another state. Excess costs
generally can occur during periods of higher
development activity and/or lower gas
prices. Underlying cumulative excess costs
for the Kansas, Oklahoma and Wyoming
conveyances remaining as of December 31,
2023, totaled $3.9 million ($3.1 million net to
the Trust), including accrued interest of $0.3
million ($0.2 million net to the Trust). This
balance does not include the portion of the
Chieftain settlement an arbitration panel
determined could be charged as a production
cost. XTO Energy estimated the amount to be
approximately $14.6 million net to the Trust.
For further information on excess costs, see
Note 4 to Financial Statements under Item 8,
“Financial Statements and Supplementary
Data” of the accompanying Form 10-K.
Cost Depletion is generally available to
unitholders as a deduction from royalty
income. Available depletion is dependent
upon the unitholder’s cost of units, purchase
date and prior allowable depletion. It may
be more beneficial for unitholders to deduct
percentage depletion. Please see the
2023 tax booklet for specific instructions.
Unitholders should consult their tax advisors
for further information.
To Unitholders:
We are pleased to present the 2023
Annual Report on Form 10-K of the
Hugoton Royalty Trust as filed with the
Securities and Exchange Commission.
This report contains important infor-
mation about the Trust’s net profits
interests, including information pro-
vided to the Trustee by XTO Energy.
For the year ended December 31,
2023, net profits income totaled $11,467,914.
Trust administration expense was $1,093,016
in 2023. Cash reserve activity for 2023
included utilization of $655,952 for the pay-
ment of Trust expenses. Interest income was
$65,670 in 2023. Changes in interest income
are attributable to fluctuations in net profits
income, cash reserve and interest rates.
Distributable income was $11,096,520 or
$0.277413 per unit in 2023.
Net profits income and distributions for
the year were lower than in 2022 primarily
due to lower oil and gas prices, increased
development costs, decreased oil and gas
production, increased production expenses,
and increased overhead, partially offset by
net excess costs activity and decreased
taxes, transportation and other costs. For fur-
ther information, see “Trustee’s Discussion
and Analysis of Financial Condition and
Results of Operations” under Item 7 of the
accompanying Form 10-K.
The 2023 average gas price was $5.18 per
Mcf, down 27 percent from the 2022 average
gas price of $7.08 per Mcf. The average oil
price for 2023 was $75.88 per Bbl, down 10
percent from the average oil price for 2022 of
$83.91 per Bbl. Gas sales volumes from the
underlying properties for 2023 were 9,397,772
Mcf, or 25,747 Mcf per day, a decrease of 4
percent from 26,773 Mcf per day in 2022. Oil
sales volumes from the underlying proper-
ties were 217,440 Bbls, or 596 Bbls per day
in 2023, a decrease of 11 percent from 673
Bbls per day in 2022. For further informa-
tion on sales volumes and product prices,
see “Trustee’s Discussion and Analysis
of Financial Condition and Results of
Operations” under Item 7 of the accompany-
ing Form 10-K.
As of December 31, 2023, proved reserves
for the underlying properties were estimated
by independent engineers to be 79.0 Bcf of
natural gas and 1.4 million Bbls of oil. From
year-end 2022 to 2023, gas and oil reserves
for the underlying properties decreased 39
percent and 14 percent, respectively, primar-
ily due to lower oil and gas prices used to
estimate reserves. Based on an allocation of
these reserves, proved reserves attributable
to the net profits interests were estimated to
be 7.3 Bcf of natural gas and 0.1 million Bbls
of oil. Because Trust reserve quantities are
determined using an allocation formula, any
fluctuations in actual or assumed prices or
costs will result in revisions to the estimated
reserve quantities allocated to the net profits
interests. All reserve information prepared by
independent engineers has been provided to
the Trustee by XTO Energy.
Estimated future net cash flows from
proved reserves of the net profits interests at
December 31, 2023 was $27.1 million. Using
an annual discount factor of 10%, the present
value of estimated future net cash flows at
December 31, 2023 was $19.0 million.
Proved reserve estimates and related
future net cash flows have been determined
based on a 12-month average gas price of
$2.59 per Mcf and a 12-month average oil
price of $75.88 per Bbl, based on the first-
day-of-the-month price for each month in the
period, and year end costs, including recov-
ery of cumulative excess costs remaining at
year end.
To Unitholders: Continued
Other guidelines used in estimating
proved reserves, as prescribed by the
Financial Accounting Standards Board, are
described in Note 9 to Financial Statements
under Item 8, “Financial Statements and
Supplementary Data” of the accompanying
Form 10-K. The present value of estimated
future net cash flows is computed based on
SEC guidelines and is not necessarily repre-
sentative of the market value of Trust units.
The accompanying financial state-
ments have been prepared assuming that
the Trust will continue as a going concern.
Financial statements prepared on a going
concern basis assume the realization of
assets and the settlement of liabilities in the
normal course of business. Accumulated
excess costs for the Kansas, Oklahoma and
Wyoming conveyances have resulted in
insufficient net proceeds to the Trust and
a reduction in the Trust’s expense reserve.
These conditions raise substantial doubt
about the Trust’s ability to continue as a going
concern as the Trust does not have sufficient
cash to meet its obligations during the one-
year period after the dates that the financial
statements are issued. Factors attributable
to the cash shortage are primarily the previ-
ously disclosed development costs to drill
three non-operated wells in Major County,
Oklahoma, lower oil and natural gas prices
during 2023, and excess cost positions
on the Kansas, Oklahoma and Wyoming
conveyances including accumulated inter-
est, which have resulted in no unitholder
distributions since July 2023. In addition, on
May 18, 2021, the arbitration panel issued its
second interim final award over the amount
of XTO Energy’s settlement in the Chieftain
class action lawsuit that can be charged to
the Trust as a production cost which XTO
Energy has estimated to be approximately
$14.6 million net to the Trust. This adjustment
would further increase excess costs on the
Oklahoma conveyance. The Trustee has
prepared a preliminary budget estimating the
administrative expenses for the year ending
December 31, 2024, and the three months
ending March 31, 2025, which assumes no
cash inflow from either net profits income
or from other sources. The Trustee intends
to review options for the Trust which may
include alternatives to continuing as a going
concern or may include seeking financing to
pay the Trust obligations during the one-year
period after the date the financial state-
ments are issued; however, there can be no
assurance that financing will be available
on acceptable terms or at all. If financing
became available to the Trust, it would have
to be repaid, together with interest, and
the Trust’s expense reserve would have to
be replenished prior to any distributions to
unitholders.
XTO Energy is a party to legal proceed-
ings that may affect future Trust distributions.
For further information, see Note 8 to
Financial Statements under Item 8, “Financial
Statements and Supplementary Data” of the
accompanying Form 10-K.
As disclosed in the tax instructions pro-
vided to unitholders in February 2024, Trust
distributions are considered portfolio income,
rather than passive income. Unitholders
should consult their tax advisors for further
information.
Hugoton Royalty Trust
By: Argent Trust Company, Trustee
By: Nancy Willis
Director of Royalty Trust Services
April 11, 2024
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
È ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2023
OR
‘ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission File No. 1-10476
.
Hugoton Royalty Trust
(Exact name of registrant as specified in its charter)
Texas
(State or other jurisdiction of
incorporation or organization)
c/o Corporate Trustee:
Argent Trust Company
3838 Oak Lawn Ave, Suite 1720
Dallas, Texas 75219-4518
(Address of principal executive offices)
58-6379215
(I.R.S. Employer
Identification No.)
75219
(Zip Code)
Registrant’s telephone number, including area code
(at the office of the Corporate Trustee):
(855) 588-7839
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Title of each class
Trading symbol
Name of each exchange on which registered
the
OTCQB
HGTXU
the registrant
the registrant
the Securities
YES È NO ‘
to Section 13 or Section 15(d) of
is not required to file reports pursuant
is a well-known seasoned issuer, as defined in Rule 405 of
Units of Beneficial Interest
Indicate by check mark if
Act. YES ‘ NO È
Indicate by check mark if
Act. YES ‘ NO È
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit such files). YES ‘ NO ‘
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller
reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller
reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:
Large accelerated filer ‘
Non-accelerated filer È
Accelerated filer
‘
Smaller reporting company È
Emerging growth company ‘
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for
complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ‘
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the
effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the
registered public accounting firm that prepared or issued its audit report. ‘
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the
registrant included in the filing reflect the correction of an error to previously issued financial statements. ‘
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based
compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ‘
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
The aggregate market value of units of beneficial interest held by non-affiliates of the registrant at June 30, 2023 (the last business day
of the registrant’s most recently completed second fiscal quarter) was approximately $36.0 million.
The number of units of beneficial interest outstanding as of March 13, 2024, was 40,000,000.
YES ‘ NO È
HUGOTON ROYALTY TRUST
2023 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
Page
Glossary of Terms
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
Part I
Item 1.
Item 1A.
Item 1B.
Item 1C.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 9C.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk Factors
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cybersecurity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part II
Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units . . . . . . . .
[Reserved] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trustee’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . .
Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . .
Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections . . . . . . . . . . . . . . . . . . . . . . .
Part III
Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . .
Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 15.
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part IV
2
3
11
11
12
22
23
24
24
25
31
31
44
44
44
44
45
45
46
46
46
47
48
i
HUGOTON ROYALTY TRUST
GLOSSARY OF TERMS
The following are definitions of significant terms used in this Annual Report on Form 10-K:
Bbl
Bcf
BOE
Mcf
MMBtu
net proceeds
net profits income
net profits interest
underlying properties
Barrel (of oil)
Billion cubic feet (of natural gas)
Barrel of oil equivalent
Thousand cubic feet (of natural gas)
One million British Thermal Units, a common energy measurement
Gross proceeds received by XTO Energy from sale of production from the
underlying properties, less applicable costs, as defined in the net profits interest
conveyances.
Net proceeds multiplied by the net profits percentage of 80%, which is paid to
the Trust by XTO Energy. “Net profits income” is referred to as “royalty income”
for income tax purposes.
An interest in an oil and gas property measured by net profits from the sale of
production, rather than a specific portion of production. The following defined
net profits interests were conveyed to the Trust from the underlying properties:
80% net profits interests - interests that entitle the Trust to receive 80% of the net
proceeds from the underlying properties.
XTO Energy’s interest in certain oil and gas properties from which the net profits
interests were conveyed. The underlying properties include working interests in
predominantly gas-producing properties located in Kansas, Oklahoma and
Wyoming.
working interest
An operating interest in an oil and gas property that provides the owner a
specified share of production that is subject to all production expense and
development costs.
1
ITEM 1. BUSINESS
PART I
Hugoton Royalty Trust (the “Trust”) is an express trust created under the laws of Texas pursuant to the
Hugoton Royalty Trust Indenture entered into on December 1, 1998, between XTO Energy Inc. (formerly known as
Cross Timbers Oil Company and, hereafter, “XTO Energy”), as grantor, and NationsBank, N.A., as Trustee. The
current trustee of the Trust is Argent Trust Company, a Tennessee chartered trust company (“Argent”). Effective
April 10, 2023, Simmons Bank resigned as trustee, and Argent was appointed as the successor trustee.
The defined term “Trustee” as used herein shall refer to Simmons Bank for periods from February 20, 2018,
through April 9, 2023, and shall refer to Argent for periods on and after April 10, 2023.
The principal office of the Trust is 3838 Oak Lawn Ave, Suite 1720, Dallas, Texas 75219. (Telephone number
855-588-7839). The Trust’s internet website is www.hgt-hugoton.com. We make available free of charge, through
our website, our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all
amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act
of 1934. These reports are accessible through our internet website as soon as reasonably practicable after we
electronically file such material with, or furnish it to, the Securities and Exchange Commission. Information on our
website is not incorporated into this report.
Effective December 1, 1998, XTO Energy conveyed to the Trust 80% net profits interests in certain
predominantly natural gas producing working interest properties in Kansas, Oklahoma and Wyoming under three
separate conveyances. In exchange for these net profits interest conveyances to the Trust, 40 million units of
beneficial interest were issued to XTO Energy. In April and May 1999, XTO Energy sold a total of 17 million units in
the Trust’s initial public offering. In 1999 and 2000, XTO Energy also sold 1.3 million Trust units to certain of its
officers. The Trust did not receive the proceeds from these sales of Trust units. In May 2006, XTO Energy
distributed all of its remaining 21.7 million Trust units as a dividend to its common stockholders. XTO Energy
currently is not a unitholder of the Trust. Units were listed and traded on the New York Stock Exchange under the
symbol “HGT” until August 27, 2018, when the Trust units were delisted from the NYSE and began to be quoted on
the OTCQX, which is maintained by the OTC Market Group Inc., under the symbol “HGTXU.” The Trust transitioned
from the OTCQX to the OTCQB on May 19, 2020.
On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.
The net profits interests entitle the Trust to receive 80% of the net proceeds from the sale of oil and gas from
the underlying properties. Each month XTO Energy determines the amount of cash received from the sale of
production and deducts property and production taxes, production expense, development costs and overhead.
Net proceeds payable to the Trust depend upon production quantities, sales prices of oil and gas and costs
to develop and produce oil and gas in the prior month. If monthly costs exceed revenues for any of the three
conveyances (one for each of the states of Kansas, Oklahoma and Wyoming), such excess costs must be
recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds
from other conveyances. For further information on excess costs, see Note 4 to Financial Statements under Item 8.
Financial Statements and Supplementary Data.
The Trust is not liable for any production costs or liabilities attributable to the underlying properties. If at any
time the Trust receives net profits income in excess of the amount due, the Trust is not obligated to return such
overpayment, but future net profits income payable to the Trust will be reduced until the overpayment, plus
interest at the prime rate, is recovered.
As a working interest owner, XTO Energy can generally decline participation in any operation and allow
consenting parties to conduct such operations, as provided under the operating agreements. XTO Energy also can
2
assign, sell, or otherwise transfer its interest in the underlying properties, subject to the net profits interests, or
can abandon an underlying property if it is incapable of producing in paying quantities, as determined by XTO
Energy.
To the extent allowed, XTO Energy is responsible for marketing its production from the underlying properties
terms reasonably obtainable in the
under existing sales contracts, or new arrangements on the best
circumstances. See “Pricing and Sales Information” under Item 2. Properties.
Net profits income received by the Trust on or before the last business day of the month is related to net
proceeds received by XTO Energy in the preceding month, and is generally attributable to oil and gas production
two months prior. The amount to be distributed to unitholders each month by the Trustee is determined by:
Adding -
1. net profits income received;
2. interest income and any other cash receipts; and
3. cash available as a result of reduction of cash reserves; then
Subtracting -
1. liabilities paid; and
2. the reduction in cash available related to establishment of or increase in any cash reserve.
The monthly distribution amount is distributed to unitholders of record within ten business days after the
monthly record date. The monthly record date is generally the last business day of the month. The Trustee
calculates the monthly distribution amount and announces the distribution per unit at least ten days prior to the
monthly record date.
The Trustee may establish cash reserves for contingencies. Cash held for such reserves, as well as for
pending payment of the monthly distribution amount, may be invested in federal obligations or certificates of
deposit of major banks.
The Trustee’s function is to collect the net profits income from the net profits interests, to pay all Trust
expenses, and to pay the monthly distribution amount to unitholders. The Trustee’s powers are specified by the
terms of the Trust indenture. The Trust cannot engage in any business activity or acquire any assets other than
the net profits interests and specific short-term cash investments. The Trust has no employees since all
administrative functions are performed by the Trustee.
The majority of previous net profits income received by the Trust has been attributable to natural gas. There
has historically been a greater demand for gas during the winter months than the rest of the year. Otherwise,
Trust income generally is not subject to seasonal factors, nor dependent upon patents, licenses, franchises or
concessions. The Trust conducts no research activities.
The oil and gas industry is highly competitive in all its phases. Operators of the properties in which the Trust
holds interests encounter competition from other oil and gas companies and from individual producers and
operators. Oil and natural gas are commodities, for which market prices are determined by external supply and
demand factors. Current market conditions are not necessarily indicative of future conditions.
ITEM 1A. RISK FACTORS
The following factors could cause actual results to differ materially from those contained in forward-looking
statements made in this report and presented elsewhere by the Trustee from time to time. Such factors may have
a material adverse effect upon the Trust’s financial condition, distributable income and changes in trust corpus.
3
The following discussion of risk factors should be read in conjunction with the financial statements and
related notes included under Item 8. Financial Statements and Supplementary Data. Because of these and other
factors, past financial performance should not be considered an indication of future performance.
The Trust may not have sufficient cash to meet its obligations during the one-year period after the date that the
financial statements are issued and may choose or be required to take other actions to satisfy its obligations by
seeking additional financing, which may not be successful.
All three of the Trust’s conveyances are in excess costs resulting in no net proceeds to the Trust and a
reduction in the Trust’s expense reserve, which have resulted in no unitholder distributions since July 2023. These
conditions raise substantial doubt about the Trust’s ability to continue as a going concern as the Trust does not
have sufficient cash to meet its obligations during the one-year period after the date the financial statements are
issued. The Trust’s financial statements do not include any adjustments that might result from the outcome of this
uncertainty. There are no assurances that the Trust will receive net profits income sufficient to pay its obligations
during the one-year period after the date the financial statements are issued, and as a result, may choose or be
required to seek additional financing or alternatives to the Trust continuing as a going concern. If the Trust is
unable to continue as a going concern, unitholders could incur significant losses on their investment in the Trust
or lose their entire investment in the Trust altogether. For further information see Item 7. Trustee’s Discussion and
Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.
The market price for the Trust units may not reflect the value of the net profits interests held by the Trust.
The public trading price for the Trust units has historically been tied to the recent and expected levels of
cash distributions on the Trust units. However, no cash distribution has occurred for eight months as of the date of
this report, April 1, 2024. The amounts available for distribution by the Trust vary in response to numerous factors
outside the control of the Trust or XTO Energy, including prevailing prices for oil and natural gas produced from
the underlying properties. The market price of the Trust units is not necessarily indicative of the value that the
Trust would realize if the net profits interests were sold to a third-party buyer. In addition, such market price is not
necessarily reflective of the fact that, since the assets of the Trust are depleting assets, a portion of each cash
distribution paid on the Trust units should be considered by investors as a return of capital, with the remainder
being considered as a return on investment. There is no guarantee that distributions made to a unitholder over the
life of these depleting assets will equal or exceed the purchase price paid by the unitholder or that distributions
from the Trust will resume in 2024 or at all.
Current and future oil and natural gas prices fluctuate due to a number of uncontrollable factors, and any decline
will adversely affect the net proceeds payable to the Trust and Trust distributions.
The Trust’s monthly cash distributions are highly dependent upon the prices realized from the sale of natural
gas and oil. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of
factors that are beyond the control of the Trust and XTO Energy. Factors that contribute to price fluctuations
include instability in oil-producing regions, worldwide economic conditions, weather conditions, trade barriers,
political instability, public health concerns, the supply of domestic and foreign oil, natural gas and natural gas
liquids, consumer demand, the price and availability of alternative fuels, the proximity to, and capacity of,
transportation facilities and the effect of worldwide energy conservation measures. Moreover, government
regulations, such as regulation of natural gas transportation and price controls, environmental regulations,
production restrictions, or trade barriers, can affect product prices. Oil and natural gas prices fluctuated widely
over the recent past and may vary significantly from period to period. Further, a significant decline in current oil or
natural gas prices or lower anticipated long-term prices could have a material adverse effect on the amount of oil
and natural gas that is economic to produce, Trust net profits (and therefore cash available for distribution to
unitholders) and proved reserves attributable to the Trust’s interests. Adjustments impacting volume or value
could also impact the reported natural gas and oil prices. The volatility of energy prices reduces the predictability
of future cash distributions to Trust unitholders.
4
Higher production expense and/or development costs, without concurrent increases in revenue, will directly
decrease the net proceeds payable to the Trust. Certain claimed production expenses by XTO Energy may
reduce or eliminate distributions to unitholders for extended periods of time.
Production expense and development costs are deducted in the calculation of the Trust’s share of net
proceeds. Accordingly, higher or lower production expense and development costs, without concurrent changes
in revenue, will directly decrease or increase the amount received by the Trust. If development costs and
production expense for underlying properties in a particular state exceed the production proceeds from the
properties (as has been the case with respect to the properties underlying all three of the Trust’s conveyances for
the eight months preceding the date of this report), the Trust will not receive net profits income for those
properties until future net proceeds from production in that state exceed the total of the excess costs plus
accrued interest during the deficit period. Development activities may not generate sufficient additional revenue
to repay the costs. Additionally, XTO Energy has advised the Trustee that total budgeted development costs for the
underlying properties are approximately $3 million for 2024 which could exceed revenues for the underlying
conveyances. See Item 2. Properties.
As described in Note 8 – Contingencies to the Notes to Financial Statements, XTO Energy advised the
Trustee that it believes a portion of the settlement it has reached in the Chieftain Royalty Company v. XTO Energy
Inc. class action lawsuit relates to the Trust. On July 27, 2018, the final plan of allocation was approved by the
court. Based on the final plan of allocation, XTO Energy advised the Trustee that it believes approximately
$24.3 million in additional production costs should be allocated to the Trust. On May 2, 2018, the Trustee submitted
a demand for arbitration seeking a declaratory judgment that the Chieftain settlement is not a production cost and
that XTO Energy is prohibited from charging the settlement as a production cost under the conveyance or
otherwise reducing the Trust’s payments now or in the future as a result of the Chieftain litigation. The Trust and
XTO Energy conducted the interim hearing on the claims related to the Chieftain settlement on October 12-13,
2020. In the arbitration, the Trustee contended that the approximately $24.3 million allocation related to the
Chieftain settlement was not a production cost and, therefore, there should not be a related adjustment to the
Trust’s share of net proceeds. However, XTO Energy contended that the approximately $24.3 million was a
production cost and should reduce the Trust’s share of net proceeds.
On January 20, 2021, the arbitration panel issued its Corrected Interim Final Award (i) “reject[ing] the Trust’s
contention that XTO has no right under the Conveyance to charge the Trust with amounts XTO paid under
section 1.18(a)(i) as royalty obligations to settle the Chieftain litigation” and (ii) stating “[t]he next phase will
determine how much of the Chieftain settlement can be so charged, if any of it can be, in the exercise of the right
found by the Panel.” Following briefing by both parties, on May 18, 2021, the Panel issued its second interim final
award over the amount of XTO Energy’s settlement in the Chieftain class action lawsuit that can be charged to the
Trust as a production cost. The Panel in its decision has ruled that out of the $80 million settlement, the “Trust is
obligated to pay its share under the Conveyance of the $48 million that was received by the plaintiffs in the
Chieftain lawsuit by virtue of the settlement of that litigation. The Trust is not obligated by the Conveyance to pay
any share of the $32 million received by the lawyers for the plaintiffs in the Chieftain lawsuit by virtue of the
settlement.” XTO Energy and the Trustee are in the process of determining the portion of the $48 million that is
allocable to Trust properties to be charged as an excess cost to the Trust, but estimate it to be approximately
$14.6 million net to the Trust.
The reduction in the Trust’s share of net proceeds from the portion of the settlement amount the Panel has
ruled may be charged against the Oklahoma conveyance would result in excess costs under the Oklahoma
conveyance that would likely result in no distributions under the Oklahoma conveyance while these excess costs
are recovered. This award completes the portion of the arbitration related to the Chieftain settlement. Excess
costs on any individual conveyance would not affect net proceeds to the Trust on any of the other remaining
conveyances.
Other Trustee claims related to disputed amounts on the computation of the Trust’s net proceeds for 2014
through 2019 and 2021 were bifurcated from the initial arbitration. Although the arbitration is not terminated, the
5
final hearing regarding the remaining dispute over net proceeds, previously scheduled to occur on November 8,
2023, was cancelled. XTO Energy and the Trustee will provide material updates as they become available. See
Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements – Note 8 – Contingencies
for additional information.
Government action, policies or regulations designed to discourage production, reduce demand for, or promote
alternatives to oil and natural gas could impact the price of oil and natural gas produced on the properties
underlying the Trust’s net profits interests, directly as intended or through unintended consequences.
Governments around the world are considering actions intended to reduce greenhouse gas emissions by
decreasing both the supply of and the demand for oil and natural gas products or promote alternatives. These
trade tariffs, minimum renewable usage
include the adoption of cap-and-trade regimes, carbon taxes,
requirements, restrictive permitting, increased mileage and other efficiency standards, mandates for sales of
electric vehicles, mandates for use of specific fuels or technologies, and other incentives or mandates designed
to support transitioning to lower-emission energy sources. Political and other actors and their agents also
increasingly seek to advance climate change objectives indirectly, such as by seeking to reduce the availability or
increase the cost of financing and investment in the oil and gas sector. Depending on how policies are formulated
and applied, such policies could impact the ability and costs of the operators of the properties underlying the
Trust’s net profits interests to supply products, demand for their products, or the competitiveness of hydrocarbon-
based products, which in turn, could reduce net proceeds to the Trust. Any policy that increases the costs for
operators of the properties underlying the net profits interests or lower market prices could have a material
impact on the distributable income of the Trust.
War, terrorism, geopolitical hostilities, and other military actions or political instability could adversely affect
Trust distributions or the market price of the Trust units.
There are a number of national and international events that could cause instability in global financial and
energy markets. War, terrorist attacks and the threat of war or terrorist attacks, whether domestic or foreign, as
well as other military or similar actions taken in response, impact the demand for and price of oil and natural gas
in unpredictable ways, including increasing volatility in pricing. Actual or threatened acts of war, terrorism and
other geopolitical hostilities could adversely affect Trust distributions or the market price of the Trust units in
unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in oil and
natural gas prices, or the possibility that the infrastructure on which the operators of the underlying properties
rely could be a direct target or an indirect casualty of such an event.
There may not be an active market for the Trust units.
On August 27, 2018, the Trust units were delisted from the NYSE and began to be quoted on the OTCQX,
which is maintained by the OTC Market Group Inc., under the symbol “HGTXU.” The Trustee received notice from
the OTC Markets Group Inc. dated April 16, 2020, notifying the Trustee that the Trust was no longer in compliance
with Section 3.2(a) of the Standards for Continued Qualification of the OTCQX Rules for U.S. Companies, in that as
of December 31, 2019, the Trust had less than $2 million in net tangible assets, average revenue of less than
$6 million over the past three years, and the Trust’s bid price is below $5 per share. The notice stated that if the
Trust was unable to cure the deficiency by May 18, 2020, then it would be moved from OTCQX to the OTC Pink
market. The Trust transitioned from the OTCQX to the OTCQB on May 19, 2020. Trading on the OTC is often
characterized as thin with sporadic fluctuations in price and the availability of buyers or sellers of a security. No
assurance can be given that an active trading market for the Trust units will further develop or continue. The Trust
units will likely be subject to greater volatility and lower trading volumes than when the Trust units were listed on
the New York Stock Exchange. This could depress the trading price of the Trust units and make it more difficult to
purchase, dispose of or obtain accurate quotations as to the value of the Trust units. No assurance can be made
how such transition may affect the liquidity of the units.
6
Proved reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material
inaccuracies in reserve estimates or underlying assumptions could cause the quantities and net present value
of the reserves to be overstated.
Estimating proved oil and gas reserves is inherently uncertain. Petroleum engineers consider many factors
and make assumptions in estimating reserves and future net cash flows. Those factors and assumptions include
historical production from the area compared with production rates from similar producing areas, the effects of
governmental regulation, assumptions about future commodity prices, production expense and development
costs, taxes and capital expenditures, the availability of enhanced recovery techniques and relationships with
landowners, working interest partners, pipeline companies and others. Lower oil and gas prices generally cause
lower estimates of proved reserves. Ultimately, actual production, revenues and expenditures for the underlying
properties will vary from estimates and those variances could be material. Because the Trust owns net profits
interests, it does not own a specific percentage of the oil and gas reserves. Estimated proved reserves for the net
profits interests are based on estimates of reserves for the underlying properties and an allocation method that
considers estimated future net proceeds and oil and gas prices. Because Trust reserve quantities are determined
using an allocation formula, increases or decreases in oil and gas prices can significantly affect estimated
reserves of the net profits interests.
Operational risks and hazards associated with the development and operations of the underlying properties may
decrease Trust distributions.
There are operational risks and hazards associated with the production and transportation of oil and natural
gas, including, without limitation, natural disasters, blowouts, explosions, fires, leakage of oil or natural gas,
releases of other hazardous materials, mechanical failures, cratering, and pollution. Any of these or similar
occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property
damage, damage to productive formations or equipment, damage to the environment or natural resources, or
cleanup obligations. The operation of oil and gas properties is also subject to various laws and regulations.
Non-compliance with such laws and regulations could subject the operator to additional costs, sanctions or
liabilities. The uninsured costs resulting from any of the above or similar occurrences could be deducted as a
production expense or development cost in calculating the net proceeds payable to the Trust, and would
therefore reduce Trust distributions by the amount of such uninsured costs.
The Trust may be subject to attempted cybersecurity disruptions from a variety of sources including state-
sponsored actors.
limited to,
XTO Energy’s defensive preparedness includes multi-layered technological capabilities designed to prevent
and detect cybersecurity disruptions; non-technological measures such as threat information sharing with
governmental and industry groups;
internal training and awareness campaigns including routine testing of
employee awareness and business preparedness for response and recovery. The Trustee also maintains robust
cybersecurity protocols including, but not
technological capabilities that prevent and detect
disruptions; computer workstations and programs protected with passwords and passphrases, as well as
employee training throughout the year on banking regulations and cybersecurity followed up by testing of that
knowledge. Other, non-technical protocols include securing of documents and work areas that could contain
personal, non-public information. If the measures taken to protect against cybersecurity disruptions prove to be
insufficient or if proprietary data is otherwise not protected, XTO Energy, the Trustee or customers, employees, or
third parties could be adversely affected. The Trust has limited ability to influence third parties, including our
partners, suppliers, and service providers (including providers of cloud-hosting services for our data or
applications), to implement strong cybersecurity controls and is exposed to potential harm from cybersecurity
events that may affect their operations. Cybersecurity disruptions could cause physical harm to people or the
environment; damage or destroy assets; compromise business systems; result in proprietary information being
altered, lost, or stolen; result in employee, customer, or third-party information being compromised; or otherwise
disrupt our business operations. We could incur significant costs to remedy the effects of a major cybersecurity
disruption in addition to costs in connection with resulting regulatory actions, litigation, or reputational harm.
7
Future net profits may be subject to risks relating to the creditworthiness of third parties.
The Trust does not lend money and has limited ability to borrow money, which the Trustee believes limits the
Trust’s risk from exposure to credit markets. The Trust’s future net profits, however, may be subject to risks
relating to the creditworthiness of the operators of the underlying properties and other purchasers of crude oil
and natural gas produced from the underlying properties. This creditworthiness may be impacted by the price of
crude oil and natural gas.
Trust unitholders and the Trustee have no influence over the operations on, or future development of, the
underlying properties.
Neither the Trustee nor the Trust unitholders can influence or control the operation or future development of
the underlying properties. The failure of an operator to conduct its operations or discharge its obligations in a
proper manner could have an adverse effect on the net proceeds payable to the Trust. Although XTO Energy and
other operators of the underlying properties must adhere to the standard of a prudent operator, they are under no
obligation to continue operating the properties. Neither the Trustee nor Trust unitholders have the right to replace
an operator.
The assets of the Trust represent interests in depleting assets and, if XTO Energy or any other operators
developing the underlying properties do not perform additional successful development projects, the assets may
deplete faster than expected. Eventually, the assets of the Trust will cease to produce in commercial quantities
and the Trust will cease to receive proceeds from such assets.
The net proceeds payable to the Trust are derived from the sale of hydrocarbons from depleting assets.
Future maintenance and development projects on the underlying properties will affect the quantity of proved
reserves and can offset the reduction in the depletion of proved reserves. The timing and size of these projects
will depend on the market prices of oil and natural gas. If the operator(s) of the properties do not implement
additional maintenance and development projects, the future rate of production decline of proved reserves may
be higher than the rate currently expected by the Trust. Because the net proceeds payable to the Trust are
derived from the sale of hydrocarbons from depleting assets, the portion of distributions to unitholders attributable
to depletion may be considered a return of capital as opposed to a return on investment. Distributions that are a
return of capital will ultimately diminish the depletion tax benefits available to the unitholders, which could reduce
the market value of the units over time. Eventually, the properties underlying the Trust’s net profits interests will
cease to produce in commercial quantities and the Trust will, therefore, cease to receive any net proceeds
therefrom.
XTO Energy may transfer its interest in the underlying properties without the consent of the Trust or the Trust
unitholders.
XTO Energy may at any time transfer all or part of its interest in the underlying properties to another party.
Neither the Trust nor the Trust unitholders are entitled to vote on any transfer of the properties underlying the
Trust’s net profits interests, and the Trust will not receive any proceeds of any such transfer. Following any
transfer, the transferred property will continue to be subject to the net profits interests of the Trust, but the
calculation, reporting and remitting of net proceeds to the Trust will be the responsibility of the transferee.
XTO Energy or any other operator of any underlying property may abandon the property, thereby terminating the
related net profits interest payable to the Trust.
XTO Energy or any other operator of the underlying properties, or any transferee thereof, may abandon any
well or property without the consent of the Trust or the Trust unitholders if they reasonably believe that the well or
property can no longer produce in commercially economic quantities. This could result in the termination of the
net profits interest relating to the abandoned well or property.
8
The net profits interests can be sold and the Trust would be terminated. The Trust will also be terminated if it
fails to generate sufficient gross proceeds.
The Trust may sell the net profits interests if the holders of 80% or more of the outstanding Trust units
approve the sale or vote to terminate the Trust. The Trust will terminate if it fails to generate gross proceeds from
the underlying properties of at least $1,000,000 per year over any successive two-year period. Sale of all of the net
profits interests will terminate the Trust. The net proceeds of any sale must be for cash with the proceeds less
administrative costs promptly distributed to the Trust unitholders.
The sale of the remaining net profits interests and the termination of the Trust will be taxable events to the
Trust unitholders. Generally, Trust unitholders will realize gain or loss equal to the difference between the amount
realized on the sale and termination of the Trust and their adjusted basis in such units. Gain or loss realized by a
Trust unitholder who is not a dealer with respect to such units and who has a holding period for the units of more
than one year will be treated as long-term capital gain or loss except to the extent of any depletion recapture
amount, which must be treated as ordinary income. Other federal and state tax issues concerning the Trust are
discussed under Item 2 and Note 6 to the Trust’s financial statements, which are included herein. Trust
unitholders should consult their own tax advisor regarding all Trust tax compliance matters.
Trust unitholders have limited voting rights and have limited ability to enforce the Trust’s rights against XTO
Energy or any other operator of the underlying properties.
The voting rights of a Trust unitholder are more limited than those of stockholders of most public
corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or
other periodic re-election of the Trustee. Additionally, Trust unitholders have no voting rights in XTO Energy or
Exxon Mobil Corporation.
The Trust indenture and related trust law permit the Trustee and the Trust to sue XTO Energy or any other
operator of the underlying properties to compel them to fulfill the terms of the conveyance of the net profits
interests. If the Trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of
the Trust unitholders would likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take
specified actions. Trust unitholders probably would not be able to sue XTO Energy or any other operator of the
underlying properties.
Financial information of the Trust is not prepared in accordance with U.S. GAAP.
The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a
comprehensive basis of accounting other than U.S. generally accepted accounting principles (“U.S. GAAP”).
Although this basis of accounting is permitted for royalty trusts by the Securities and Exchange Commission, the
financial statements of the Trust differ from U.S. GAAP financial statements because net profits income is not
accrued in the month of production, expenses are not recognized when incurred and cash reserves may be
established for certain contingencies that would not be recorded in U.S. GAAP financial statements. See Item 8.
Financial Statements and Supplementary Data – Notes to Financial Statements – Note 2 Basis of Accounting for
additional information.
The limited liability of Trust unitholders is uncertain.
The Trust unitholders are not protected from the liabilities of the Trust to the same extent that a shareholder
would be protected from a corporation’s liabilities. The structure of the Trust does not include the interposition of
a limited liability entity such as a corporation or limited partnership which would provide further limited liability
protection to Trust unitholders. While the Trustee is liable for any excess liabilities incurred if the Trustee fails to
ensure that such liabilities are to be satisfied only out of Trust assets, under the laws of Texas, which are
unsettled on this point, a unitholder may be jointly and severally liable for any liability of the Trust if the
9
satisfaction of such liability was not contractually limited to the assets of the Trust and the assets of the Trust and
the Trustee are not adequate to satisfy such liability. As a result, Trust unitholders may be exposed to personal
liability. The Trust, however, is not liable for production costs or other liabilities of the underlying properties.
Drilling oil and natural gas wells is a high-risk activity and subjects the Trust to a variety of factors that it
cannot control.
Drilling oil and natural gas wells involves numerous risks, including the risk that commercially productive oil
and natural gas reservoirs are not encountered. The presence of unanticipated pressures or irregularities in
formations, miscalculations or accidents may cause drilling activities to be unsuccessful. In addition, there is
often uncertainty as to the future cost or timing of drilling, completing and operating wells. Further, development
activities may be curtailed, delayed or canceled as a result of a variety of factors, including:
1.
2.
3.
4.
5.
6.
7.
8.
reduced oil or natural gas prices;
unexpected drilling conditions;
title problems;
restricted access to land for drilling or laying pipeline;
pressure or irregularities in formations;
equipment failures or accidents;
adverse weather conditions, natural disasters or public health events; and
costs of, or shortages or delays in the availability of, drilling rigs,
equipment.
labor, tubular materials, and
While these risks do not expose the Trust to liabilities of the drilling contractor or operator of the well, they
can reduce net proceeds payable to the Trust and Trust distributions by decreasing oil and gas revenues or
increasing production expense or development costs from the underlying properties. Furthermore, these risks may
cause the costs of development activities on the underlying properties to exceed the revenues therefrom, thereby
reducing net proceeds payable to the Trust and Trust distributions.
The underlying properties are subject to complex federal, state and local laws and regulations that could
adversely affect net proceeds payable to the Trust and Trust distributions.
Extensive federal, state and local regulation of the oil and natural gas industry significantly affects operations
on the underlying properties. In particular, oil and natural gas development and production are subject to stringent
environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing,
operating and abandoning oil and natural gas wells and other related facilities, which costs could reduce net
proceeds payable to the Trust and Trust distributions. These regulations may become more demanding in the
future. These regulations can often be changed by administrative agencies without formal legislation, resulting in
additional costs that can impact distributions. See Item 2. Properties – Regulation, and Item 7. Trustee’s
Discussion and Analysis of Financial Condition and Results of Operations – Greenhouse Gas Emissions and
Climate Change Regulations.
Cash held by the Trustee is not insured by the Federal Deposit Insurance Corporation.
Currently, cash held by the Trust reserved for the payment of accrued liabilities and estimated future
expenses and distributions to unitholders is typically held in a treasury fund that under normal market conditions
invests exclusively in U.S. Treasury obligations. Although the fund’s underlying investments are obligations of the
U.S. government, the fund itself is not insured by the Federal Deposit Insurance Corporation. In the event that the
fund becomes insolvent, the Trustee may be unable to recover any or all such cash from the insolvent fund. Any
loss of such cash may have a material adverse effect on the Trust’s cash balances and any distributions to
unitholders.
10
The tax treatment of an investment in Trust units could be affected by recent and potential legislative changes,
possibly on a retroactive basis.
U.S. federal tax reform legislation informally known as the Tax Cuts and Jobs Act (“TCJA”) was enacted
December 22, 2017, and made significant changes to the federal income tax rules applicable to both individuals
and entities, including changes to the effective tax rate on a Trust unitholder’s allocable share of certain income
from the Trust. The TCJA is complex and Trust unitholders should consult their tax advisor regarding the TCJA and
its effect on an investment in Trust units. In addition, the current administration has generally proposed repealing
fossil fuel tax subsidies, which could impact certain tax benefits available to Trust unitholders.
Any modification to the U.S. federal income tax laws or interpretations thereof may be applied retroactively
and could adversely affect our business, financial condition or results of operations. The Trust is unable to predict
whether any changes or other proposals will ultimately be enacted, or whether any adverse interpretations will be
used. Any such changes or interpretations could negatively impact the value of an investment in the Trust units.
ITEM 1B. UNRESOLVED STAFF COMMENTS
As of December 31, 2023, the Trust did not have any unresolved Securities and Exchange Commission staff
comments.
ITEM 1C. CYBERSECURITY
The Trust does not have a board of directors; therefore, the Trustee is responsible for oversight of the Trust’s
risks from cybersecurity threats. The Trustee has dedicated personnel that are responsible for assessing and
managing the Trust’s cyber risk management program, informing senior management of the Trustee regarding the
prevention, detection, mitigation, and remediation of cybersecurity incidents and supervising such efforts. The
Trustee’s information technology team has decades of experience selecting, deploying, and operating
cybersecurity technologies,
intelligence as well as other
information obtained from governmental, public or private sources, including external consultants engaged by the
Trustee to monitor the prevention, detection, mitigation, and remediation of cybersecurity incidents. External
partners are a key part of the Trustee’s cybersecurity protocols and policies. The Trustee works with leading firms
in the cybersecurity industry, leveraging their technology and expertise to monitor and maintain the performance
and effectiveness of products and services that are used by the Trustee.
initiatives, and processes, and relies on threat
The Trustee maintains a cyber risk management program designed to identify, assess, manage, mitigate, and
respond to cybersecurity threats, which processes are integrated into the Trustee’s overall risk management
process. The Trustee maintains robust cybersecurity protocols including, but not limited to technological
capabilities that prevent and detect disruptions; computer workstations and programs protected with passwords
and passphrases, as well as employee training throughout the year on financial regulations and cybersecurity
followed up by testing of that knowledge. The protocols are based on recognized best practices and standards for
cybersecurity and information technology. The Trustee has an annual assessment, performed by a third-party
vendor, of the Trustee’s cyber risk management program.
Other, non-technical protocols include securing of documents and work areas that could contain personal,
non-public information and independent verification of information changes by outside vendors.
The Trust faces risks from cybersecurity threats that could have a material adverse effect on its business,
financial condition, results of operations, cash flows or reputation. The Trustee has experienced, and will continue
to experience, cyber incidents in the normal course of its business. However, prior cybersecurity incidents have
not had a material adverse effect on the Trust’s business, financial condition, results of operations, or cash flows.
See Item 1A. Risk Factors – The Trust may be subject to attempted cybersecurity disruptions from a variety of
sources including state-sponsored actors.
11
ITEM 2. PROPERTIES
The net profits interests are the principal asset of the Trust. The Trustee cannot acquire any other assets,
with the exception of certain short-term investments as specified under Item 1. Business. The Trustee may sell or
otherwise dispose of all or any part of the net profits interests if approved by a vote of holders of 80% or more of
the outstanding Trust units, or upon termination of the Trust. Otherwise, the Trust is required to sell up to one
percent of the value of the net profits interests in any calendar year, pursuant to notice from XTO Energy of its
desire to sell the related underlying properties. Any sale must be for cash with 80% of the proceeds distributed to
the unitholders on the next declared distribution. All the underlying properties are currently owned by XTO Energy.
XTO Energy may sell all or any portion of the underlying properties at any time, subject to and burdened by the net
profits interests.
The underlying properties are predominantly gas-producing properties with established production histories
in the Hugoton area of Oklahoma and Kansas, the Anadarko Basin of Oklahoma and the Green River Basin of
Wyoming. The average reserve-to-production index for the underlying properties as of December 31, 2023, is
approximately 10 years. This index is calculated using total proved reserves and estimated 2024 production for the
underlying properties. The projected 2024 production is from proved developed producing reserves as of
December 31, 2023. Based on estimated future net cash flows at 12-month average oil and gas prices, based on
the first-day-of-the-month price for each month in the period, the future net cash flows from proved reserves of
the underlying properties are approximately 55 percent natural gas and 45 percent oil. XTO Energy operates
approximately 95 percent of the underlying properties.
Because the underlying properties are working interests, production expense, development costs and
overhead are deducted in calculating net profits income. As a result, net profits income is affected by the level of
maintenance and development activity on the underlying properties. See Item 7. Trustee’s Discussion and
Analysis of Financial Condition and Results of Operations. Total 2023 development costs deducted for the
underlying properties were $9.5 million, an increase of $7.1 million from the prior year. XTO Energy has informed
the Trustee that total 2024 budgeted development costs for the underlying properties are approximately $3 million.
Changes in oil or natural gas prices could impact future development plans on the underlying properties.
Significant Properties
Hugoton Area
Natural gas was discovered in the Hugoton area in 1922. With an estimated five million productive acres
covering parts of Texas, Oklahoma and Kansas, the Hugoton area is one of the largest domestic natural gas
producing areas. During 2023, daily sales volumes from the underlying properties in the Hugoton area averaged
approximately 5,600 Mcf of gas and 30 Bbls of oil.
Most of the production from the underlying properties in the Hugoton area is from the Chase formation. XTO
Energy has informed the Trustee that it has begun to develop other formations that underlie the 79,500 net acres
held by production by the Chase formation wells, which include the Council Grove, Morrow, Chester and St. Louis
formations. These formations are characterized by both oil and gas production from a variety of structural and
stratigraphic traps. Prior to 2011, XTO Energy drilled wells to these formations and plans to continue this
development program sometime in the future.
Within this area, XTO Energy did not drill any new wells or perform any workovers in 2023. XTO Energy has
informed the Trustee that it does not plan to drill any new wells or perform any workovers during 2024.
12
XTO Energy’s future development plans for the underlying properties in the Hugoton area may include:
1.
2.
3.
4.
5.
6.
additional compression to lower line pressures;
installing artificial lift;
opening new producing zones in existing wells;
restimulating producing intervals in existing wells utilizing new technology;
deepening existing wells to new producing zones; and
future drilling of additional wells.
Effective May 1, 2014, XTO Energy entered into a gas sales and processing contract with DCP Midstream, L.P.
to process all gas production from its wells attached to the Timberland Gathering System in Seward County,
Kansas and in Texas and Beaver Counties, Oklahoma. XTO Energy has advised the Trustee that the system
collects approximately 7,000 Mcf per day, of which the majority of its throughput is from underlying properties.
XTO Energy receives 100% of the net value for residue gas based upon a price per MMBtu of Panhandle Eastern
Pipe Line Company index. Under this contract DCP is entitled to charge a processing fee of $0.25 per Delivery
Point MMBtu and a helium processing fee of $0.05 per 97% Delivery Point Mcf in addition to other deductions
such as for fuel and transportation. XTO Energy has exercised its contractual right to take in kind and sell its NGLs
and helium. XTO Energy sells 100% of the net value for any recovered NGLs to an ExxonMobil affiliate at Conway
pricing as posted by Oil Price Information Services minus an adjusted base differential. XTO Energy sells the
helium to Air Products and Chemicals, Inc. and Air Products Helium, Inc. under a pricing formula based upon the
open market crude helium sales price established by the U.S. Bureau of Land Management. Timberland
Gathering & Processing Company, Inc. (“Timberland”), an affiliate of XTO Energy, provides gathering from the
wellhead to DCP’s gathering system for a fee of $0.75 per Mcf of gas delivered by XTO Energy. The sales contract
with DCP Midstream, L.P. has passed its primary term date of March 31, 2019, and is currently being renewed
annually on an evergreen basis, and can be canceled by either party upon 180 days written notice.
Other Hugoton gas production is sold under a third-party contract that remains in effect for the life of the
lease. Under the contract, XTO Energy receives 74.5% of the net proceeds received by the buyer from the sale of
the residue gas and liquids produced from certain underlying properties. The residue gas net proceeds are based
upon the weighted average price of the gas sold by the buyer at its facilities, and the liquids net proceeds are
based upon an average daily index sales price, less transportation, processing and storage fees incurred by the
buyer. The buyer agrees to use its best efforts to take all of the gas produced, subject to its market requirements.
The buyer has been taking all of the gas produced for over ten years.
Anadarko Basin
Oil and gas accumulations were discovered in the Anadarko Basin of western Oklahoma in 1945. XTO Energy
is one of the largest producers in the Ringwood, Northwest Okeene and Cheyenne Valley fields of Major County,
the Northeast Cedardale field of Woodward County and the Elk City field of Beckham County, the principal
producing regions of the underlying properties in the Anadarko Basin. Daily sales volumes from the underlying
properties in the Anadarko Basin averaged approximately 12,200 Mcf of gas and 550 Bbls of oil in 2023.
The fields in the Major County area are characterized by oil and gas production from a variety of structural
and stratigraphic traps. Productive zones include the Oswego, Red Fork, Inola, Chester, Manning, Mississippian,
Hunton and Arbuckle formations. Within this area, XTO Energy performed one workover in 2023. XTO Energy has
informed the Trustee that it does not plan to drill any new wells or perform any workovers in Major County during
2024.
The fields within Woodward County are characterized primarily by gas production from a variety of structural
and stratigraphic traps. Productive zones include the Cottage Grove, Oswego, Chester and Mississippian
formations. Within this area, XTO Energy did not drill any wells or perform any workovers in 2023. XTO Energy has
informed the Trustee that it does not plan to drill any new wells or perform any workovers in Woodward County
during 2024.
13
The Elk City field on the eastern edge of Beckham County produces oil and gas from a structural anticline
with stratigraphic trapping features. Production zones include the Hoxbar, Atoka and Morrow formations. Within
this area, XTO Energy performed one workover in 2023. XTO Energy has informed the Trustee that it does not plan
to drill any new wells or perform any workovers within the Elk City field during 2024.
XTO Energy’s future development plans for the underlying properties in the Anadarko Basin may include:
1. mechanical stimulation of existing wells;
2.
3.
4.
5.
installing artificial lift;
opening new producing zones in existing wells;
deepening existing wells to new producing zones; and
future drilling of additional wells.
A gathering subsidiary of XTO Energy operates a 300-mile gathering system and pipeline in the Major County
area. The gathering subsidiary and a third-party processor purchase natural gas produced at the wellhead from
XTO Energy and other producers in the area under various agreements, most of which were entered into in the
1960’s and 1970’s, and which include life-of-production terms such that the contracts will continue until there is no
further production from the underlying properties, unless the production declines so that it is no longer
economical to take the gas. The gathering subsidiary and the third-party processor are required to take certain
minimum volumes of the gas produced but have been taking all of the volumes produced for over ten years. The
gathering subsidiary gathers and transports the gas to a third-party processor, which processes the gas and pays
XTO Energy and other producers for at least 50 percent of the liquids processed based upon a weighted average
sales price less transportation charges, which price may vary in the event of inadequate markets. After the gas is
processed, the gathering subsidiary transports the gas via a residue pipeline to a connection with an interstate
pipeline. The gathering subsidiary pays XTO Energy for the residue gas based upon a weighted average price from
downstream sales to third parties, which price will vary monthly based upon market conditions. The gathering
subsidiary pays this price to XTO Energy less a compression and gathering fee of approximately $0.31 per Mcf of
residue gas. This gathering fee was previously approved by the Federal Energy Regulatory Commission when the
gathering subsidiary was regulated. As of December 31, 2023, the gathering system was collecting approximately
5,800 Mcf per day, approximately 65 percent of which are operated by XTO Energy. Estimated capacity of the
gathering system is 21,000 Mcf per day. The gathering subsidiary also provides contract operating services to
properties in Woodward County, collecting approximately 2,050 Mcf per day, for an average fee of approximately
$0.48 per Mcf. The fee is subject to an annual price renegotiation under which either party can request that the
price provided under the contract be renegotiated. The contract continues on a yearly basis, and it is subject to
termination upon written notice prior to its annual renewal or in the event the parties fail to agree upon a pricing
renegotiation. XTO Energy also sells gas directly to third parties. The price paid to XTO Energy is based upon the
weighted average price of several published indices, which price varies upon market conditions, and includes a
deduction for any transportation fees charged by the third party. Neither party has a firm obligation to sell or
purchase any specific minimum quantity of gas.
Green River Basin
The Green River Basin is located in southwestern Wyoming. Natural gas was discovered in the Fontenelle
field of the Green River Basin in the early 1970’s. The producing reservoirs are the Frontier, Baxter and Dakota
sandstones.
Daily 2023 sales volumes from the underlying properties in the Fontenelle field averaged approximately 8,000
Mcf of natural gas and 20 Bbls of oil. XTO Energy did not drill any wells or perform any workovers in the Green
River Basin in 2023. XTO Energy has advised the Trustee that it does not plan to drill any new wells or perform any
workovers in the Green River Basin during 2024. XTO Energy has advised the Trustee that it is continuing its efforts
to reduce pipeline pressure which has shown potential for increasing production and extending field life in the
Fontenelle field.
14
Potential development activities for the underlying properties in this area include:
1.
2.
3.
4.
installing artificial lift;
restimulating producing intervals utilizing new technology;
additional compression to lower line pressures; and
opening new producing zones in existing wells.
XTO Energy markets the gas produced from the Fontenelle field and nearby properties under various
marketing arrangements. Under the agreement covering the majority of the gas sold, XTO Energy compresses the
gas on the lease, transports it off the lease and compresses the gas again prior to entry into the gas plant pipeline.
The pipeline transports the gas to the gas plant, where the gas is processed, then redelivered to XTO Energy. The
owner of the gas plant and related pipeline charges XTO Energy for operational fuel and processing and has
agreed to accept certain volumes, which amounts can be adjusted by the owner. The owner may be able to cease
taking volumes if it has valid unaddressed concerns regarding the creditworthiness of XTO Energy. In 2023, the
fuel charge was approximately one percent of the volumes produced and the fee was approximately $0.14 per
MMBtu. These charges are adjusted annually based upon a published governmental economic index, and the
contract renews on a year-to-year basis. XTO Energy transports and sells this gas directly to the markets based
on a spot sales price on a month-to-month term, and the volumes to be sold are generally determined upon a
monthly basis. These contracts may be terminated by either party if there are credit issues with the other party.
The gas not sold under the above arrangement may be gathered and sold under a similar arrangement on a
month-to-month term where the fee is approximately $0.13 per MMBtu and is adjusted annually. The amount of
gas that the gatherer is required to gather is limited to certain maximum volumes, and the gatherer may be able to
cease taking volumes if it has valid unaddressed concerns regarding the creditworthiness of XTO Energy.
Alternatively, the gas may be sold under a contract where XTO Energy directly sells the gas to a third party on the
lease at an adjusted index price, which price varies upon market conditions. The contract continues on a
month-to-month basis, and the buyer is obligated to make a good faith effort to purchase a minimum 90 percent of
the gas nominated by buyer for purchase. Condensate is sold to an independent third party at market rates on a
month-to-month basis. The purchaser accepts all condensate delivered at the lease, but either party may suspend
performance of the contract if there are credit issues with the other party.
Producing Acreage, Drilling and Well Counts
For the following data, “gross” refers to the total wells or acres on the underlying properties in which XTO
Energy owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working
interest owned by XTO Energy. Although many of XTO Energy’s wells produce both oil and gas, a well
is
categorized as an oil well or a gas well based upon the ratio of oil to natural gas production. Operated wells are
managed by XTO Energy, while non-operated wells are managed by others.
The underlying properties are interests in developed properties located primarily in gas producing regions of
Kansas, Oklahoma and Wyoming. The following is a summary of the approximate producing acreage of the
underlying properties at December 31, 2023. Undeveloped acreage is not significant.
Hugoton Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Anadarko Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Green River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
201,032
151,699
35,862
189,142
119,400
28,151
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
388,593
336,693
Gross
Net
15
The following is a summary of the producing wells on the underlying properties as of December 31, 2023:
Operated
Wells
Non-Operated
Wells
Total (a)
Gross
Net
Gross
Net
Gross
Net
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil
987.0
36.0
883.8
33.9
192.0
28.0
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,023.0
917.7
220.0
43.6
3.9
47.5
1,179.0
64.0
927.4
37.8
1,243.0
965.2
(a) During 2023, 2022, and 2021 there were no exploratory wells drilled on the underlying properties. There were
no dry wells drilled in 2023 and 2021 and there was one gross (0.01 net) non-operated dry well drilled in 2022.
There were three gross (1.53 net), one gross (0.35 net), and one gross (0.67 net) developmental wells drilled in
2023, 2022, and 2021, respectively. Not included in the total is one gross (0.22 net) non-operated well in
progress of drilling at December 31, 2023.
Estimated Proved Reserves and Future Net Cash Flows
The following are proved reserves of the underlying properties, as estimated by independent engineers, and
proved reserves and future net cash flows from proved reserves of the net profits interests, based on an
allocation of these reserves, at December 31, 2023:
Underlying Properties
Proved Reserves (a)
Gas
(Mcf)
Oil
(Bbls)
(in thousands)
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
56,325
17,772
4,925
79,022
1,318
21
95
1,434
Net Profits Interests
Proved Reserves (a) (b)
Gas
(Mcf)
7,329
—
—
7,329
Oil
(Bbls)
171
—
—
171
Future Net Cash Flows
from Proved Reserves (a) (c)
Discounted
Undiscounted
$27,056
—
—
$27,056
$19,012
—
—
$19,012
(a) Based on 12-month average oil price of $75.88 per Bbl and $2.59 per Mcf
for gas, based on the
first-day-of-the-month price for each month in the period.
(b) Since the Trust has defined net profits interests, the Trust does not own a specific percentage of the oil and
gas reserves. Oil and gas reserves are allocated to the net profits interests by dividing Trust net cash inflows
by 12-month average oil and gas prices. As such, reserves allocated to the Trust have been reduced to
reflect recovery of the Trust’s portion of applicable production and development costs, which includes
overhead and excess costs. Any conveyance where costs exceed revenues will result in zero allocated net
profits interests reserves for that conveyance.
(c) Before income taxes, since future net cash flows are not subject to taxation at the trust level. Future net cash
flows are discounted at an annual rate of 10 percent.
Proved reserves at December 31, 2023, consist of the following:
Underlying Properties
Proved Reserves
Oil
(Bbls)
Gas
(Mcf)
Net Profits Interests
Proved Reserves
Oil
(Bbls)
Gas
(Mcf)
(in thousands)
Proved developed producing reserves . . . . . . . . . . . . . .
Proved undeveloped reserves . . . . . . . . . . . . . . . . . . . . .
Proved developed non-producing reserves . . . . . . . . . .
Total proved reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . .
79,022
—
—
79,022
1,434
—
—
1,434
7,329
—
—
7,329
171
—
—
171
16
The process of estimating oil and gas reserves is complex and requires significant judgment as discussed in
Item 1A. Risk Factors, and is performed by XTO Energy. As a result, XTO Energy has developed internal policies
and controls for estimating and recording reserves. XTO Energy’s policies regarding booking reserves require
proved reserves to be in compliance with the SEC definitions and guidance. XTO Energy’s policies assign
responsibilities for compliance in reserves bookings to its reserve engineering group and require that reserve
estimates be made by qualified reserves estimators, as defined by the Society of Petroleum Engineers’ standards.
All qualified reserves estimators are required to receive education covering the fundamentals of SEC proved
reserves assignments.
The XTO Energy reserve engineering group reviews reserve estimates with third-party petroleum
consultants, Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents, Ltd. estimated oil and gas
reserves attributable to the underlying properties as of December 31, 2023. Miller and Lents’ primary technical
person responsible for calculating the Trust’s reserves has more than 12 years of experience as a reserve
engineer. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the
estimated oil and gas reserves attributable to the net profits interests. Numerous uncertainties are inherent in
estimating reserve volumes and values, and such estimates are subject to change as additional information
becomes available. The reserves actually recovered and the timing of production of these reserves may be
substantially different from the original estimates.
Reserve quantities and revenues for the net profits interests were estimated from projections of reserves
and revenues attributable to the underlying properties. Since the Trust has defined net profits interests, the Trust
does not own a specific percentage of the oil and gas reserves. Oil and gas reserves are allocated to the net
profits interests by dividing Trust net cash inflows by 12-month average oil and gas prices.
Oil and Natural Gas Production
Trust production is recognized in the period net profits income is received, which is the month following
receipt by XTO Energy, and generally two months after the time of production. Oil and gas sales volumes are
allocated to the net profits interests based upon a formula that considers oil and gas prices and the total amount
of production expense and development costs. As such, the underlying property production volume changes may
not correlate with the Trust’s net profit share of those volumes in any given period.
Oil and gas production and average sales prices attributable to the underlying properties and the net profits
interests for each of the three years ended December 31 were as follows:
2023
2022
2021
Production
Underlying Properties
Gas – Sales (Mcf) . . . . . . . . . . . . . . . . . . . . . . . .
Average per day (Mcf) . . . . . . . . . . . . . . . . . .
Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . .
Average per day (Bbls) . . . . . . . . . . . . . . . . . .
Net Profits Interests
Gas – Sales (Mcf) . . . . . . . . . . . . . . . . . . . . . . . .
Average per day (Mcf) . . . . . . . . . . . . . . . . . .
Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . .
Average per day (Bbls) . . . . . . . . . . . . . . . . . .
Average Sales Price
9,397,772
25,747
217,440
596
990,526
2,714
11,205
31
9,771,977
26,773
245,586
673
2,440,780
6,687
48,829
134
Gas (per Mcf)
Oil (per Bbl)
Average Production
. . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost per BOE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
5.18
75.88
18.36
$
$
$
7.08
83.91
16.16
$
$
$
10,193,158
27,926
232,576
637
—
—
—
—
4.05
59.25
13.37
17
Oil and gas production by conveyance attributable to the underlying properties for each of the three years
ended December 31 were as follows:
Conveyance
Underlying Gas Production (Mcf)
2022
2021
2023
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5,845,567
2,921,925
630,280
5,833,016
3,249,822
689,139
6,002,087
3,480,757
710,314
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,397,772
9,771,977
10,193,158
Conveyance
Underlying Oil Production (Bbls)
2022
2021
2023
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
201,461
6,267
9,712
217,440
181,577
7,169
56,840
245,586
220,964
7,789
3,823
232,576
Pricing and Sales Information
XTO Energy sells most of its natural gas production directly to third parties, and a portion is sold to certain of
XTO Energy’s wholly owned subsidiaries based on a weighted average sales price. The weighted average sales
price received from the subsidiary is based upon sales to third parties for the best available price. Oil production
is generally marketed at the wellhead to third parties at the best available price. XTO Energy arranges for some of
its natural gas to be processed by unaffiliated third parties and markets the natural gas liquids. Some of the
natural gas attributable to the underlying properties is marketed under contracts existing at Trust inception.
Contracts covering production from the Ringwood area of the Major County area are generally for the life of the
lease. The contract with an unaffiliated third party for the majority of production from the Hugoton area is in effect
through the life of the lease. If new contracts are entered with unaffiliated third parties, the proceeds from sales
under those new contracts will be included in gross proceeds from the underlying properties. If new contracts are
entered with any subsidiary of XTO Energy, it may charge XTO Energy a fee that may not exceed two percent of
the sales price of the oil and natural gas received from unaffiliated parties. The sales price is net of any
deductions for transportation from the wellhead to the unaffiliated parties and any gravity or quality adjustments.
For further information on these arrangements see “Significant Properties” above.
Regulation
Natural Gas Regulation
The interstate transportation and sale for resale of natural gas is subject to federal regulation, including
transportation and storage rates charged, tariffs, and various other matters, by the Federal Energy Regulatory
Commission (“FERC”). Federal price controls on wellhead sales of domestic natural gas terminated on January 1,
1993. While natural gas prices are currently unregulated, Congress historically has been active in the area of
natural gas regulation. 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 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 FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the
Energy Policy Act, including enforcement rules and new annual reporting requirements for certain sellers of
natural gas. It is impossible to predict whether new legislation to regulate natural gas might be proposed, what
proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any,
such proposals might have on the operations of the underlying properties.
18
Federal Regulation of Oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market
prices. The net price received from the sale of these products is affected by market transportation costs. Under
rules adopted by FERC effective January 1995, interstate oil pipelines can change rates based on an inflation
index, though other rate mechanisms may be used in specific circumstances.
On December 19, 2007, the President signed into law the Energy Independence & Security Act of 2007
(PL 110-140) (“EISA”). 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. XTO Energy has advised the Trustee
that it cannot predict the impact of future government regulation on any crude oil, condensate or natural gas
liquids facilities, sales or transportation transactions.
Environmental Regulation
Companies that are engaged in the oil and gas industry are affected by federal, state and local
laws
regulating the discharge of materials into the environment. Those laws may impact operations of the underlying
properties. No material expenses have been incurred on the underlying properties in complying with
environmental laws and regulations. XTO Energy does not expect that future compliance will have a material
adverse effect on the Trust.
There is an increased focus by local, national and international regulatory bodies on greenhouse gas
(“GHG”) emissions and climate change. Several states have adopted climate change legislation and regulations,
and various other regulatory bodies have announced their intent to regulate GHG emissions or adopt climate
change regulations. As these regulations are under development, XTO Energy is unable to predict the total impact
of the potential regulations upon the operators of the underlying properties, and it is possible that operators of the
underlying properties could face increases in operating costs in order to comply with climate change or GHG
emissions legislation, which costs could reduce net proceeds payable to the Trust and Trust distributions.
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 allowable from both oil and gas wells may be established on a market demand or conservation basis,
or both.
Federal Income Taxes
For federal income tax purposes, the Trust constitutes a fixed investment trust that is taxed as a grantor trust.
A grantor trust is not subject to tax at the trust level. The unitholders are considered to own the Trust’s income
and principal as though no trust were in existence. The income of the Trust is deemed to have been received or
accrued by each unitholder at the time such income is received or accrued by the Trust and not when distributed
by the Trust. Impairments recorded for book purposes will not result in a loss for tax purposes for the unitholders
until the loss is recognized.
Because the Trust is a grantor trust for federal tax purposes, unitholders are taxed directly on their
proportionate share of income, deductions and credits of the Trust consistent with each such unitholder’s taxable
year and method of accounting and without regard to the taxable year or method of accounting employed by the
Trust. The income of the Trust consists primarily of a specified share of the net profits from the sale of oil and
19
natural gas produced from the underlying properties. The Trust also incurs administration expenses and may earn
interest income on funds held for distribution and on the cash reserve maintained for the payment of contingent
and future obligations of the Trust.
The Trust generally allocates its items of income, gain,
loss and deduction between transferors and
transferees of the units each month based upon the ownership of the Trust units on the monthly record date,
instead of on the basis of the date a particular unit is transferred. It is possible that the IRS could disagree with
this allocation method and could assert that income and deductions of the Trust should be determined and
allocated on a daily or prorated basis, which could require adjustments to the tax returns of the unitholders
affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.
The net profits interests constitute “economic interests” in oil and gas properties for federal tax purposes.
Each unitholder is entitled to amortize the cost of the units through cost depletion over the life of the net profits
interests or, if greater, through percentage depletion equal to 15 percent of the gross income from such net profits
interest, limited to 100 percent of the net income from such net profits interests. Unlike cost depletion, percentage
depletion is not limited to a unitholder’s depletable tax basis in the units. Rather, a unitholder is entitled to a
percentage depletion deduction as long as the applicable underlying properties generate gross income.
Unitholders should compute both percentage depletion and cost depletion from each property and claim the
larger amount as a deduction on their income tax returns.
Unitholders must maintain records of their adjusted basis in their Trust units (generally their cost less prior
depletion deductions), make adjustments for depletion deductions to such basis, and use the adjusted basis for
the computation of gain or loss on the disposition of the Trust units.
If a taxpayer disposes of any “Section 1254 property” (certain oil, gas, geothermal or other mineral property),
and the adjusted basis of such property includes adjustments for depletion deductions under Section 611 of the
Internal Revenue Code (the “Code”), the taxpayer generally must recapture the amount deducted for depletion as
ordinary income (to the extent of gain realized on such disposition). This depletion recapture rule applies to any
disposition of Section 1254 property that was placed in service by the taxpayer after December 31, 1986. Detailed
rules set forth in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury Regulations govern dispositions of
property after March 13, 1995.
Interest and net profits income attributable to ownership of units and any gain on the sale thereof are
considered portfolio income, and not income from a “passive activity,” to the extent a unitholder acquires and
holds units as an investment and not in the ordinary course of a trade or business. Therefore, interest and net
profits income attributable to ownership of units generally may not be offset by losses from any passive activities.
Under the TCJA, for tax years beginning after December 31, 2017, and before January 1, 2026, the highest
marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37 percent, and the highest
marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or
exchange of certain investment assets held for more than one year) and qualified dividends of individuals is
20 percent. Under the TCJA, for such tax years, personal exemptions and miscellaneous itemized deductions are
not allowed. Further, the U.S. federal income tax rate applicable to corporations is 21 percent, and such rate
applies to both ordinary income and capital gains.
Section 1411 of the Code imposes a 3.8 percent Medicare tax on certain investment income earned by
individuals, estates, and trusts. For these purposes,
investment income generally will include a unitholder’s
allocable share of the Trust’s interest and net profits income plus the gain recognized from a sale of Trust units. In
the case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all
investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified
threshold levels depending on such individual’s federal income tax filing status. In the case of an estate or trust,
the tax is imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross
income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.
20
The difference between the per-unit taxable income for any period and the per-unit cash distributions, if any,
reported for such period is attributable to (i) items that reduce cash distributions but are not currently deductible,
such as an increase in the cash reserve maintained by the Trust for the payment of future expenditures; (ii) the
current deduction of expenses that are paid with amounts previously reserved; (iii) items that increase cash
distributions but do not constitute taxable income, such as a decrease in the cash reserve maintained by the Trust
and/or a return of capital; and (iv) items that constitute taxable income due to the recovery of prior period expense
adjustments. Because of these types of items and when the Trustee elects to reserve amounts from monthly
distributions to maintain an administrative expense reserve, the taxable income per period frequently differs from
the actual amount distributed to unitholders.
Individuals may also incur expenses in connection with the acquisition or maintenance of Trust units. For tax
years beginning before January 1, 2018, and after December 31, 2025, these expenses, which are different from a
unitholder’s share of the Trust’s administrative expenses discussed above, may be deductible as “miscellaneous
itemized deductions” only to the extent that such expenses exceed two percent of the individual’s adjusted gross
income. Under the TCJA, for tax years beginning after December 31, 2017, and before January 1, 2026,
miscellaneous itemized deductions are not allowed.
Pursuant to the Foreign Account Tax Compliance Act (commonly referred to as “FATCA”), distributions from
the Trust to “foreign financial institutions” and certain other “non-financial foreign entities” may be subject to U.S.
withholding taxes. Specifically, certain “withholdable payments” (including certain royalties, interest and other
gains or income from U.S. sources) made to a foreign financial institution or non-financial foreign entity will
generally be subject to the withholding tax unless the foreign financial institution or non-financial foreign entity
complies with certain information reporting, withholding, identification, certification and related requirements
imposed by FATCA. Foreign financial
institutions located in jurisdictions that have an intergovernmental
agreement with the United States governing FATCA may be subject to different rules.
The Treasury Department issued guidance providing that the FATCA withholding rules described above
generally will apply to qualifying payments made after June 30, 2014. Foreign unitholders are encouraged to
consult their own tax advisor regarding the possible implications of these withholding provisions on their
investment in Trust units.
Some Trust units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and
includes custodians, nominees, certain joint owners, and brokers holding an interest for a customer in street
name, collectively referred to herein as “middlemen”). Therefore, the Trustee considers the Trust to be a
non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. Argent Trust
Company, EIN: 62-1437218, 3838 Oak Lawn Ave, Suite 1720, Dallas, Texas, 75219, telephone number 1-855-588-7839,
email address Trustee@hgt-hugoton.com, is the representative of the Trust that will provide tax information in
accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the
Trust as a WHFIT. Tax information is also posted by the Trustee at www.hgt-hugoton.com. Notwithstanding the
foregoing, the middlemen holding Trust units on behalf of unitholders, and not the Trustee of the Trust, are solely
responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with
including the issuance of IRS Forms 1099 and certain written tax statements.
respect to such Trust units,
Unitholders whose Trust units are held by middlemen should consult with such middlemen regarding the
information that will be reported to them by the middlemen with respect to the Trust units.
Unitholders should consult their tax advisor regarding Trust tax compliance matters.
State Income Taxes
All revenues from the Trust are from sources within Kansas, Oklahoma or Wyoming. Kansas and Oklahoma
each impose a state income tax, which is potentially applicable to income from the net profits interests located in
each of those states. Because it distributes all of its net income to unitholders, the Trust is not taxed at the trust
21
level in Kansas or Oklahoma. While the Trust does not owe tax, the Trustee is required to file an Oklahoma income
tax return reflecting the income and deductions of the Trust attributable to properties located in the state, along
with a schedule that includes information regarding distributions to unitholders. Oklahoma taxes the income of
nonresidents from real property located within the state, and the Trust has been advised by counsel that
Oklahoma will tax nonresidents on income from the net profits interest located within the state. Oklahoma also
imposes a corporate income tax that may apply to unitholders organized as corporations (subject to certain
exceptions for S corporations and limited liability companies, depending on their treatment for federal tax
purposes).
Kansas also taxes the income of nonresidents from property located within the state. The Trust did not file a
Kansas income tax return for the 2015 through 2021 tax years due to the fact that there were no revenues, income,
or deductions attributable to properties located in Kansas in that time period.
Wyoming does not impose a state income tax.
Unitholders should consult their own tax advisor regarding state income tax requirements, if any, applicable
to such person’s ownership of Trust units.
State Tax Withholding
Several states have enacted legislation requiring state income tax withholding from payments to nonresident
recipients of oil and gas proceeds. After consultation with its tax counsel, the Trustee believes that it is not
required to withhold on payments made to the unitholders. However, regulations are subject to change by the
various states, which could change this conclusion. Should amounts be withheld on payments made to the Trust
or the unitholders, distributions to the unitholders would be reduced by the required amount, subject to the filing
of a claim for refund by the Trust or unitholders for such amount.
Other Regulation
The petroleum industry is also subject to compliance with various other federal, state and local regulations
and laws, including, but not limited to, regulations and laws relating to environmental protection, occupational
safety, resource conservation and equal employment opportunity. XTO Energy has advised the Trustee that it does
not believe that compliance with these laws will have any material adverse effect upon the unitholders.
ITEM 3. LEGAL PROCEEDINGS
As previously disclosed, XTO Energy advised the Trustee that it reached a settlement with the plaintiffs in the
Chieftain class action royalty case. On July 27, 2018, the final plan of allocation was approved by the court. Based
on the final plan of allocation, XTO Energy advised the Trustee that it believes approximately $24.3 million in
additional production costs should be allocated to the Trust. On May 2, 2018, the Trustee submitted a demand for
arbitration seeking a declaratory judgment that the Chieftain settlement is not a production cost and that XTO
Energy is prohibited from charging the settlement as a production cost under the conveyance or otherwise
reducing the Trust’s payments now or in the future as a result of the Chieftain litigation. The Trust and XTO Energy
conducted the interim hearing on the claims related to the Chieftain settlement on October 12-13, 2020. In the
arbitration, the Trustee contended that the approximately $24.3 million allocation related to the Chieftain
settlement was not a production cost and, therefore, there should not be a related adjustment to the Trust’s share
of net proceeds. However, XTO Energy contended that the approximately $24.3 million was a production cost and
should reduce the Trust’s share of net proceeds.
On January 20, 2021, the arbitration panel issued its Corrected Interim Final Award (i) “reject[ing] the Trust’s
contention that XTO has no right under the Conveyance to charge the Trust with amounts XTO paid under
section 1.18(a)(i) as royalty obligations to settle the Chieftain litigation” and (ii) stating “[t]he next phase will
22
determine how much of the Chieftain settlement can be so charged, if any of it can be, in the exercise of the right
found by the Panel.” Following briefing by both parties, on May 18, 2021, the Panel issued its second interim final
award over the amount of XTO Energy’s settlement in the Chieftain class action lawsuit that can be charged to the
Trust as a production cost. The Panel in its decision has ruled that out of the $80 million settlement, the “Trust is
obligated to pay its share under the Conveyance of the $48 million that was received by the plaintiffs in the
Chieftain lawsuit by virtue of the settlement of that litigation. The Trust is not obligated by the Conveyance to pay
any share of the $32 million received by the lawyers for the plaintiffs in the Chieftain lawsuit by virtue of the
settlement.” XTO Energy and the Trustee are in the process of determining the portion of the $48 million that is
allocable to Trust properties to be charged as an excess cost to the Trust but estimate it to be approximately
$14.6 million net to the Trust.
The reduction in the Trust’s share of net proceeds from the portion of the settlement amount the Panel has
ruled may be charged against the Oklahoma conveyance would result in excess costs under the Oklahoma
conveyance that would likely result in no distributions under the Oklahoma conveyance while these excess costs
are recovered. This award completes the portion of the arbitration related to the Chieftain settlement. Excess
costs on any individual conveyance would not affect net proceeds to the Trust on any of the other remaining
conveyances.
Other Trustee claims related to disputed amounts on the computation of the Trust’s net proceeds for 2014
through 2019 and 2021 were bifurcated from the initial arbitration. Although the arbitration is not terminated, the
final hearing regarding the remaining dispute over net proceeds, previously scheduled to occur on November 8,
2023, was cancelled. XTO Energy and the Trustee will provide material updates as they become available.
Certain of the underlying properties are involved in various other lawsuits and governmental proceedings
arising in the ordinary course of business. XTO Energy has advised the Trustee that, based on the information
available at this stage of the various proceedings, it does not believe that the ultimate resolution of these claims
will have a material effect on the financial position or liquidity of the Trust, but may have an effect on annual
distributable income.
ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable.
23
PART II
ITEM 5. MARKET FOR UNITS OF THE TRUST, RELATED UNITHOLDER MATTERS AND TRUST PURCHASES OF
UNITS
Units of Beneficial Interest
The units of beneficial interest in the Trust began trading on the New York Stock Exchange on April 9, 1999
under the symbol “HGT.” On August 27, 2018, the Trust units were delisted from the NYSE and began to be quoted
on the OTCQX, which is maintained by the OTC Market Group Inc., under the symbol “HGTXU.” The Trust
transitioned from the OTCQX to the OTCQB on May 19, 2020. Any quotations on the OTCQB reflect inter-dealer
prices, without retail mark-up, mark-down, or commission and may not necessarily reflect actual transactions.
At March 19, 2024, there were 40,000,000 units outstanding and approximately 516 unitholders of record;
39,630,379 of these units were held by depository institutions.
The Trust has no equity compensation plans, nor has it purchased any units during the period covered by this
report.
See Item 1. Business for a description of the Trustee’s obligations to make monthly distributions and how the
monthly distribution amount is determined under the indenture.
ITEM 6. [RESERVED]
24
ITEM 7. TRUSTEE’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Calculation of Net Profits Income
The following is a summary of the calculation of net profits income received by the Trust:
Year Ended
December 31 (a)
Three Months Ended
December 31 (a)
2023
2022
2023
2022
Sales Volumes
Gas (Mcf) (b)
Underlying properties . . . . . . . . . . . . . . . . . . . . . . .
Average per day . . . . . . . . . . . . . . . . . . . . . . . . .
Net profits interests . . . . . . . . . . . . . . . . . . . . . . . . .
9,397,772
25,747
990,526
9,771,977
26,773
2,440,780
2,465,801
26,802
—
Oil (Bbls) (b)
Underlying properties . . . . . . . . . . . . . . . . . . . . . . .
Average per day . . . . . . . . . . . . . . . . . . . . . . . . .
Net profits interests . . . . . . . . . . . . . . . . . . . . . . . . .
217,440
596
11,205
245,586
673
48,829
95,885
1,042
—
2,486,247
27,024
1,007,610
45,584
495
19,700
Average Sales Prices
Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
5.18
75.88
$
$
7.08
83.91
$
$
3.37
77.16
$
$
7.53
87.51
Revenues
Gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$48,663,530
16,498,624
$69,197,629
20,607,491
$ 8,302,933
7,398,667
$18,723,053
3,988,840
Total Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
65,162,154
89,805,120
15,701,600
22,711,893
Costs
Taxes, transportation and other . . . . . . . . . . . . . . . . .
Production expense . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development costs . . . . . . . . . . . . . . . . . . . . . . . . . . .
Overhead . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Excess costs (c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,224,150
19,727,285
9,460,301
13,025,797
(3,610,271)
13,169,884
17,692,775
2,390,390
12,587,189
19,534,417
2,573,696
5,178,180
205,602
3,373,745
4,370,377
3,799,727
4,981,516
970,974
3,084,904
—
Total Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
50,827,262
65,374,655
15,701,600
12,837,121
Other Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
32
Net Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Profits Percentage . . . . . . . . . . . . . . . . . . . . . . . . . .
14,334,892
80%
24,430,497
80%
Net Profits Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$11,467,914
$19,544,398
$
—
—
80%
—
—
9,874,772
80%
$ 7,899,818
(a) Because of the two-month interval between time of production and receipt of net profits income by the Trust:
1) oil and gas sales for the year ended December 31 generally relate to 12 months of production for the period
November through October, and 2) oil and gas sales for the three months ended December 31 generally
relate to production for the period August through October.
(b) Oil and gas sales volumes are allocated to the net profits interests by dividing Trust net cash inflows by
average sales prices. As oil and gas prices change, the Trust’s allocated production volumes are impacted
as the quantity of production necessary to cover expenses changes inversely with price. As such, the
underlying property production volume changes may not correlate with the Trust’s allocated production
volumes in any given period. Therefore, comparative discussion of oil and gas sales volumes is based on the
underlying properties.
(c) See Note 4 to Financial Statements under Item 8. Financial Statements and Supplementary Data.
25
Results of Operations
Years Ended December 31, 2023 and 2022
Net profits income for 2023 was $11,467,914, as compared with $19,544,398 for 2022. This was primarily the
result of lower oil and gas prices ($16.5 million), increased development costs ($5.7 million), decreased oil and gas
production ($3.3 million), increased production expenses ($1.6 million), and increased overhead ($0.3 million),
partially offset by net excess costs activity ($18.5 million) and decreased taxes, transportation and other costs
($0.8 million).
Trust administration expense was $1,093,016 in 2023 as compared to $758,312 in 2022. Cash reserve activity
was ($655,952) in 2023 and $1,000,000 in 2022. Cash reserve activity for 2023 included utilization of $655,952 for the
payment of trust expenses. Cash reserve activity for 2022 included additions of $1,000,000 which the Trustee
reserved for administrative expenses. Interest income was $65,670 in 2023 and $16,810 in 2022. Changes in interest
income are attributable to fluctuations in net profits income, cash reserve and interest rates. Distributable income
was $11,096,520 or $0.277413 per unit in 2023 and $16,585,039 or $0.414626 per unit in 2022.
Net profits income is recorded when received by the Trust, which is the month following receipt by XTO
Energy, and generally two months after oil and gas production. Net profits income is generally affected by three
major factors:
1.
2.
3.
oil and gas sales volumes;
oil and gas sales prices; and
costs deducted in the calculation of net profits income.
Volumes
Gas. Underlying gas sales volumes decreased 4 percent from 2022 to 2023 primarily because of natural
production decline and timing of cash receipts, partially offset by gas sales from new wells in Major County,
Oklahoma.
Oil. Underlying oil sales volumes decreased 11 percent from 2022 to 2023 primarily because of natural
production decline and timing of cash receipts, partially offset by oil sales from new wells in Major County,
Oklahoma.
The estimated rate of natural production decline on the underlying oil and gas properties is approximately six
to eight percent a year.
Prices
Gas. The 2023 average gas price was $5.18 per Mcf, down 27 percent from the 2022 average gas price of
$7.08 per Mcf. Natural gas prices are affected by the level of North American production, weather, crude oil and
natural gas liquids prices, the U.S. economy, storage levels and export levels of liquefied natural gas. Natural gas
prices are expected to remain volatile. The average NYMEX price for November 2023 through January 2024 was
$2.83 per MMBtu. At March 15, 2024, the average NYMEX gas price for the following 12 months was $2.70 per
MMBtu.
Oil. The average oil price for 2023 was $75.88 per Bbl, down 10 percent from the average oil price for 2022
of $83.91 per Bbl. Oil prices are expected to remain volatile. The average NYMEX price for November 2023 through
January 2024 was $74.50 per Bbl. At March 15, 2024, the average NYMEX oil price for the following 12 months was
$77.89 per Bbl.
26
Costs
The calculation of net profits income includes deductions for production expense, development costs and
overhead since the related underlying properties are working interests.
Taxes, transportation and other. Taxes, transportation and other costs generally fluctuate with changes in
total revenues. Taxes, transportation and other costs decreased 7 percent from 2022 to 2023 primarily because of
decreased gas production taxes and gas deductions due to lower revenues, partially offset absence of Oklahoma
production tax refunds.
Production expense. Production expense increased 11 percent from 2022 to 2023 primarily because of
increased labor, plug and abandonment expenses, pipeline costs, and repairs and maintenance, partially offset by
decreased power and fuel and salt water disposal costs.
Development costs. Development costs increased $7.1 million from 2022 to 2023 primarily because of timing
of drilling costs related to non-operated wells in Major County, Oklahoma. Changes in oil or natural gas prices
could impact future development plans on the underlying properties.
Overhead. Overhead is charged by XTO Energy and other operators for administrative expenses incurred to
support operations of the underlying properties. Overhead fluctuates based on changes in the active well count
and drilling activity on the underlying properties, as well as an annual cost level adjustment.
Excess costs.
If monthly costs exceed revenues for any of the three conveyances (one for each of the
states of Kansas, Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from
future net proceeds of that conveyance and cannot reduce net proceeds from other conveyances. For further
information on excess costs, including the balance and accrued interest by conveyance, see Note 4 to Financial
Statements under Item 8. Financial Statements and Supplementary Data.
Fourth Quarter 2023 and 2022
Net profits income for fourth quarter 2023 was $0 as compared with $7,899,818 for fourth quarter 2022. This
was primarily the result of lower oil and gas prices ($8.7 million), net excess costs activity ($3.5 million), increased
overhead ($0.2 million), and increased production expenses ($0.2 million), offset by increased oil production
($3.1 million), decreased taxes, transportation and other costs ($1.0 million), and decreased development costs
($0.6 million).
After adding interest income of $8,212, deducting administration expense of $302,627 and utilizing $294,415 of
the cash reserve for the payment of trust expenses, distributable income for fourth quarter 2023 was $0 or
$0.000000 per unit. Distributable income for fourth quarter 2022 was $7,620,680 or $0.190517 per unit.
Distributions to unitholders for the quarter ended December 31, 2023, were:
Record Date
Payment Date
October 31, 2023
November 30, 2023
December 29, 2023
November 14, 2023
December 14, 2023
January 16, 2024
Per Unit
$0.000000
0.000000
0.000000
$0.000000
Volumes
Fourth quarter underlying gas sales volumes decreased 1 percent primarily because of natural production
decline and timing of cash receipts, partially offset by gas sales from new wells in Major County, Oklahoma.
Underlying oil sales increased 110 percent primarily due to oil sales from new wells in Major County, Oklahoma,
partially offset by natural production decline and timing of cash receipts.
27
Prices
The average fourth quarter 2023 gas price was $3.37 per Mcf, down 55 percent from the fourth quarter 2022
average price of $7.53 per Mcf. The average fourth quarter 2023 oil price was $77.16 per Bbl, down 12 percent
from the fourth quarter 2022 average price of $87.51 per Bbl. For further information about product prices, see
“Years Ended December 31, 2023 and 2022 – Prices” above.
Costs
Taxes, transportation and other. Taxes, transportation and other costs decreased 32 percent for the fourth
quarter primarily because of decreased production taxes and gas deductions due to lower gas revenues.
Production expense. Fourth quarter production expense increased 4 percent primarily because of increased
plug and abandonment expenses, labor, and pipeline costs, partially offset by decreased repairs and maintenance
expenses and field costs.
Development costs. Development costs decreased 79 percent for the fourth quarter primarily because of
timing of drilling costs related to non-operated wells in Major County, Oklahoma.
Overhead. Overhead is charged by XTO Energy and other operators for administrative expenses incurred to
support operations of the underlying properties. Overhead fluctuates based on changes in the active well count
and drilling activity on the underlying properties, as well as an annual cost level adjustment.
Excess costs. If monthly costs exceed revenues for any of the three conveyances (one for each of the states
of Kansas, Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from future net
proceeds of that conveyance and cannot reduce net proceeds from other conveyances. For information on
excess costs, including the excess cost balance and accrued interest by conveyance, see Note 4 to Financial
Statements under Item 8. Financial Statements and Supplementary Data.
Liquidity and Capital Resources
The Trust’s only cash requirement is any declared monthly distribution of its income to unitholders, which is
funded by the monthly receipt of net profits income after payment of Trust administration expenses. The Trust is
not liable for any production costs or liabilities attributable to the net profits interests. If at any time the Trust
receives net profits income in excess of the amount due, the Trust is not obligated to return such overpayment,
but future net profits income payable to the Trust will be reduced by the overpayment, plus interest at the prime
rate. The Trust may borrow funds required to pay Trust liabilities if fully repaid prior to further distributions to
unitholders.
The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities
or persons that could materially affect the Trust’s liquidity or the availability of capital resources.
The accompanying financial statements have been prepared assuming that the Trust will continue as a going
concern. Financial statements prepared on a going concern basis assume the realization of assets and the
settlement of liabilities in the normal course of business. Accumulated excess costs for the Kansas, Oklahoma and
Wyoming conveyances have resulted in insufficient net proceeds to the Trust and a reduction in the Trust’s
expense reserve. These conditions raise substantial doubt about the Trust’s ability to continue as a going concern
as the Trust does not have sufficient cash to meet its obligations during the one-year period after the dates that
the financial statements are issued. Factors attributable to the cash shortage are primarily the previously
disclosed development costs to drill three non-operated wells in Major County, Oklahoma, lower oil and natural
gas prices during 2023, and excess cost positions on the Kansas, Oklahoma and Wyoming conveyances including
accumulated interest, which have resulted in no unitholder distributions since July 2023. In addition, on May 18,
28
2021, the arbitration panel issued its second interim final award over the amount of XTO Energy’s settlement in
the Chieftain class action lawsuit that can be charged to the Trust as a production cost which XTO Energy has
estimated to be approximately $14.6 million net to the Trust. This adjustment would further increase excess costs
on the Oklahoma conveyance. The Trustee has prepared a preliminary budget estimating the administrative
expenses for the year ending December 31, 2024, and the three months ending March 31, 2025, which assumes no
cash inflow from either net profits income or from other sources. The Trustee intends to review options for the
Trust which may include alternatives to continuing as a going concern or may include seeking financing to pay the
Trust obligations during the one-year period after the date the financial statements are issued; however, there can
be no assurance that financing will be available on acceptable terms or at all. If financing became available to the
Trust, it would have to be repaid, together with interest, and the Trust’s expense reserve would have to be
replenished prior to any distributions to unitholders.
On July 9, 2020, the Trustee notified XTO Energy of the Trustee’s claim to indemnification to the Trust Estate
for all liability, expense, claims, damages or loss incurred by the Trustee in connection with the administration of
the Trust. The Trustee stated it anticipates seeking reimbursement from XTO Energy upon depletion of the Trust’s
cash reserve. XTO Energy responded that any indemnity claim to XTO Energy is premature before the Trust Estate
is exhausted.
The Trust’s financial statements do not include any adjustments that might result from the outcome of these
uncertainties.
Greenhouse Gas Emissions and Climate Change Regulations
There is an increased focus by local, national and international regulatory bodies on greenhouse gas
(“GHG”) emissions and climate change. A number of nations and U.S. states have adopted or are considering
some form of climate change legislation and regulations, including carbon taxes, cap-and-trade policies and bans
on drilling in certain areas or in certain ways. The climate accord reached at the Conference of the Parties
(COP21) in Paris set many new goals, and while many related policies are still emerging, XTO Energy has informed
the Trustee that it continues to anticipate that such policies will increase the cost of carbon dioxide emissions
over time. As these regulations are under development, XTO Energy is unable to predict the total impact of the
potential regulations upon the operators of the underlying properties, and it is possible that the operators of the
underlying properties could face increases in operating costs or a ban of certain types of activities in order to
comply with climate change or GHG emissions legislation, which costs could reduce or eliminate net proceeds
payable to the Trust and Trust distributions.
Off-Balance Sheet Arrangements
The Trust has no off-balance sheet financing arrangements. The Trust has not guaranteed the debt of any
other party, nor does the Trust have any other arrangements or relationships with other entities that could
potentially result in unconsolidated debt, losses or contingent obligations.
Related Party Transactions
XTO Energy operates approximately 95 percent of the underlying properties. In computing net proceeds, XTO
Energy deducts an overhead charge for reimbursement of administrative expenses on the underlying properties it
operates. As of December 31, 2023, the monthly overhead charge, based on the number of operated wells, was
approximately $1,060,000 ($848,000 net to the Trust) and is subject to annual adjustment based on an oil and gas
industry index as defined in the Trust Indenture.
Certain of XTO Energy’s wholly owned subsidiaries purchase natural gas and provide services for the
properties operated by XTO Energy. In the Hugoton area, Timberland provides gathering from the wellhead to
DCP’s gathering system for approximately $0.75 per Mcf and an ExxonMobil affiliate purchases NGLs for a price
29
based upon third-party sales. A portion of the gas production in Major County, Oklahoma is sold to Ringwood
Gathering Company (“RGC”) for a price based upon third-party sales. RGC retains approximately $0.31 per Mcf as
a compression and gathering fee. For further information regarding natural gas sales from the underlying
properties to affiliates of XTO Energy, see “Significant Properties,” under Item 2. Properties.
Total gas sales from the underlying properties to XTO Energy’s wholly owned subsidiaries were $4.1 million
for 2023, or 8 percent of total gas sales, $6.1 million for 2022, or 9 percent of total gas sales.
On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.
Critical Accounting Policies
The financial statements of the Trust are significantly affected by its basis of accounting and estimates
related to its oil and gas properties and proved reserves, as summarized below.
Basis of Accounting
The Trust’s financial statements are prepared on a modified cash basis, which is a comprehensive basis of
accounting other than U.S. GAAP. This method of accounting is consistent with reporting of taxable income to
Trust unitholders. The most significant differences between the Trust’s financial statements and those prepared in
accordance with U.S. GAAP are:
1.
2.
3.
Net profits income is recognized in the month received rather than accrued in the month of production.
Expenses are recognized when paid rather than when incurred.
Cash reserves may be established by the Trustee for certain contingencies that would not be recorded
under U.S. GAAP.
This comprehensive basis of accounting other than U.S. GAAP corresponds to the accounting permitted for
royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin
Topic 12:E, Financial Statements of Royalty Trusts. For further information regarding the Trust’s basis of
accounting, see Note 2 to Financial Statements under Item 8. Financial Statements and Supplementary Data.
All amounts included in the Trust’s financial statements are based on cash amounts received or disbursed, or
on the carrying value of the net profits interests, which was derived from the historical cost of the interests at the
date of their transfer from XTO Energy, less accumulated amortization to date. Accordingly, there are no fair value
estimates included in the financial statements based on either exchange or non-exchange trade values.
Oil and Gas Reserves
The proved oil and gas reserves for the underlying properties are estimated by independent petroleum
engineers. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the
estimated oil and gas reserves attributable to the net profits interests. Reserve engineering is a subjective
process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different
engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing
and production subsequent to the date of an estimate, as well as economic factors such as changes in product
prices, may justify revision of such estimates. Because proved reserves are required to be estimated using
12-month average prices, based on the first-day-of-the-month price for each month in the period, estimated
reserve quantities can be significantly impacted by changes in product prices. Accordingly, oil and gas quantities
ultimately recovered and the timing of production may be substantially different from original estimates.
The standardized measure of discounted future net cash flows and changes in such cash flows, as reported
in Note 9 to Financial Statements under Item 8. Financial Statements and Supplementary Data, is prepared using
30
assumptions required by the Financial Accounting Standards Board and the Securities and Exchange
Commission. Such assumptions include using 12-month average oil and gas prices, based on the
first-day-of-the-month price for each month in the period, and year end costs for estimated future development
and production expenditures, including recovery of cumulative excess costs remaining at year end. Discounted
future net cash flows are calculated using a 10 percent rate. Changes in any of these assumptions, including
consideration of other factors, could have a significant impact on the standardized measure. Accordingly, the
standardized measure does not represent XTO Energy’s or the Trustee’s estimated current market value of proved
reserves.
Forward-Looking Statements
Certain information included in this annual report and other materials filed, or to be filed, by the Trust with the
Securities and Exchange Commission (as well as information included in oral statements or other written
statements made or to be made by XTO Energy or the Trustee) contain forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act
of 1933, as amended, relating to the Trust, operations of the underlying properties and the oil and gas industry.
Such forward-looking statements may concern, among other things, excess costs, reserve-to-production ratios,
future production, development activities and associated operating expenses, future development plans by area,
increased density drilling, maintenance projects, development, production, regulatory and other costs, oil and gas
prices and expectations for future demand, the impact of inflation and economic downturns on economic activity,
government policy and its impact on oil and gas prices and future demand, the development and competitiveness
of alternative energy sources, pricing differentials, proved reserves, future net cash flows, production levels,
expense reserve budgets, availability of
financing, political and
financing, arbitration,
regulatory matters, such as tax and environmental policy, climate policy, trade barriers, sanctions, competition,
war and other political or security disturbances. Such forward-looking statements are based on XTO Energy’s and
the Trustee’s current plans, expectations, assumptions, projections and estimates and are identified by words
such as “may,” “expects,” “intends,” “plans,” “projects,” “anticipates,” “predicts,” “believes,” “goals,”
“estimates,” “should,” “could,” “would,” and similar words that convey the uncertainty of future events. These
statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions
that are difficult to predict. Therefore, actual financial and operational results may differ materially from
expectations, estimates or assumptions expressed in,
implied in, or forecasted in such forward-looking
statements. Some of the risk factors that could cause actual results to differ materially are explained in Item 1A.
Risk Factors.
litigation,
liquidity,
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not required for smaller reporting companies; the Trust has elected to omit this information.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm (PCAOB 238) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statements of Assets, Liabilities and Trust Corpus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statements of Distributable Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statements of Changes in Trust Corpus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
32
33
33
33
34
All financial statement schedules are omitted as they are inapplicable or the required information has been
included in the consolidated financial statements or notes thereto.
31
Report of Independent Registered Public Accounting Firm
To the Unitholders of Hugoton Royalty Trust and Argent Trust Company, as Trustee
Opinion on the Financial Statements
We have audited the accompanying statements of assets, liabilities and trust corpus of Hugoton Royalty Trust (the
“Trust”) as of December 31, 2023 and 2022, and the related statements of distributable income and changes in trust
corpus for the years then ended, including the related notes (collectively referred to as the “financial statements”).
In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities and trust corpus
of the Trust as of December 31, 2023 and 2022, and its distributable income and its changes in trust corpus for the
years then ended in conformity with the modified cash basis of accounting described in Note 2.
Substantial Doubt about the Trust’s Ability to Continue as a Going Concern
The accompanying financial statements have been prepared assuming that the Trust will continue as a going
concern. As discussed in Note 2 to the financial statements, accumulated excess costs have resulted in insufficient
net proceeds available to the Trust and a reduction in the Trust’s expense reserve that raise substantial doubt about
its ability to continue as a going concern. The Trustee’s plans in regard to these matters are also described in Note 2.
The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Basis for Opinion
These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the
Trust’s financial statements based on our audits. We are a public accounting firm registered with the Public
Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to
the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were
we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to
obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on
the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements,
whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also
included evaluating the accounting principles used and significant estimates made by the Trustee, as well as evaluating
the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Basis of Accounting
As described in Note 2, these financial statements were prepared on the modified cash basis of accounting,
which is a comprehensive basis of accounting other than generally accepted accounting principles.
Critical Audit Matters
Critical audit matters are matters arising from the current period audit of the financial statements that were
communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures
that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex
judgments. We determined there are no critical audit matters.
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
April 1, 2024
We have served as the Trust’s auditor since 2011.
32
HUGOTON ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
December 31
2023
2022
Assets
Cash and short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest to be received . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net profits interests in oil and gas properties – net (Notes 1 and 2) . . . . . . . . . . . . . . . . .
$344,048
—
—
$2,829,458
4,902
—
$344,048
$2,834,360
Liabilities and Trust Corpus
Distribution payable to unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expense reserve (a)
. . . . .
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)
$ — $1,834,360
1,000,000
344,048
—
—
$344,048
$2,834,360
(a) The expense reserve allows the Trustee to pay its obligations should it be unable to pay them out of the net profits
income.
STATEMENTS OF DISTRIBUTABLE INCOME
Year Ended December 31
2023
2022
Net profits income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$11,467,914
65,670
$19,544,398
16,810
Total income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Administration expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash reserves withheld (used) for Trust expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in accounts payable to the Trustee (increase)/decrease . . . . . . . . . . . . . . . . . . .
11,533,584
1,093,016
(655,952)
—
19,561,208
758,312
1,000,000
1,217,857
Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$11,096,520
$16,585,039
Distributable income per unit (40,000,000 units) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 0.277413
$ 0.414626
STATEMENTS OF CHANGES IN TRUST CORPUS
Year Ended December 31
2023
2022
Trust corpus, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions declared . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in accounts payable to the Trustee (increase)/decrease . . . . . . . . . . . . . . . . . .
$
11,096,520
(11,096,520)
— $ (1,217,857)
16,585,039
(16,585,039)
1,217,857
—
Trust corpus, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $
—
See accompanying notes to financial statements.
33
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS
1. Trust Organization and Provisions
Hugoton Royalty Trust (the “Trust”) was created on December 1, 1998, by XTO Energy Inc. (formerly known
as “Cross Timbers Oil Company” and, hereafter, “XTO Energy”). Effective on that date, XTO Energy conveyed 80%
net profits interests in certain predominantly gas-producing working interest properties in Kansas, Oklahoma and
Wyoming to the Trust under separate conveyances for each of the three states. In exchange for the conveyances
of the net profits interests to the Trust, XTO Energy received 40 million units of beneficial interest in the Trust. The
Trust’s initial public offering was in April 1999. The majority of the underlying working interest properties are
currently owned and operated by XTO Energy (Note 7).
Effective April 10, 2023, Argent Trust Company (“Argent”) became the Trustee of the Trust. References herein
to the Trustee for periods prior to April 10, 2023, shall refer to Simmons Bank, the former Trustee of the Trust. The
Trust indenture provides, among other provisions, that:
1.
2.
3.
4.
5.
6.
the Trust cannot engage in any business activity or acquire any assets other than the net profits
interests and specific short-term cash investments;
the Trust may dispose of all or part of the net profits interests if approved by a vote of holders of 80% or
more of the outstanding Trust units, or upon Trust termination. Otherwise, the Trust is required to sell up
to one percent of the value of the net profits interests in any calendar year, pursuant to notice from XTO
Energy of its desire to sell the related underlying properties. Any sale must be for cash with 80% of the
proceeds distributed to the unitholders on the next declared distribution;
the Trustee may establish a cash reserve for payment of any liability that is contingent or not currently
payable;
the Trustee may borrow funds to pay Trust liabilities if repaid in full prior to further distributions to
unitholders;
the Trustee will make monthly cash distributions to unitholders (Note 3); and
the Trust will terminate upon the first occurrence of:
a)
b)
c)
disposition of all net profits interests pursuant to terms of the Trust indenture,
gross proceeds from the underlying properties falling below $1 million per year for two successive
years, or
a vote of holders of 80% or more of the outstanding Trust units to terminate the Trust in
accordance with provisions of the Trust indenture.
2. Basis of Accounting
The financial statements of the Trust are prepared on the following basis and are not intended to present
financial position and results of operations in conformity with U.S. GAAP:
1.
2.
3.
4.
Net profits income is recorded in the month received by the Trustee (Note 3);
Interest income, interest to be received and distribution payable to unitholders include interest to be
earned on net profits income from the monthly record date (last business day of the month) through the
date of the next distribution;
Trust expenses are recorded based on liabilities paid and cash reserves established by the Trustee for
liabilities and contingencies; and
Distributions to unitholders are recorded when declared by the Trustee (Note 3).
34
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
The most significant differences between the Trust’s financial statements and those prepared in accordance
with U.S. GAAP are:
1.
2.
3.
Net profits income is recognized in the month received rather than accrued in the month of production.
Expenses are recognized when paid rather than when incurred.
Cash reserves may be established by the Trustee for certain contingencies that would not be recorded
under U.S. GAAP.
This comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the
U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial
Statements of Royalty Trusts.
Most accounting pronouncements apply to entities whose financial statements are prepared in accordance
with U.S. GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when
such revenues were received or expenses were paid. Because the Trust’s financial statements are prepared on
the modified cash basis, as described above, most accounting pronouncements are not applicable to the Trust’s
financial statements.
Net profits interests in oil and gas properties
The initial carrying value of the net profits interests of $247,066,951 represents XTO Energy’s historical net
book value for the interests on December 1, 1998, the date of the transfer to the Trust. During the second quarter
2016, the carrying value of the NPI was written down to its fair value of $28,801,000, resulting in an impairment of
$57,306,527 charged directly to trust corpus. During the third quarter 2019, the carrying value of the NPI was
written down to its fair value of zero, resulting in an impairment of $15,681,533 charged directly to trust corpus.
Amortization of the net profits interests is calculated on a unit-of-production basis and charged directly to trust
corpus. Accumulated amortization was $174,078,891 as of September 30, 2019, when the NPI was written down to
its fair value of zero.
Liquidity and Going Concern
The accompanying financial statements have been prepared assuming that the Trust will continue as a going
concern. Financial statements prepared on a going concern basis assume the realization of assets and the
settlement of liabilities in the normal course of business. Accumulated excess costs for the Kansas, Oklahoma and
Wyoming conveyances have resulted in insufficient net proceeds to the Trust and a reduction in the Trust’s
expense reserve. These conditions raise substantial doubt about the Trust’s ability to continue as a going concern
as the Trust does not have sufficient cash to meet its obligations during the one-year period after the dates that
the financial statements are issued. Factors attributable to the cash shortage are primarily the previously
disclosed development costs to drill three non-operated wells in Major County, Oklahoma, lower oil and natural
gas prices during 2023, and excess cost positions on the Kansas, Oklahoma and Wyoming conveyances including
accumulated interest, which have resulted in no unitholder distributions since July 2023. In addition, on May 18,
2021, the arbitration panel issued its second interim final award over the amount of XTO Energy’s settlement in
the Chieftain class action lawsuit that can be charged to the Trust as a production cost which XTO Energy has
estimated to be approximately $14.6 million net to the Trust. This adjustment would further increase excess costs
on the Oklahoma conveyance. The Trustee has prepared a preliminary budget estimating the administrative
expenses for the year ending December 31, 2024, and the three months ending March 31, 2025, which assumes no
cash inflow from either net profits income or from other sources. The Trustee intends to review options for the
Trust which may include alternatives to continuing as a going concern or may include seeking financing to pay the
35
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
Trust obligations during the one-year period after the date the financial statements are issued; however, there can
be no assurance that financing will be available on acceptable terms or at all. If financing became available to the
Trust, it would have to be repaid, together with interest, and the Trust’s expense reserve would have to be
replenished prior to any distributions to unitholders.
On July 9, 2020, the Trustee notified XTO Energy of the Trustee’s claim to indemnification to the Trust Estate
for all liability, expense, claims, damages or loss incurred by the Trustee in connection with the administration of
the Trust. The Trustee stated it anticipates seeking reimbursement from XTO Energy upon depletion of the Trust’s
cash reserve. XTO Energy responded that any indemnity claim to XTO Energy is premature before the Trust Estate
is exhausted.
The Trust’s financial statements do not include any adjustments that might result from the outcome of these
uncertainties.
3. Distributions to Unitholders
The Trustee determines the amount to be distributed to unitholders each month by totaling net profits
income, interest income and other cash receipts, and subtracting liabilities paid and adjustments in cash reserves
established by the Trustee. The resulting amount is distributed to unitholders of record within ten business days
after the monthly record date, which is the last business day of the month.
Net profits income received by the Trustee consists of net proceeds received in the prior month by XTO
Energy from the underlying properties, multiplied by 80%. Net proceeds are the gross proceeds received from the
sale of production,
legal and marketing
less costs. Costs generally include applicable taxes, transportation,
charges, production expense, development and drilling costs, and overhead.
XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the
three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming). If costs exceed revenues for
any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that
conveyance and cannot reduce net profits income from the other conveyances (Note 4).
36
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
4. Excess Costs
If monthly costs exceed revenues for any of the three conveyances (one for each of the states of Kansas,
Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds
of that conveyance and cannot reduce net proceeds from other conveyances.
The following summarizes excess costs activity, cumulative excess costs balance and accrued interest to be
recovered by conveyance as calculated by XTO Energy:
Underlying
KS
OK
WY
Total
Cumulative excess costs remaining at 12/31/22 . . . . . . . . . . . . . . . . $ — $
Net excess costs (recovery) for the quarter ended 3/31/23 . . . . . . .
Net excess costs (recovery) for the quarter ended 6/30/23 . . . . . . .
Net excess costs (recovery) for the quarter ended 9/30/23 . . . . . . .
Net excess costs (recovery) for the quarter ended 12/31/23 . . . . . .
—
177,356
192,368
127,953
— $
—
1,146,689
5,662,363
(5,414,066)
— $
—
—
803,055
915,736
—
—
1,324,045
6,657,786
(4,370,377)
Cumulative excess costs remaining at 12/31/23 . . . . . . . . . . . . . . . .
Accrued interest at 12/31/23 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
497,677
16,861
1,394,986
224,485
1,718,791
27,374
3,611,454
268,720
Total remaining to be recovered at 12/31/23 . . . . . . . . . . . . . . . . . . . $514,538 $ 1,619,471 $1,746,165 $ 3,880,174
KS
OK
WY
Total
NPI
Cumulative excess costs remaining at 12/31/22 . . . . . . . . . . . . . . . . $ — $
Net excess costs (recovery) for the quarter ended 3/31/23 . . . . . . .
Net excess costs (recovery) for the quarter ended 6/30/23 . . . . . . .
Net excess costs (recovery) for the quarter ended 9/30/23 . . . . . . .
Net excess costs (recovery) for the quarter ended 12/31/23 . . . . . .
—
141,885
153,894
102,362
— $
—
917,351
4,529,891
(4,331,253)
— $
—
—
642,444
732,588
—
—
1,059,236
5,326,229
(3,496,303)
Cumulative excess costs remaining at 12/31/23 . . . . . . . . . . . . . . . .
Accrued interest at 12/31/23 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
398,141
13,489
1,115,989
179,588
1,375,032
21,899
2,889,162
214,976
Total remaining to be recovered at 12/31/23 . . . . . . . . . . . . . . . . . . . $411,630 $ 1,295,577 $1,396,931 $ 3,104,138
For the year ended December 31, 2023, excess costs were $497,677 ($398,141 net to the Trust) and recoveries
of accrued interest were $240 ($192 net to the Trust) on properties underlying the Kansas net profits interests. This
includes excess costs of $127,953 ($102,362 net to the Trust) for the quarter ended December 31, 2023.
For the year ended December 31, 2023, excess costs were $1,394,986 ($1,115,989 net to the Trust) and
recoveries of accrued interest were $943 ($754 net to the Trust) on properties underlying the Oklahoma net profits
interests. This includes recoveries of excess costs of $5,414,066 ($4,331,253 net to the Trust) for the quarter ended
December 31, 2023.
For the year ended December 31, 2023, excess costs on properties underlying the Wyoming net profits
interests increased by $1,718,791 ($1,375,032 net to the Trust). This includes excess costs of $915,736 ($732,588 net
to the Trust) for the quarter ended December 31, 2023.
Underlying cumulative excess costs for the Kansas, Oklahoma and Wyoming conveyances remaining as of
December 31, 2023, totaled $3.9 million ($3.1 million net to the Trust), including accrued interest of $0.3 million
($0.2 million net to the Trust). This balance does not include the portion of the Chieftain settlement the Panel
determined could be charged as a production cost. XTO Energy has estimated the amount to be approximately
$14.6 million (net to the Trust).
37
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
5. Administration Expense
Administrative expenses are incurred so that the Trustee may meet its reporting obligations to the
unitholders and regulatory entities and otherwise manage the administrative functions of the Trust. These
obligations include, but are not limited to, all expenses, taxes, compensation to the Trustee for managing the
Trust, fees to consultants, accountants, attorneys, transfer agents, other professional and expert persons,
expenses for clerical and other administrative assistance, and fees and expenses for all other services. See Item
11. Executive Compensation, for further information on the remuneration received by the Trustee.
6. Income Taxes
For federal income tax purposes, the Trust constitutes a fixed investment trust that is taxed as a grantor trust.
A grantor trust is not subject to tax at the trust level. Accordingly, no provision for income taxes has been made in
the financial statements. The unitholders are considered to own the Trust’s income and principal as though no
trust were in existence. The income of the Trust is deemed to have been received or accrued by each unitholder
at the time such income is received or accrued by the Trust and not when distributed by the Trust. Impairments
recorded for book purposes will not result in a loss for tax purposes for the unitholders until the loss is recognized.
All revenues from the Trust are from sources within Kansas, Oklahoma or Wyoming. Because it distributes all
of its net income to unitholders, the Trust has not been taxed at the trust level in Kansas or Oklahoma. While the
Trust has not owed tax, the Trustee is generally required to file Kansas and Oklahoma income tax returns
reflecting the income and deductions of the Trust attributable to properties located in each state, along with a
schedule that includes information regarding distributions to unitholders. The Trust did not file a Kansas income
tax return for the 2015 through 2021 tax years due to the fact that there were no revenues, income, or deductions
attributable to properties located in Kansas in that time period.
Wyoming does not impose a state income tax.
The Trust may be required to bear a portion of the legal settlement costs arising from the Chieftain royalty
class action settlement. For information on contingencies, including the Chieftain class action, see Note 8 to
Financial Statements. The Panel has determined the Trust is responsible for a portion of the costs. Pending
finalization of all claims included in the arbitration, XTO Energy would have the right to deduct the costs in its
calculation of the net profits income payable to the Trust from the applicable net profits interests. Thus, for
unitholders, the portion of legal settlement costs for which the Trust is determined to be responsible will be
reflected through a reduction in net profits income received from the Trust and thus in a reduction in the gross
royalty income reported by and taxable to the unitholders. In the event that the Trustee objects to such claimed
reductions, the Trustee may also incur legal fees in representing the Trust’s interests. For unitholders, such costs
would be reflected through an increase in the Trust’s administrative expenses, which would be deductible by
unitholders in determining the net royalty income from the Trust.
Unitholders should consult their own tax advisor regarding income tax requirements, if any, applicable to
such person’s ownership of Trust units.
38
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
7. Related Party Transactions
XTO Energy operates approximately 95 percent of the underlying properties. In computing net proceeds, XTO
Energy deducts an overhead charge for reimbursement of administrative expenses on the underlying properties it
operates. As of December 31, 2023, the monthly overhead charge, based on the number of operated wells, was
approximately $1,060,000 ($848,000 net to the Trust) and is subject to annual adjustment based on an oil and gas
industry index as defined in the Trust Indenture.
Certain of XTO Energy’s wholly owned subsidiaries purchase natural gas and provide services for the
properties operated by XTO Energy. In the Hugoton area, Timberland provides gathering from the wellhead to
DCP’s gathering system for approximately $0.75 per Mcf and an ExxonMobil affiliate purchases NGLs for a price
based upon third-party sales. A portion of the gas production in Major County, Oklahoma is sold to Ringwood
Gathering Company (“RGC”) for a price based upon third-party sales. RGC retains approximately $0.31 per Mcf as
a compression and gathering fee.
Total gas sales from the underlying properties to XTO Energy’s wholly owned subsidiaries were $4.1 million
for 2023, or 8 percent of total gas sales, $6.1 million for 2022, or 9 percent of total gas sales.
On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.
8. Contingencies
Litigation
Royalty Class Action and Arbitration
As previously disclosed, XTO Energy advised the Trustee that it reached a settlement with the plaintiffs in the
Chieftain class action royalty case. On July 27, 2018, the final plan of allocation was approved by the court. Based
on the final plan of allocation, XTO Energy advised the Trustee that it believes approximately $24.3 million in
additional production costs should be allocated to the Trust. On May 2, 2018, the Trustee submitted a demand for
arbitration seeking a declaratory judgment that the Chieftain settlement is not a production cost and that XTO
Energy is prohibited from charging the settlement as a production cost under the conveyance or otherwise
reducing the Trust’s payments now or in the future as a result of the Chieftain litigation. The Trust and XTO Energy
conducted the interim hearing on the claims related to the Chieftain settlement on October 12-13, 2020. In the
arbitration, the Trustee contended that the approximately $24.3 million allocation related to the Chieftain
settlement was not a production cost and, therefore, there should not be a related adjustment to the Trust’s share
of net proceeds. However, XTO Energy contended that the approximately $24.3 million was a production cost and
should reduce the Trust’s share of net proceeds.
On January 20, 2021, the arbitration panel issued its Corrected Interim Final Award (i) “reject[ing] the Trust’s
contention that XTO has no right under the Conveyance to charge the Trust with amounts XTO paid under
section 1.18(a)(i) as royalty obligations to settle the Chieftain litigation” and (ii) stating “[t]he next phase will determine
how much of the Chieftain settlement can be so charged, if any of it can be, in the exercise of the right found by the
Panel.” Following briefing by both parties, on May 18, 2021, the Panel issued its second interim final award over the
amount of XTO Energy’s settlement in the Chieftain class action lawsuit that can be charged to the Trust as a production
cost. The Panel in its decision has ruled that out of the $80 million settlement, the “Trust is obligated to pay its share
under the Conveyance of the $48 million that was received by the plaintiffs in the Chieftain lawsuit by virtue of the
settlement of that litigation. The Trust is not obligated by the Conveyance to pay any share of the $32 million received by
the lawyers for the plaintiffs in the Chieftain lawsuit by virtue of the settlement.” XTO Energy and the Trustee are in the
process of determining the portion of the $48 million that is allocable to Trust properties to be charged as an excess cost
to the Trust, but estimate it to be approximately $14.6 million net to the Trust.
39
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
The reduction in the Trust’s share of net proceeds from the portion of the settlement amount the Panel has ruled
may be charged against the Oklahoma conveyance would result in excess costs under the Oklahoma conveyance
that would likely result in no distributions under the Oklahoma conveyance while these excess costs are recovered.
This award completes the portion of the arbitration related to the Chieftain settlement. Excess costs on any individual
conveyance would not affect net proceeds to the Trust on any of the other remaining conveyances.
Other Trustee claims related to disputed amounts on the computation of the Trust’s net proceeds for 2014
through 2019 and 2021 were bifurcated from the initial arbitration. Although the arbitration is not terminated, the
final hearing regarding the remaining dispute over net proceeds, previously scheduled to occur on November 8,
2023, was cancelled. XTO Energy and the Trustee will provide material updates as they become available.
Other Lawsuits and Governmental Proceedings
Certain of the underlying properties are involved in various other lawsuits and governmental proceedings
arising in the ordinary course of business. XTO Energy has advised the Trustee that, based on the information
available at this stage of the various proceedings, it does not believe that the ultimate resolution of these claims
will have a material effect on the financial position or liquidity of the Trust, but may have an effect on annual
distributable income.
Other
Several states have enacted legislation requiring state income tax withholding from payments made to
nonresident recipients of oil and gas proceeds. After consultation with its tax counsel, the Trustee believes that it
is not required to withhold on payments made to the unitholders. However, regulations are subject to change by
the various states, which could change this conclusion. Should amounts be withheld on payments made to the
Trust or the unitholders, distributions to the unitholders would be reduced by the required amount, subject to the
filing of a claim for refund by the Trust or unitholders for such amount.
9. Supplemental Oil and Gas Reserve Information (Unaudited)
Oil and Natural Gas Reserves
Proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are
those quantities of oil and natural 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 regulation before the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed
reserves are the quantities expected to be recovered through existing wells with existing equipment and operating
methods in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to
the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as
additional information becomes available. The reserves actually recovered and the timing of production of these
reserves may be substantially different from the original estimate. Revisions result primarily from new information
obtained from development drilling and production history and from changes in economic factors.
Standardized Measure
The standardized measure of discounted future net cash flows and changes in such cash flows are prepared
using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of
12-month average prices for oil and gas, based on the first-day-of-the-month price for each month in the period,
and year end costs for estimated future development and production expenditures to produce the proved
40
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
reserves,
including recovery of cumulative excess costs remaining at year end. Future net cash flows are
discounted at an annual rate of 10 percent. No provision is included for federal income taxes since future net cash
flows are not subject to taxation at the trust level.
The standardized measure does not represent XTO Energy’s or the Trustee’s estimate of future cash flows or
the value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future,
are excluded from the calculations. Furthermore, prices used to determine the standardized measure are
influenced by supply and demand as affected by recent economic conditions as well as other factors and may not
be the most representative in estimating future revenues or reserve data.
Estimated costs to plug and abandon wells on the underlying working interest properties at the end of their
productive lives have not been deducted from cash flows since this is not a legal obligation of the Trust. These
costs are the legal obligation of XTO Energy as the owner of the underlying working interests and will only be
deducted from net proceeds payable to the Trust if net proceeds from the related conveyance exceed such costs
when paid, subject to excess cost carryforward provisions (Notes 3 and 4).
The average realized gas prices used to determine the standardized measure were $2.59 per Mcf in 2023, and
$5.75 per Mcf in 2022. Oil prices used to determine the standardized measure were based on average realized oil
prices of $75.88 per Bbl in 2023, and $93.46 per Bbl in 2022.
Reserve quantities and revenues for the net profits interests were estimated from projections of reserves
and revenues attributable to the underlying properties. Since the Trust has defined net profits interests, the Trust
does not own a specific percentage of the oil and gas reserves. Oil and gas reserves are allocated to the net
profits interests by dividing Trust net cash inflows by 12-month average oil and gas prices. Any fluctuations in
12-month average prices or estimated costs will result in revisions to the estimated reserve quantities allocated to
the net profits interests, which may not correlate with revisions of underlying proved reserves.
Proved Reserves
(in thousands)
Underlying Properties
Oil (Bbls)
Gas (Mcf)
Net Profits Interests
Oil (Bbls)
Gas (Mcf)
Balance, December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance, December 31, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
120,475
186
18,958
(9,772)
—
129,847
471
(41,898)
(9,398)
—
Balance, December 31, 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
79,022
1,461
83
378
(246)
—
1,676
130
(155)
(217)
—
1,434
23,561
90
23,536
(2,441)
—
44,746
202
(36,629)
(990)
—
7,329
334
40
307
(49)
—
632
56
(506)
(11)
—
171
Revisions of prior estimates of the proved gas reserves for the underlying properties in each year are
primarily because of changes in the gas and oil prices. Revisions for the net profits interests may not correlate
with underlying properties in any given year since the Trust’s allocated reserves reflect recovery of the Trust’s
portion of production and development costs at 12-month average prices. Any conveyance where costs exceed
revenues will result in zero allocated net profits interests reserves for that conveyance.
41
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
Proved Developed Reserves
(in thousands)
Underlying Properties
Oil (Bbls)
Gas (Mcf)
Net Profits Interests
Oil (Bbls)
Gas (Mcf)
December 31, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129,847
December 31, 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79,022
1,676
1,434
44,746
7,329
632
171
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
Underlying Properties
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future costs:
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31
2023
2022
$313,585
$903,302
279,766
—
33,819
10,055
545,894
—
357,408
162,851
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 23,764
$194,557
Net Profits Interests
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future production taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 29,140
2,084
$313,533
27,606
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
27,056
8,044
285,927
130,281
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 19,012
$155,646
42
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
2023
2022
Underlying Properties
Standardized measure, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 194,557
$ 69,604
Revisions:
Prices and costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Quantity estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production rates and other
Net revisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(174,761)
5,954
17,501
(9,460)
18
(160,748)
4,290
(23,795)
9,460
—
126,066
16,068
6,758
(2,390)
(80)
146,422
2,962
(26,821)
2,390
—
Net change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(170,793)
124,953
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 23,764
$194,557
Net Profits Interests
Standardized measure, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of discount
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of prior estimates, changes in price and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net profits income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 155,646
3,432
14,001
(142,599)
—
(11,468)
$ 55,683
2,369
5,406
111,732
—
(19,544)
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 19,012
$155,646
10. Quarterly Financial Data (Unaudited)
The following is a summary of net profits income, distributable income and distributable income per unit by
quarter for 2023 and 2022:
2023
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022
First Quarter
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
43
Net Profits
Income
Distributable
Income
Distributable
Income per
Unit
$10,459,753
1,008,161
—
—
$10,175,760
920,760
—
—
$0.254394
0.023019
0.000000
0.000000
$11,467,914
$11,096,520
$0.277413
$
347,410
1,856,317
9,440,853
7,899,818
$
—
—
8,964,359
7,620,680
$0.000000
0.000000
0.224109
0.190517
$19,544,398
$16,585,039
$0.414626
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Trustee conducted an evaluation of the Trust’s disclosure controls and procedures, as such term is
defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this
evaluation, the Trustee has concluded that the Trust’s disclosure controls and procedures were effective as of the
end of the period covered by this annual report. In its evaluation of disclosure controls and procedures, the
Trustee has relied, to the extent considered reasonable, on information provided by XTO Energy.
Trustee’s Report on Internal Control Over Financial Reporting
The Trustee is responsible for establishing and maintaining adequate internal control over financial
reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as
amended. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial
reporting based on the criteria established in Internal Control–Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under
the framework in Internal Control–Integrated Framework (2013), the Trustee concluded that the Trust’s internal
control over financial reporting was effective as of December 31, 2023.
Changes in Internal Control Over Financial Reporting
There were no changes in the Trust’s internal control over financial reporting during the quarter ended
December 31, 2023, that have materially affected, or are reasonably likely to materially affect, the Trust’s internal
control over financial reporting.
ITEM 9B. OTHER INFORMATION
The Trust has no directors or officers, and as a result, no such persons adopted or terminated a “Rule 10b5-1
trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of
Regulation S-K.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
44
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
PART III
(a) Directors, Officers and Committees. The Trust has no directors, executive officers, audit committee, audit
committee financial expert, compensation committee or nominating committee. The Trustee is a corporate
Trustee which may be removed, with or without cause, by the affirmative vote of the holders of a majority of
all the units then outstanding.
(b) Section 16(a) Beneficial Ownership Reporting Compliance. Section 16(a) of the Securities Exchange Act of
1934 requires that directors, officers, and beneficial owners of more than 10 percent of the registrant’s equity
securities file initial reports of beneficial ownership and reports of changes in beneficial ownership with the
Securities and Exchange Commission and the New York Stock Exchange. To the Trustee’s knowledge, based
solely on the information furnished to the Trustee, the Trustee is unaware of any person that failed to file on a
timely basis reports required by Section 16(a) filing requirements with respect to the Trust units of beneficial
interest during and for the year ended December 31, 2023.
(c) Code of Ethics. Because the Trust has no employees, it does not have a code of ethics. Employees of the
Trustee, Argent Trust Company, must comply with the company’s code of ethics which may be found at
www.argentfinancial.com.
ITEM 11. EXECUTIVE COMPENSATION
(a) Compensation Committee Interlocks and Insider Participation/Compensation Committee Report. The Trust
has no officers or directors and is administered by a trustee. The Trust does not have a compensation
committee or maintain any equity compensation plans and there are no units reserved for issuance under
any such plans.
(b) Compensation of the Trustee. The Trustee calculated the following annual compensation for the fiscal
years ended December 31, 2023 and 2022, as specified in the Trust indenture:
Argent Trust Company, Trustee (1)
. . . . . . . . . . . . . . . . . . . . . . .
Simmons Bank, Trustee (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$82,265
—
—
$76,909
2023
2022
(1) Under the Trust indenture, the trustee is entitled to an annual administrative fee, paid in equal monthly installments. Such fee
can be adjusted annually based on an oil and gas industry index. Upon termination of the Trust, the trustee is entitled to a
termination fee of $15,000.
45
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
UNITHOLDER MATTERS
(a) Equity Compensation Plans and Trust Repurchases. The Trust has no equity compensation plans. The
Trust has not repurchased any units during the fourth quarter of fiscal 2023.
(b) Security Ownership of Certain Beneficial Owners. Based on the Trustee’s review of information filed with
the SEC as of March 19, 2024, the following table sets forth information with respect to each person known to
the Trustee to beneficially own more than 5 percent of the outstanding units.
Name and Address
Amount and Nature
of Beneficial Ownership
Percent
of Class
Christopher John Heck
2100 E. 377
Granbury, TX 76049 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,220,500 (1)
15.56%
(1) Pursuant to a Schedule 13G/A filed January 19, 2024, Christopher John Heck reported as of December 31, 2023, he
beneficially owned 6,220,500 units, of which he had sole voting and dispositive power with respect to 6,215,500 units and
shared voting and dispositive power with respect to 5,000 units.
(c) Security Ownership of Management. The Trust has no directors or executive officers. Argent Trust
Company, the Trustee, held as of February 26, 2024, an aggregate of 203 units in various fiduciary capacities,
and it had sole voting and investment power with respect to all such units.
(d) Changes in Control. The Trustee knows of no arrangements which may subsequently result in a change in
control of the Trust.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
XTO Energy sells a portion of natural gas production from the underlying properties to certain of its wholly
owned subsidiaries under contracts in existence when the Trust was created, generally at amounts
approximating monthly published prices. For further information, see Item 2. Properties.
In computing net profits income paid to the Trust for the net profits interests, XTO Energy deducts an
overhead charge for reimbursement of administrative expenses of operating the underlying properties. For further
information, see Note 7 to Financial Statements under Item 8. Financial Statements and Supplementary Data.
As of March 11, 2024, XTO Energy did not own any units.
See Item 11. Executive Compensation, for the remuneration received by the Trustee for the fiscal years
ended December 31, 2022, through December 31, 2023.
As noted in Item 10. Directors, Executive Officers and Corporate Governance, the Trust has no directors,
executive officers, audit committee, audit committee financial expert, compensation committee or nominating
committee. The Trustee is a corporate trustee which may be removed, with or without cause, by the affirmative
vote of the holders of a majority of all the units then outstanding.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Fees for services performed by PricewaterhouseCoopers LLP for the years ended December 31, 2023 and 2022 are:
Audit fees-PwC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Audit-related fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All other fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2023
$220,000
—
—
—
$220,000
2022
$209,000
—
—
—
$209,000
As referenced in Item 10. Directors, Executive Officers and Corporate Governance, above, the Trust has no
audit committee, and as a result, has no audit committee pre-approval policy with respect to fees paid to
PricewaterhouseCoopers LLP.
46
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as a part of this report:
1. Financial Statements (included in Item 8 of this report)
Report of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus at December 31, 2023 and 2022
Statements of Distributable Income for the years ended December 31, 2023 and 2022
Statements of Changes in Trust Corpus for the years ended December 31, 2023 and 2022
Notes to Financial Statements
2.
Financial Statement Schedules
Financial statement schedules are omitted because of the absence of conditions under which they are
required or because the required information is given in the financial statements or notes thereto.
3.
Exhibits
(4) (a)
(b)
(c)
(d)
(e)
(23)
(31)
(32)
(97)
Hugoton Royalty Trust Indenture by and between NationsBank, N.A., as Trustee, and Cross
Timbers Oil Company (predecessor of XTO Energy) heretofore filed as Exhibit 4.1 to the Trust’s
Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange
Commission on December 4, 1998, is incorporated herein by reference.
Amendment No. 1 to Amended and Restated Royalty Trust Indenture, dated March 24, 1999, of
Hugoton Royalty Trust heretofore filed as Exhibit 4.1 to the Trust’s Current Report on Form 8-K filed
with the Securities and Exchange Commission on April 5, 2023, is incorporated herein by reference.
Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80% – Kansas) as amended and
restated from Cross Timbers Oil Company (predecessor of XTO Energy) to NationsBank, N.A.,
as Trustee, dated December 1, 1998, heretofore filed as Exhibit 10.1.1 to the Trust’s
Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange
Commission on March 16, 1999, is incorporated herein by reference.
Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80% – Oklahoma) as amended and
restated from Cross Timbers Oil Company (predecessor of XTO Energy) to NationsBank, N.A.,
as Trustee, dated December 1, 1998, heretofore filed as Exhibit 10.2.1 to the Trust’s
Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange
Commission on March 16, 1999, is incorporated herein by reference.
Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80% – Wyoming) as amended and
restated from Cross Timbers Oil Company (predecessor of XTO Energy) to NationsBank, N.A.,
as Trustee, dated December 1, 1998, heretofore filed as Exhibit 10.3.1 to the Trust’s
Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange
Commission on March 16, 1999, is incorporated herein by reference.
Consent of Miller and Lents, Ltd.
Rule 13a-14(a)/15d-14(a) Certification
Section 1350 Certification
Hugoton Royalty Trust Executive Officer Compensation Recovery Policy
(99.1)
Miller and Lents, Ltd. Report
Copies of the above Exhibits are available to any unitholder, at the actual cost of reproduction, upon written
request to the Argent Trust Company, 3838 Oak Lawn Ave, Suite 1720, Dallas, Texas 75219-4518.
47
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has
duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
SIGNATURES
HUGOTON ROYALTY TRUST
By ARGENT TRUST COMPANY, TRUSTEE
By
/s/ NANCY WILLIS
Nancy Willis
Director of Royalty Trust Services
EXXON MOBIL CORPORATION
Date: April 1, 2024
By
/s/ WENDI POWELL
Wendi Powell
Upstream Controller
(The Trust has no directors or executive officers.)
48
March 28, 2024
EXHIBIT 99.1
Ms. Kameron Fivecoat
Reserves Manager
XTO Energy Inc.
22777 Springwoods Village Parkway
Spring, TX 77389
Re: Underlying Properties (100%)
Relating to the Hugoton Royalty Trust
Reserves and Future Net Revenues
As of December 31, 2023
SEC Price Case
Dear Ms. Fivecoat:
At your request, Miller and Lents, Ltd. (M&L) estimated the proved reserves and future net revenues as of
December 31, 2023, attributable to the XTO Energy Inc. (XTO) interest in certain oil and gas properties prior to
i.e., Underlying Properties (100%). The Underlying Properties (100%)
inclusion in the Hugoton Royalty Trust,
include working interest properties from which net profits interests were conveyed to the Hugoton Royalty Trust.
The properties consist of approximately 1,340 leases and 1,461 wells located primarily in Kansas, Oklahoma, and
Wyoming. The aggregate results of M&L’s evaluations are as follows:
Reserves Category
Kansas
Net Reserves
Future Net Revenues
Oil and
Condensate
MBBL
Gas
MMCF
Undiscounted
M$
Discounted at
10% Per Year
M$
Proved Developed Producing . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma
Proved Developed Producing . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming
Proved Developed Producing . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Underlying Properties (100%)
Proved Developed Producing . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
96
96
1,318
1,318
21
21
1,434
1,434
4,925
4,925
56,325
56,325
17,772
17,772
79,022
79,022
6,750
6,750
105,652
105,652
18,374
18,374
130,776
130,776
3,849
3,849
62,428
62,428
12,385
12,385
78,662
78,662
Oil and condensate volumes are expressed in thousand barrels (MBBL). Gas volumes are expressed in million
cubic feet (MMCF). Future net revenues are expressed in thousand dollars (M$).
The report was prepared for the use of XTO in its financial and reserves reporting and was completed on
March 28, 2024. M&L performed evaluations, which are designated as the SEC Price Case, using price and
expense premises specified by XTO and described in detail on Appendix 1.
Proved reserves and future net revenues were estimated in accordance with the provisions contained in
Securities and Exchange Commission Regulation S-X, Rule 4-10(a). The Securities and Exchange Commission
definition of proved reserves is shown on Appendix 2 (not included). Gas volumes for each property are stated at
Underlying Properties (100%)
Relating to the Hugoton Royalty Trust
March 28, 2024
the pressure and temperature bases appropriate for the sales contract or state regulatory authority; therefore,
some of the aggregated totals may be stated at a mixed pressure base. No provisions for the possible
consequences, if any, of product sales imbalances were included in M&L’s projections since M&L received no
relevant data. Estimates of future net revenues and discounted future net revenues are not intended and should
not be interpreted to represent fair market values for the estimated reserves. In M&L’s projections, future costs of
abandoning facilities and wells were assumed to be offset by salvage values. Estimated costs,
if any, for
restoration of producing properties to satisfy environmental standards are beyond the scope of this assignment.
Following Appendix 2 (not included) is a list of exhibits that include annual projections of future production and net
revenues for each state and reserves category. Also included in the exhibits are one-line summaries for the total
royalty trust and for each state showing the proved reserves and future net revenues for the individual properties.
These exhibits should not be relied upon independently of this narrative.
The proved developed producing reserves and production forecasts were estimated by production decline
extrapolations, water-oil ratio trends, P/Z declines, or in a few cases, by volumetric calculations. For some
properties with insufficient performance history to establish trends, M&L estimated future production by analogy
with other properties with similar characteristics. The past performance trends of many properties were
influenced by production curtailments, workovers, waterfloods, and/or infill drilling. Actual future production may
require that M&L’s estimated trends be significantly altered. Reserves estimates from volumetric calculations and
from analogies are often less certain than reserves estimates based on well performance obtained over a period
during which a substantial portion of the reserves was produced.
The estimated proved developed nonproducing reserves can be produced from existing well bores but require
capital costs for recompletions or for pipeline connections. These proved developed nonproducing reserves
estimates were based on analogies with other wells that commercially produce from the same formation in the
same field. The timing of initial production was provided to M&L by XTO. When actual production history is
available for these nonproducing reserves, M&L’s reserves estimates may be significantly revised.
The estimated proved undeveloped reserves require significant capital expenditures, such as for planned drilling
and completion costs. The proved undeveloped reserves estimates for infill wells are based on analogies to
similar infill wells in the same field and/or the production histories of offset wells in the same field. As actual
results of the planned drilling become available, M&L’s reserves estimates may be significantly revised.
The data employed in M&L’s estimations of proved reserves and future net revenues were provided by XTO. The
current expenses for each lease were obtained from operating statements provided by XTO except for certain
leases where XTO deducted items considered by XTO to be nonrecurring expenditures. No overhead was
included for those properties operated by XTO. For some properties, such as large waterfloods, XTO assumed a
decline in operating costs due to depleting production that was derived by forecasting a decrease in the property
well count. For some gas properties, XTO assumed operating costs would be split between a variable component
and a fixed component. The variable component was a constant cost per thousand cubic feet of gas production
and the fixed component was a constant cost per well completion. The data provided to M&L by XTO, including,
but not limited to, graphical representations and tabulations of past production performance, well tests and
pressures, ownership interests, prices, capital expenditures, and operating costs were accepted as represented
and were considered appropriate for the purpose of this report. M&L employed all methods, data, procedures, and
assumptions considered necessary and appropriate in utilizing the data provided to prepare this report.
The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect
M&L’s informed judgments and are subject to the inherent uncertainties associated with interpretation of
geological, geophysical, and engineering information. These uncertainties include, but are not limited to, (1) the
Underlying Properties (100%)
Relating to the Hugoton Royalty Trust
March 28, 2024
utilization of analogous or indirect data and (2) the application of professional judgments. Government policies and
market conditions different from those employed in this study may cause (1) the total quantity of oil, natural gas
liquids, or gas to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to
vary from those presented in this report. At this time, M&L is not aware of any regulations that would affect XTO’s
ability to recover the estimated reserves.
Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller
and Lents, Ltd. has any financial ownership in XTO Energy Inc. or any related company. M&L’s compensation for
the required investigations and preparation of this report is not contingent on the results obtained and reported,
and it has not performed other work that would affect M&L’s objectivity. Production of this report was supervised
by Jennifer A. Godbold, P.E., an officer of the firm who is a licensed Professional Engineer in the State of Texas
and is professionally qualified, with more than 12 years of relevant experience, in the estimation, assessment, and
evaluation of oil and gas reserves.
M&L’s work papers and data are in its files and available for review upon request. If you have any questions
regarding the above, or if M&L can be of further assistance, please call.
Very truly yours,
MILLER AND LENTS, LTD.
Texas Registered Engineering Firm No. F-1442
By /S/ JENNIFER A. GODBOLD
Jennifer A. Godbold, P. E.
Senior Vice President
Hugoton Royalty Trust (100%)
SEC PRICE CASE
Appendix 1
A. Oil Price
B. Gas Price
Average price during the 12-month period prior to 12/31/23 determined as the
arithmetic average of the first-day-of-the-month price for each month during the year
2023. The average price was based on the West Texas Intermediate benchmark price.
The arithmetic average of the first-day-of-the-month benchmark prices is $78.22 per
barrel and is held constant through the life of the property. The average realized price,
after appropriate adjustments, is $75.88 per barrel.
Average price during the 12-month period prior to 12/31/23 determined as the
arithmetic average of the first-day-of-the-month price for each month during the year
2023. The average price was based on the Henry Hub benchmark price. The arithmetic
average of the first-day-of-the-month benchmark price is $2.637 per MMBTU and is
held constant through the life of the property. The average realized price, after
appropriate adjustments is $2.59 per MCF.
C.
Operating Costs
Current expenses held constant through the life of the property. For some properties,
expenses included a variable component that was a constant cost per unit of gas
production and a fixed component that was a constant cost per well completion.
D. Discount Rate
10% per year.
Form 10-K
A copy of the Hugoton Royalty Trust Form 10-K has been provided with this Annual Report.
Additional copies of this Annual Report and Form 10-K will be provided to unitholders
without charge upon request. Copies of exhibits to the Form 10-K may be obtained upon
request or from the Trust’s website at www.hgt-hugoton.com.
Hugoton Royalty Trust
Argent Trust Company, Trustee
3838 Oak Lawn Avenue, Suite 1720
Dallas, Texas 75219
Attention: Annual Reports
1-855-588-7839
Website
www.hgt-hugoton.com
Auditors
PricewaterhouseCoopers LLP
Dallas, Texas
Legal and Tax Counsel
Holland & Knight LLP
Dallas, Texas
Transfer Agent and Registrar
Equiniti Trust Company, LLC
www.equiniti.com
Certification
The Trustee’s certification, required by Section 302 of the Sarbanes-Oxley Act of 2002, has been
filed as Exhibit 31 of the Trust’s Form 10-K, for the fiscal year ended December 31, 2023.
Hugoton Royalty Trust
Argent Trust Company
3838 Oak Lawn Avenue, Suite 1720
Dallas, Texas 75219
1-855-588-7839
www.hgt-hugoton.com