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 tax reporting 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
2021
Years Ended December 31,
0
Net Profits Income ...................... $
0
Distributable Income ...................
Distributable Income per Unit ...... 0.000000
Distributions per Unit .................. 0.000000
Total Assets at Year End ............... 660,000
2020
$
0
0
0.000000
0.000000
0
2019
$ 369,458
0
0.000000
0.000000
605,646
2018
$ 1,590,949
370,040
0.009251
0.009251
16,945,147
2017
$ 5,317,931
4,520,240
0.113006
0.113006
17,813,389
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 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, 2021 totaled
$19.3 million ($15.5 million net to the Trust),
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.
including accrued interest of $3.1 million
($2.5 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 has 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
2021 tax booklet for specific instructions.
Unitholders should consult their tax advisors
for further information.
To Unitholders:
We are pleased to present the 2021
Annual Report on Form 10-K of
the Hugoton Royalty Trust as filed with the
that the Trust will continue as a going
concern. Financial statements prepared on a
going concern basis assume the realization
Securities and Exchange Commission. This
of assets and the settlement of liabilities in
report contains important information about
the normal course of business. Accumulated
the Trust’s net profits interests, including
excess costs for the Kansas, Oklahoma
information provided to the Trustee by
and Wyoming conveyances have resulted in
XTO Energy.
insufficient net proceeds to the Trust and a
Net profits income for 2021 was $0.
reduction in the Trust’s expense reserve to
This was primarily the result of higher oil and
zero. These conditions raise substantial doubt
gas prices ($21.9 million) and decreased
about the Trust’s ability to continue as a going
production expenses ($2.2 million), offset
concern as the Trust does not have sufficient
by net excess costs activity ($13.8 million),
cash to meet its obligations during the
decreased oil and gas production ($7.8
one year period after the date the financial
million), increased development costs ($1.5
statements are issued.
million), and increased taxes, transportation
The Trustee is reviewing the Trust’s
and other costs ($1.0 million).
alternatives to continuing as a going
Trust administration expense was
concern, which may include a sale of the
$935,488 in 2021. Simmons Bank funded
Trust’s assets and/or termination of the
$935,488 for the payment of Trust expenses
Trust. The Trustee engaged a third party to
in 2021. Interest income was $0 in 2021.
market the Trust’s assets, and following an
Changes in interest income are attributable
extensive marketing period for the assets,
to fluctuations in net profits income, cash
on July 2, 2021, the Trustee entered into a
reserve and interest rates. For further
purchase and sale agreement for the Trust’s
information, see “Trustee’s Discussion
assets with the highest bidder, XTO Energy,
and Analysis of Financial Condition and
for a cash purchase price of $6,600,000
Results of Operations” under Item 7 of the
(subject to adjustment as set forth in the
accompanying Form 10-K.
purchase and sale agreement). Although the
The accompanying financial
Trustee and XTO Energy have entered into
statements have been prepared assuming
the purchase and sale agreement, there is
To Unitholders: Continued
no assurance that a sale can be completed
from the outcome of these uncertainties.
under the terms of the indenture, or if a sale
For further information, see “Liquidity and
is completed under the indenture, that there
Going Concern” under Item 8, “Financial
will be any funds available for distribution to
Statements and Supplementary Data” of the
unitholders. Any material sale of assets and/
accompanying Form 10-K.
or termination of the Trust requires unitholder
XTO Energy is a party to legal
approval by at least 80% of all outstanding
proceedings that may affect future Trust
units. The Trustee held a Special Meeting
distributions. For further information, see
of unitholders on December 10, 2021 for
Note 8 to Financial Statements under Item 8,
the purpose of approving the sale of assets.
“Financial Statements and Supplementary
The sale was not approved by unitholders.
Data” of the accompanying Form 10-K.
Simmons Bank, as Trustee, is currently paying
The 2021 average gas price was $4.05
the expenses for the Trust, subject to its rights
per Mcf, up 88% from the 2020 average gas
to be indemnified and reimbursed pursuant
price of $2.15 per Mcf.
to the terms of the Trust indenture. However,
The average oil price for 2021 was
there is nothing in the Trust indenture that
$59.25 per Bbl, up 44% from the average oil
requires Simmons Bank to pay the expenses
price for 2020 of $41.12 per Bbl.
for the Trust. Any funds that Simmons Bank,
Gas sales volumes from the underlying
as Trustee, utilizes to pay expenses of the
properties for 2021 were 10,193,158 Mcf,
Trust must be repaid in full (including
or 27,926 Mcf per day, a decrease of 10%
from proceeds received from a sale of the
from 31,073 Mcf per day in 2020. Oil sales
Trust’s assets, if any) before distributions to
volumes from the underlying properties were
unitholders could be made. There can be no
232,576 Bbls, or 637 Bbls per day in 2021,
assurances that a sale of the Trust’s assets,
a decrease of 26% from 866 Bbls per day
if any, will produce net proceeds sufficient
in 2020. For further information on sales
to allow distributions to the unitholders
volumes and product prices, see “Trustee’s
and if such proceeds are available, there is
Discussion and Analysis of Financial
no assurance when any distribution will be
Condition and Results of Operations” under
made. The Trust’s financial statements do not
Item 7 of the accompanying Form 10-K.
include any adjustments that might result
As of December 31, 2021, proved
To Unitholders: Continued
reserves for the underlying properties were
$3.61 per Mcf and a 12-month average oil
estimated by independent engineers to be
price of $64.60 per Bbl, based on the first-
120.5 Bcf of natural gas and 1.5 million
day-of-the-month price for each month in the
Bbls of oil. From year-end 2020 to 2021, gas
period, and year end costs, including recovery
and oil reserves for the underlying properties
of cumulative excess costs remaining at year
increased 133% and 34%, respectively,
end. Other guidelines used in estimating
primarily due to higher oil and gas prices
proved reserves, as prescribed by the
used to estimate reserves. Based on an
Financial Accounting Standards Board, are
allocation of these reserves, proved reserves
described in Note 9 to Financial Statements
attributable to the net profits interests were
under Item 8, “Financial Statements and
estimated to be 23.6 Bcf of natural gas
Supplementary Data” of the accompanying
and 334,000 Bbls of oil. Because Trust
Form 10-K. The present value of estimated
reserve quantities are determined using an
future net cash flows is computed based
allocation formula, any fluctuations in actual
on SEC guidelines and is not necessarily
or assumed prices or costs will result in
representative of the market value of
revisions to the estimated reserve quantities
Trust units.
allocated to the net profits interests. All
As disclosed in the tax instructions
reserve information prepared by independent
provided to unitholders in February 2022,
engineers has been provided to the Trustee by
Trust distributions are considered portfolio
XTO Energy.
income, rather than passive income.
Estimated future net cash flows from
Unitholders should consult their tax advisors
proved reserves of the net profits interests
for further information.
at December 31, 2021 was $97.6 million.
Using an annual discount factor of 10%, the
present value of estimated future net cash
flows at December 31, 2021 was $55.7
Hugoton Royalty Trust
By: Simmons Bank, Trustee
million. Proved reserve estimates and related
future net cash flows have been determined
By: Nancy Willis
Vice President
based on a 12-month average gas price of
April 11, 2022
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, 2021
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:
Simmons Bank
2911 Turtle Creek Blvd, Suite 850
Dallas, Texas
(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
Units of Beneficial Interest
Trading symbol
HGTXU
Name of each exchange on which registered
OTCQB
YES ‘ NO È
YES ‘ NO È
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
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.
YES È NO ‘
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. ‘
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
YES ‘ NO È
The aggregate market value of units of beneficial interest held by non-affiliates of the registrant at June 30, 2021 (the last business day of the registrant’s
most recently completed second fiscal quarter) was approximately $5.6 million.
The number of units of beneficial interest outstanding as of March 15, 2022 was 40,000,000.
HUGOTON ROYALTY TRUST
2021 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
Page
Glossary of Terms
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
Part I
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1.
Item 1A.
Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 3.
Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4.
Part II
Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units . . . . . . . . . . . . . . .
Item 5.
[Reserved] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 6.
Item 7.
Trustee’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . .
Item 7A. Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 8.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . .
Item 9.
Item 9A.
Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part III
Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 11.
Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters . . . . . .
Item 13. Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . . . . . . . .
Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 14.
2
3
11
11
21
22
23
23
24
30
30
45
45
45
45
46
46
47
47
48
Item 15.
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
49
Part IV
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
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 tax reporting
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.
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. Simmons Bank (the “Trustee”) is now the
Trustee of the Trust.
The principal office of the Trust is 2911 Turtle Creek Blvd, Suite 850, 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 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 under
existing sales contracts, or new arrangements on the best terms reasonably obtainable in the circumstances. See “Pricing
and Sales Information” under Item 2. Properties.
2
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.
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.
Although the Trustee engaged a third party to market the sale of the Trust’s assets, to date unitholders have not
approved a sale of the Trust’s assets, and there is no assurance that the Trustee and any prospective buyer will agree
to terms of sale, or that a sale can be completed under the indenture, or if a sale is completed under the indenture,
that there will be any funds available for distribution to unitholders.
In 2020, the Trustee engaged a third party to market the sale of the Trust’s assets. In July 2021, the Trustee entered
into a purchase and sale agreement with XTO Energy with respect to a sale of the Trust’s assets; however, at a special
3
meeting of the Trust’s unitholders held in December 2021, the proposed sale failed to receive the approval of holders of
80% of the Trust’s units. As a result, the conditions to closing under the purchase and sale agreement have not been
satisfied, although the agreement remains in effect. The Trustee is unable to predict whether any future prospective buyer
will agree to terms of a sale. Any material sale of assets and/or termination of the Trust requires unitholder approval by at
least 80% of all outstanding units. Failure to reach the 80% threshold would delay or possibly terminate any sale process or
buyer interest. Even if any sale of assets and/or termination of the Trust is approved, the expense reserve used to pay
liabilities of the Trust in the absence of current distributions was depleted in October 2020. Simmons Bank, the Trustee, is
currently paying the liabilities of the Trust, which include the ongoing costs and expenses of the Trust as well as the costs
and expenses incurred to sell the Trust’s assets and terminate the Trust. However, there is nothing in the Trust indenture that
requires Simmons Bank to pay the expenses for the Trust. These costs and expenses will reduce the proceeds that are
available from any sale of the Trust’s assets. There can be no assurances that a sale of the Trust’s assets, if any, will
produce net proceeds sufficient to allow distributions to the unitholders and if such proceeds are available, there is no
assurance when any distribution will be made. Accordingly, there can be no assurances as to the amount, if any, of the
proceeds that will be available for distribution to unitholders.
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 have been in excess costs for all of 2020 and 2021 resulting in no net proceeds to
the Trust and depletion of 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 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. If the Trust is unable to obtain additional financing and is unable to
meet its obligations, the Trust could be forced to consider alternatives such as seeking approval from the unitholders to
amend the Trust indenture either to permit the sale of some or all of the net profits interests or approve termination of the
Trust. Unitholders could incur significant losses on their investment in the Trust or lose their entire investment in the Trust
altogether if the funds obtained from any such sale or liquidation of the net profits interests are such that there are no funds
to distribute to unitholders after all financial obligations are met. See Item 7. Trustee’s Discussion and Analysis of Financial
Condition and Results of Operations – Liquidity and Capital Resources for further information.
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 48 months as of the date of this report,
March 30, 2022. 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 2022 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
the Trust and XTO Energy. Factors that contribute to price fluctuations include instability in
beyond the control of
4
oil-producing regions, worldwide economic conditions, weather conditions, trade barriers, political instability, public health
concerns, such as COVID-19, 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
regulations, such as regulation of natural gas
worldwide energy conservation measures. Moreover, government
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. For
example, sharp decline in demand as a result of the COVID-19 pandemic and the ensuing government responses resulted in
negative oil prices briefly in 2020. 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.
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 was the case with respect to the properties
underlying all three of the Trust’s conveyances for all of 2020 and 2021), 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 between $1 million
and $2 million for 2022 which could continue to exceed revenues for the underlying conveyances. See Item 2. Properties.
As described in Note 8 – Contingencies to the Notes to Financial Statements, XTO Energy has 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
the approximately
to the Trust’s share of net proceeds. However, XTO Energy contended that
related adjustment
$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.
5
The Oklahoma conveyance is already currently subject to excess costs that will need to be recovered prior to any
distribution to unitholders. Therefore, 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 additional excess costs
under the Oklahoma conveyance that would likely result in no distributions under the Oklahoma conveyance for several
additional years while these additional excess costs are recovered. This award completes the portion of the arbitration
related to the Chieftain settlement.
Other Trustee claims related to disputed amounts on the computation of the Trust’s net proceeds for 2014 through
2016 were bifurcated from the initial arbitration and will be heard at a later date, which is still to be determined should the
arbitration proceed. Pursuant to the purchase and sale agreement entered into between the Trustee and XTO Energy, the
parties have agreed to stay the arbitration from the date of execution of the purchase and sale agreement to the earlier of
the termination of the purchase and sale agreement or closing date of the sale of assets. The Panel has stayed proceedings.
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 include the adoption of
cap and trade regimes, carbon taxes, trade tariffs, minimum renewable usage 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 decreased 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,
6
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.
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.
XTO Energy and the Trustee may be subject to attempted cybersecurity disruptions from a variety of sources including
state-sponsored actors.
XTO Energy’s defensive preparedness includes multi-layered technological capabilities for prevention and detection of
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 an emphasis on
resiliency including business response and recovery. The Trustee also 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 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 is also exposed to potential harm from cybersecurity events that may affect
the operations of third-parties, including our partners, suppliers, service providers (including providers of cloud-hosting
7
services for our data or applications), and customers. 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.
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 interest will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any net
proceeds therefrom.
XTO Energy drilled four horizontal wells in Major County, Oklahoma during 2018 which are currently producing. There is
no guarantee that these wells will produce in commercial quantities sufficient to recoup the investment.
The spread of different variants of the COVID-19, or the novel coronavirus, and the continually changing measures
taken to mitigate the impact of single or multiple waves of the COVID-19 pandemic, had and may in the future have an
adverse effect on the demand for oil and gas and the business and operations of the operators of the properties
underlying the net profits interests, which in turn could have an adverse effect on Trust distributions.
Demand for oil and gas, and the business and operations of the operators of the properties underlying the net profits
interests, has been and may in the future be adversely impacted by the different variants of the COVID-19 pandemic and
measures being taken to mitigate its impact. As past coronavirus outbreaks and government responses escalated and
de-escalated regionally and sporadically, the extent of any future impact on domestic sales of crude oil and natural gas
remains unknown. The industry experienced a sharp and rapid decline in the demand for crude oil and natural gas as the
8
U.S. and global economy in 2020, and commodity prices, were negatively impacted as economic activity was curtailed in
response to the COVID-19 pandemic, as well as due to other geopolitical
to
which COVID-19 will negatively impact the global economy and the oil and gas industry in the future is uncertain, but
pandemics or other significant public health events will most likely have a material adverse effect on operators’ business
and financial condition which would likely have an adverse effect on Trust distributions.
the full extent
factors. At
this time,
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.
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, a Trust unitholder will realize gain or loss equal to the difference between the amount realized on the
sale and termination of the Trust and his 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. Each Trust unitholder should consult his own tax advisor regarding Trust tax
compliance matters, including federal and state tax implications concerning the sale of the net profits interests and the
termination of the Trust.
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
9
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, or 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 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, labor, tubular materials and equipment.
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.
10
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.
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 (the “TCJA”) was enacted
December 22, 2017, and makes 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, thus, 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 (including administrative guidance
relating to the TCJA) 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, 2021, the Trust did not have any unresolved Securities and Exchange Commission staff comments.
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 1% 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
11
average reserve-to-production index for the underlying properties as of December 31, 2021 is approximately eleven years.
This index is calculated using total proved reserves and estimated 2022 production for the underlying properties. The
projected 2022 production is from proved developed producing reserves as of December 31, 2021. 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 80% natural gas
and 20% oil. XTO Energy operates approximately 95% 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 2021 development costs deducted for the underlying properties were $3.0 million, an increase
of 188% from the prior year. XTO Energy has informed the Trustee that total 2022 budgeted development costs for the
underlying properties are between $1 million and $2 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
2021, daily sales volumes from the underlying properties in the Hugoton area averaged approximately 6,100 Mcf of gas
and 20 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 2021. XTO Energy has informed the
Trustee that it does not plan to drill any new wells or perform any workovers during 2022.
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 ONEOK 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
12
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 12,300 Mcf of gas and 600 Bbls of oil in 2021.
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 did not drill any wells or perform any workovers in 2021. XTO Energy has
informed the Trustee that it does not plan to drill any new wells but may perform 1 workover in Major County during 2022.
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 2021. XTO Energy has informed the Trustee that it does
not plan to drill any new wells but may perform 1 workover in Woodward County during 2022.
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 did not drill any wells or perform any workovers in 2021. 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 2022.
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% 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
13
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, 2021, the gathering system was
collecting approximately 6,200 Mcf per day, approximately 82% 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 2,500 Mcf per day, for an average fee of approximately $0.38 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 2021 sales volumes from the underlying properties in the Fontenelle field averaged 9,500 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 2021. 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
2022. 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. XTO Energy has advised the Trustee that a
salt water disposal conversion may be executed in 2022 to assist with disposal in the Fontenelle field.
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 2021, the fuel charge was approximately 1% of the volumes produced and
the fee was approximately $0.13 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 $0.20 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% 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.
14
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, 2021. Undeveloped acreage is not significant.
Hugoton Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 202,374 190,311
Anadarko Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156,652 121,979
25,570
Green River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
32,233
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 391,259 337,860
Gross
Net
The following is a summary of the producing wells on the underlying properties as of December 31, 2021:
Operated
Wells
Non-operated
Wells
Total (a)
Gross
Net
Gross
Net
Gross
Net
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,014.0 908.9 211.0 47.2 1,225.0 956.1
36.2
Oil
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
39.0
35.0
49.0
10.0
1.2
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,053.0 943.9 221.0 48.4 1,274.0 992.3
(a) During 2021, 2020, and 2019 there were no exploratory or dry wells drilled on the underlying properties. There were 1 gross
(0.67 net), 1 gross (0.13 net), and 7 gross (3.16 net) developmental wells drilled in 2021, 2020, and 2019, respectively.
Not included in the total is 1 gross (0.28 net) non-operated well in process of drilling at December 31, 2021.
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, 2021:
Underlying Properties
Proved Reserves (a)
Gas
(Mcf)
Oil
(Bbls)
Net Profits Interests
Proved Reserves (a) (b)
Gas
(Mcf)
Oil
(Bbls)
Future Net Cash Flows
from Proved Reserves (a) (c)
Discounted
Undiscounted
(in thousands)
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
73,874
37,641
8,960
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120,475
1,355
56
50
1,461
17,691
5,785
85
23,561
324
9
1
334
$77,633
19,723
279
$42,387
13,182
114
$97,635
$55,683
(a) Based on 12-month average oil price of $64.60 per Bbl and $3.61 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
15
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%.
Proved reserves at December 31, 2021 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 . . . . . . . . . . . . .
120,475
—
—
Total proved reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
120,475
1,461
—
—
1,461
23,561
—
—
23,561
334
—
—
334
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, 2021. Miller and Lents’ primary technical person responsible for calculating the
Trust’s reserves has more than ten 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.
16
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:
2021
2020
2019
Production
Underlying Properties
Average per day (Mcf)
Gas – Sales (Mcf) . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . .
Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . .
Average per day (Bbls) . . . . . . . . . . . . .
10,193,158
27,926
232,576
637
11,372,815
31,073
316,978
866
11,112,535
30,445
302,040
828
Net Profits Interests
Average per day (Mcf)
Gas – Sales (Mcf) . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . .
Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . .
Average per day (Bbls) . . . . . . . . . . . . .
Average Sales Price
Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . . .
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . .
Average Production
Cost per BOE . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
—
—
—
—
—
—
$
$
$
4.05
59.25
13.37
$
$
$
2.15
41.12
12.97
$
$
$
109,541
300
249
1
2.95
53.60
15.13
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)
2020
2021
2019
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
710,314
6,002,087
3,480,757
808,264
7,154,714
3,409,837
868,947
6,572,242
3,671,346
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10,193,158
11,372,815
11,112,535
Conveyance
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Underlying Oil Production (Bbls)
2020
2021
2019
3,823
220,964
7,789
232,576
4,353
305,178
7,447
316,978
6,102
288,662
7,276
302,040
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
17
exceed 2% 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. 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.
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). 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.
18
State Regulation
The various states regulate the production and sale of oil and natural gas, including imposing requirements for
obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of
waste of oil and gas resources. The rates of production may be regulated and the maximum daily production allowables
from both oil and gas wells may be established on a market demand or conservation basis, or both.
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, each unitholder is taxed directly on his 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 natural gas produced from the underlying
properties. The Trust also incurs administration expenses and may earn interest income on funds held for distribution and for
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% of gross income, limited to 100% of the net income from such net
profits interest. 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.
19
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%, 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%. Under the TCJA, for such tax years,
personal exemptions and miscellaneous itemized deductions are not allowed. For such tax years, the U.S. federal income
tax rate applicable to corporations is 21%, and such rate applies to both ordinary income and capital gains.
Section 1411 of the Code imposes a 3.8% 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 royalty 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.
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 2 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. Simmons Bank, EIN: 71-0162300, 2911 Turtle Creek Blvd,
Suite 850, 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 respect to such Trust units, including the issuance of IRS Forms 1099 and certain written tax
20
statements. 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 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. However, the Trust will not file a
Kansas income tax return for the 2021 tax year because the Trust had no revenues, income or deductions in 2021
attributable to properties located in Kansas. The Trust did not file a return with Kansas for the 2020 and 2019 tax years for
the same reason.
Wyoming does not impose a state income tax.
Each unitholder 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
21
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
the approximately
to the Trust’s share of net proceeds. However, XTO Energy contended that
related adjustment
$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 Oklahoma conveyance is already currently subject to excess costs that will need to be recovered prior to any
distribution to unitholders. Therefore, 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 additional excess costs
under the Oklahoma conveyance that would likely result in no distributions under the Oklahoma conveyance for several
additional years while these additional excess costs are recovered. This award completes the portion of the arbitration
related to the Chieftain settlement.
Other Trustee claims related to disputed amounts on the computation of the Trust’s net proceeds for 2014 through
2016 were bifurcated from the initial arbitration and will be heard at a later date, which is still to be determined should the
arbitration proceed. Pursuant to the purchase and sale agreement entered into between the Trustee and XTO Energy, the
parties have agreed to stay the arbitration from the date of execution of the purchase and sale agreement to the earlier of
the termination of the purchase and sale agreement or closing date of the sale of assets. The Panel has stayed 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.
ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable.
22
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 7, 2022,
there were 40,000,000 units outstanding and approximately 543 unitholders of
record;
39,786,655 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]
23
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)
2021
2020
2021
2020
Sales Volumes
Gas (Mcf) (b)
Underlying properties . . . . . . . . . . . . . . . . . . . . . . .
Average per day . . . . . . . . . . . . . . . . . . . . . . . . .
Net profits interests . . . . . . . . . . . . . . . . . . . . . . . . .
10,193,158
27,926
—
11,372,815
31,073
—
2,535,648
27,561
—
2,893,066
31,446
—
Oil (Bbls) (b)
Underlying properties . . . . . . . . . . . . . . . . . . . . . . .
Average per day . . . . . . . . . . . . . . . . . . . . . . . . .
Net profits interests . . . . . . . . . . . . . . . . . . . . . . . . .
232,576
637
—
316,978
866
—
53,307
579
—
64,808
704
—
Average Sales Prices
Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
4.05 $
59.25 $
2.15 $
41.12 $
5.38 $
71.49 $
2.30
38.40
Revenues
Gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $41,253,923 $24,396,826 $13,642,480 $ 6,664,085
2,488,611
Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13,779,370
13,034,661
3,810,638
Total Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . .
55,033,293
37,431,487
17,453,118
9,152,696
Costs
. . . . . . . . . . . . . . . . . .
Taxes, transportation and other
Production expense . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development costs . . . . . . . . . . . . . . . . . . . . . . . . . . .
Overhead . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Excess costs (c)
10,696,192
13,691,172
2,966,646
12,141,737
15,634,495
9,353,562
16,491,918
1,030,577
12,211,615
(1,656,185)
3,040,509
3,684,901
210,872
3,056,381
7,460,455
2,428,829
4,673,294
337,144
2,875,246
(1,161,817)
Total Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
55,130,242
37,431,487
17,453,118
9,152,696
Other Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
96,949
Net Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Profits Percentage . . . . . . . . . . . . . . . . . . . . . . . . . .
—
80%
—
—
80%
—
—
80%
Net Profits Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
— $
— $
— $
—
—
80%
—
(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 twelve 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.
24
Results of Operations
Years Ended December 31, 2021 and 2020
Net profits income for 2021 was $0, as compared with $0 for 2020. This was primarily the result of higher oil and gas
prices ($21.9 million) and decreased production expenses ($2.2 million), offset by net excess costs activity ($13.8 million),
decreased oil and gas production ($7.8 million),
increased development costs ($1.5 million), and increased taxes,
transportation and other costs ($1.0 million).
Trust administration expense was $935,488 in 2021 as compared to $890,855 in 2020. Simmons Bank funded
$935,488 for the payment of Trust expenses in 2021. In addition to Simmons Bank funding $282,369 towards payment of
Trust expenses in 2020, the remaining cash reserve balance as of January 1, 2020 of $605,646 was utilized for the
payment of Trust expenses in 2020. Interest income was $0 in 2021 and $2,840 in 2020. Changes in interest income are
rates. Distributable income was $0 or
attributable to fluctuations in net profits income, cash reserve and interest
$0.000000 per unit in 2021 and $0 or $0.000000 per unit in 2020.
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 10% from 2020 to 2021 primarily because of lower gas sales from
new wells in Major County, Oklahoma, increased downtime, and natural production decline.
Oil. Underlying oil sales volumes decreased 27% from 2020 to 2021 primarily because of lower oil sales from new
wells in Major County, Oklahoma, increased downtime, and natural production decline.
The estimated rate of natural production decline on the underlying oil and gas properties is approximately 6% to 8% a
year.
Prices
Gas.
The 2021 average gas price was $4.05 per Mcf, up 88% from the 2020 average gas price of $2.15 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 2021 through January 2022 was $5.22 per MMBtu. At March 15, 2022,
the average NYMEX gas price for the following 12 months was $4.79 per MMBtu.
Oil.
The average oil price for 2021 was $59.25 per Bbl, up 44% from the average oil price for 2020 of $41.12 per
Bbl. Oil prices are expected to remain volatile. The average NYMEX price for November 2021 through January 2022 was
$77.07 per Bbl. At March 15, 2022, the average NYMEX oil price for the following 12 months was $86.91 per Bbl.
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.
revenues. Taxes, transportation and other costs increased 14% from 2020 to 2021 primarily because of
production and property taxes, partially offset by decreased gas deductions.
Taxes, transportation and other costs generally fluctuate with changes in total
increased
25
Production expense.
Production expense decreased 17% from 2020 to 2021 primarily because of decreased labor,
field costs, salt water disposal costs, plug and abandonment expenses, and timing of the annual Oklahoma SB168 fee,
partially offset by the absence of credits received for material transfers.
Development costs. Development costs increased 188% from 2020 to 2021 primarily because of drilling costs on a
non-operated well. 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 conveyance, these excess costs must be recovered, with
from future net proceeds of that conveyance and cannot reduce net profits income from another
accrued interest,
conveyance. Underlying cumulative excess costs for the Kansas, Oklahoma and Wyoming conveyances remaining as of
December 31, 2021 totaled $19.3 million ($15.5 million net to the Trust), including accrued interest of $3.1 million
($2.5 million net to the Trust). 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.
Other Proceeds.
The calculation of net profits income for 2021 included $96,949 ($77,559 net to the Trust) from
XTO Energy due to interest received on past due payments.
Fourth Quarter 2021 and 2020
Net profits income for fourth quarter 2021 was $0, as compared with $0 for fourth quarter 2020. This was primarily
the result of higher oil and gas prices ($8.8 million), decreased production expenses ($0.8 million), and decreased
development costs ($0.1 million), offset by net excess costs activity ($6.9 million), decreased oil and gas production ($2.2
million), increased taxes, transportation and other costs ($0.5 million), and increased overhead ($0.1 million).
After adding interest income of $0, deducting administration expense of $263,690, and utilizing funds of $263,690
provided by Simmons Bank for the payment of Trust expenses, distributable income for fourth quarter 2021 was $0 or
$0.000000 per unit. Distributable income for fourth quarter 2020 was $0 or $0.000000 per unit.
Distributions to unitholders for the quarter ended December 31, 2021 were:
Record Date
Payment Date
October 29, 2021
November 30, 2021
December 31, 2021
November 15, 2021
December 14, 2021
January 14, 2022
Per Unit
$0.000000
0.000000
0.000000
$0.000000
Volumes
Fourth quarter underlying gas and oil sales volumes decreased 12% and 18%, respectively, primarily because of
natural production decline, lower sales from new wells in Major County, Oklahoma, and timing of cash receipts.
Prices
The average fourth quarter 2021 gas price was $5.38 per Mcf, up 134% from the fourth quarter 2020 average price of
$2.30 per Mcf. The average fourth quarter 2021 oil price was $71.49 per Bbl, up 86% from the fourth quarter 2020
average price of $38.40 per Bbl. For further information about product prices, see “Years Ended December 31, 2021 and
2020 – Prices” above.
26
Costs
Taxes, transportation and other. Taxes, transportation and other costs increased 25% for the fourth quarter primarily
because of increased production taxes, partially offset by decreased gas deductions.
Production expense. Fourth quarter production expense decreased 21% primarily because of timing of the annual
Oklahoma SB168 fee, decreased plug and abandonment expense, field costs, and labor partially offset by increased repairs
and maintenance expenses.
Development costs. Development costs decreased 37% for the fourth quarter primarily because of decreased
development costs 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 conveyance, these excess costs must be recovered, with
from future net proceeds of that conveyance and cannot reduce net profits income from another
accrued interest,
conveyance. 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 to zero. 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. Factors attributable to the
cash shortage are primarily the previously disclosed development costs to drill four horizontal wells in Major County,
Oklahoma, lower oil and gas prices during 2019 and 2020, and excess cost positions on the Kansas, Oklahoma and
Wyoming conveyances which have resulted in no unitholder distributions since March 2018. 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, 2022
and the three months ending March 31, 2023 which assumes no cash inflow from either net profits income or from other
sources. The Trustee has sought financing to pay the Trust obligations during the one year period after the date the financial
statements are issued, especially now that the expense reserve was depleted in October 2020; however, to date such
financing has not become available.
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
27
Trustee stated it anticipates seeking reimbursement from XTO Energy upon depletion of the Trust’s cash reserve. XTO Energy
has responded that any indemnity claim to XTO Energy is premature before the Trust Estate is exhausted.
The Trustee is reviewing the Trust’s alternatives to continuing as a going concern, which may include a sale of the
Trust’s assets and/or termination of the Trust. The Trustee engaged a third party to market the Trust’s assets, and following
an extensive marketing period for the assets, on July 2, 2021, the Trustee entered into a purchase and sale agreement for
the Trust’s assets with the highest bidder, XTO Energy, for a cash purchase price of $6,600,000 (subject to adjustment as
set forth in the purchase and sale agreement). Although the Trustee and XTO Energy have entered into the purchase and
sale agreement, there is no assurance that a sale can be completed under the terms of the indenture, or if a sale is
completed under the indenture, that there will be any funds available for distribution to unitholders. Any material sale of
assets and/or termination of the Trust requires unitholder approval by at least 80% of all outstanding units. The Trustee held
a Special Meeting of unitholders on December 10, 2021 for the purpose of approving the sale of assets. The sale was not
approved by unitholders. Simmons Bank, as Trustee, is currently paying the expenses for the Trust, subject to its rights to be
indemnified and reimbursed pursuant to the terms of the Trust indenture. However, there is nothing in the Trust indenture
that requires Simmons Bank to pay the expenses for the Trust. Any funds that Simmons Bank, as Trustee, utilizes to pay
expenses of the Trust must be repaid in full (including from proceeds received from a sale of the Trust’s assets, if any)
before distributions to unitholders could be made. There can be no assurances that a sale of the Trust’s assets, if any, will
produce net proceeds sufficient to allow distributions to the unitholders and if such proceeds are available, there is no
assurance when any distribution will be made. 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 Regulation
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% 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, 2021, the monthly overhead charge, based on the number of operated wells, was approximately $989,000
($791,200 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. 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
28
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 $2.8 million for 2021,
or 7% of total gas sales, $1.9 million for 2020, or 8% of total gas sales.
On June 25, 2010, XTO Energy became a wholly-owned subsidiary of Exxon Mobil Corporation.
Simmons Bank, as Trustee of Hugoton Royalty Trust, is currently funding the expenses for the Trust, subject to its rights
to be indemnified and reimbursed pursuant to the terms of the Trust indenture. This includes reimbursement from proceeds
received from a sale of the Trust’s assets, if any. Amount funded as of December 31, 2021 is $1,217,857 as reflected in
Item 8. Financial Statements and Supplementary Data. Under the Trust indenture, the Trustee is entitled to an annual
administrative fee for services performed which was $78,255 in 2021. See Item 11. Executive Compensation, for further
information on the remuneration received by the Trustee.
The calculation of net profits income for 2021 included $96,949 ($77,559 net to the Trust) from XTO Energy due to
interest received on past due payments.
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
29
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 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% 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, potential asset sales or termination of the Trust, 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, government policy and its impact on oil and gas prices and future demand, pricing differentials, proved reserves,
future net cash flows, production levels, expense reserve budgets, availability of financing, arbitration, litigation, political
and regulatory matters, such as tax and environmental policy, climate policy,
trade barriers, sanctions, war, and
competition. 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
future performance and involve certain risks,
uncertainty of
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.
future events. These statements are not guarantees of
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
31
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.
30
Report of Independent Registered Public Accounting Firm
To the Unitholders of Hugoton Royalty Trust and Simmons Bank, 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, 2021 and 2020, 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, 2021 and 2020, 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 to zero 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 audits 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.
31
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
March 30, 2022
We have served as the Trust’s auditor since 2011.
32
HUGOTON ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
Assets
Cash and short-term investments (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Net profits interests in oil and gas properties – net (Notes 1 and 2) . . . . . . . . . . . . . . . .
660,000 $
—
$
660,000 $
Liabilities and Trust Corpus
December 31
2021
2020
Distribution payable to unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Performance guarantee deposit (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable Simmons Bank (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. .
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding) (b)
660,000
1,217,857
(1,217,857)
—
$
282,369
(282,369)
—
—
—
—
—
$
660,000 $
—
(a) Performance guarantee deposit paid by XTO Energy equal to 10% of the purchase price per Section 3.02 of the
purchase and sale agreement. In the event of a termination of the purchase and sale agreement (other than due to the
failure of XTO Energy to perform any of its material obligations thereunder or a material breach of any representation by
XTO Energy), the performance guarantee deposit, together with interest, must be returned to XTO Energy.
(b) Simmons Bank, as Trustee of the Hugoton Royalty Trust, is currently paying the expenses for the Trust, subject to its
rights to be indemnified and reimbursed pursuant to the terms of the Trust indenture. This includes reimbursement
from proceeds received from a sale of the Trust’s assets, if any.
STATEMENTS OF DISTRIBUTABLE INCOME
Net profits income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Administration expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash reserves withheld (used) for Trust expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash funded by Simmons Bank for Trust expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31
2020
2021
—
—
—
935,488
—
(935,488)
$
—
2,840
2,840
890,855
(605,646)
(282,369)
Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
—
$
—
Distributable income per unit (40,000,000 units) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.000000 $ 0.000000
STATEMENTS OF CHANGES IN TRUST CORPUS
Year Ended December 31
2020
2021
Trust corpus, beginning of year
Cash funded by Simmons Bank for Trust expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (282,369) $
(935,488)
(282,369)
—
Trust corpus, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(1,217,857) $(282,369)
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).
Simmons Bank is the Trustee for 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 1% 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.
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
4.
Distributions to unitholders are recorded when declared by the Trustee (Note 3).
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.
34
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
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 to zero. 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. Factors attributable to the
cash shortage are primarily the previously disclosed development costs to drill four horizontal wells in Major County,
Oklahoma, lower oil and gas prices during 2019 and 2020, and excess cost positions on the Kansas, Oklahoma and
Wyoming conveyances which have resulted in no unitholder distributions since March 2018. 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, 2022
and the three months ending March 31, 2023 which assumes no cash inflow from either net profits income or from other
sources. The Trustee has sought financing to pay the Trust obligations during the one year period after the date the financial
statements are issued, especially now that the expense reserve was depleted in October 2020; however, to date such
financing has not become available.
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
has responded that any indemnity claim to XTO Energy is premature before the Trust Estate is exhausted.
The Trustee is reviewing the Trust’s alternatives to continuing as a going concern, which may include a sale of the
Trust’s assets and/or termination of the Trust. The Trustee engaged a third party to market the Trust’s assets, and following
an extensive marketing period for the assets, on July 2, 2021, the Trustee entered into a purchase and sale agreement for
the Trust’s assets with the highest bidder, XTO Energy, for a cash purchase price of $6,600,000 (subject to adjustment as
35
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
set forth in the purchase and sale agreement). Although the Trustee and XTO Energy have entered into the purchase and
sale agreement, there is no assurance that a sale can be completed under the terms of the indenture, or if a sale is
completed under the indenture, that there will be any funds available for distribution to unitholders. Any material sale of
assets and/or termination of the Trust requires unitholder approval by at least 80% of all outstanding units. The Trustee held
a Special Meeting of unitholders on December 10, 2021 for the purpose of approving the sale of assets. The sale was not
approved by unitholders. Simmons Bank, as Trustee, is currently paying the expenses for the Trust, subject to its rights to be
indemnified and reimbursed pursuant to the terms of the Trust indenture. However, there is nothing in the Trust indenture
that requires Simmons Bank to pay the expenses for the Trust. Any funds that Simmons Bank, as Trustee, utilizes to pay
expenses of the Trust must be repaid in full (including from proceeds received from a sale of the Trust’s assets, if any)
before distributions to unitholders could be made. There can be no assurances that a sale of the Trust’s assets, if any, will
produce net proceeds sufficient to allow distributions to the unitholders and if such proceeds are available, there is no
assurance when any distribution will be made. 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, less
costs. Costs generally include applicable taxes,
legal and marketing charges, production expense,
transportation,
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).
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.
36
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
The following summarizes excess costs activity, cumulative excess costs balance and accrued interest to be recovered
by conveyance as calculated by XTO Energy:
KS
OK
WY
Total
Underlying
Cumulative excess costs remaining at
12/31/20 . . . . . . . . . . . . . . . . . . . . . .
$3,004,413
$23,933,548
$ 4,914,021
$31,851,982
Net excess costs (recovery) for the quarter
ended 3/31/21 . . . . . . . . . . . . . . . . . .
121,719
(1,572,241)
(579,456)
(2,029,978)
Net excess costs (recovery) for the quarter
ended 6/30/21 . . . . . . . . . . . . . . . . . .
110,948
467,270
(422,347)
155,871
Net excess costs (recovery) for the quarter
ended 9/30/21 . . . . . . . . . . . . . . . . . .
(33,637)
(5,266,894)
(999,402)
(6,299,933)
Net excess costs (recovery) for the quarter
ended 12/31/21 . . . . . . . . . . . . . . . . .
(238,412)
(5,547,816)
(1,674,227)
(7,460,455)
Cumulative excess costs remaining at
12/31/21 . . . . . . . . . . . . . . . . . . . . . .
Accrued interest at 12/31/21 . . . . . . . . . .
2,965,031
441,426
12,013,867
2,382,292
1,238,589
294,068
16,217,487
3,117,786
Total remaining to be recovered at
12/31/21 . . . . . . . . . . . . . . . . . . . . . .
$3,406,457
$14,396,159
$ 1,532,657
$19,335,273
KS
OK
WY
Total
NPI
Cumulative excess costs remaining at
12/31/20 . . . . . . . . . . . . . . . . . . . . . .
$2,403,530
$19,146,838
$ 3,931,217
$25,481,585
Net excess costs (recovery) for the quarter
ended 3/31/21 . . . . . . . . . . . . . . . . . .
97,375
(1,257,792)
(463,565)
(1,623,982)
Net excess costs (recovery) for the quarter
ended 6/30/21 . . . . . . . . . . . . . . . . . .
88,758
373,816
(337,878)
124,696
Net excess costs (recovery) for the quarter
ended 9/30/21 . . . . . . . . . . . . . . . . . .
(26,909)
(4,213,515)
(799,521)
(5,039,945)
Net excess costs (recovery) for the quarter
ended 12/31/21 . . . . . . . . . . . . . . . . .
(190,730)
(4,438,252)
(1,339,382)
(5,968,364)
Cumulative excess costs remaining at
12/31/21 . . . . . . . . . . . . . . . . . . . . . .
Accrued interest at 12/31/21 . . . . . . . . . .
2,372,024
353,141
9,611,095
1,905,833
990,871
235,254
12,973,990
2,494,228
Total remaining to be recovered at
12/31/21 . . . . . . . . . . . . . . . . . . . . . .
$2,725,165
$11,516,928
$ 1,226,125
$15,468,218
For the year ended December 31, 2021, excess costs recovered on properties underlying the Kansas net profits
interests were $39,382 ($31,506 net to the Trust). This includes excess cost recoveries of $238,412 ($190,730 net to the
Trust) for the quarter ended December 31, 2021.
37
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
For the year ended December 31, 2021, excess costs recovered on properties underlying the Oklahoma net profits
recoveries of $5,547,816
to the Trust). This includes excess cost
interests were $11,919,681 ($9,535,743 net
($4,438,252 net to the Trust) for the quarter ended December 31, 2021.
For the year ended December 31, 2021, excess costs recovered on properties underlying the Wyoming net profits
interests were $3,675,432 ($2,940,346 net to the Trust). This includes excess cost recoveries of $1,674,227 ($1,339,382
net to the Trust) for the quarter ended December 31, 2021.
Underlying cumulative excess costs for
the Kansas, Oklahoma and Wyoming conveyances remaining as of
December 31, 2021 totaled $19.3 million ($15.5 million net to the Trust), including accrued interest of $3.1 million
($2.5 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).
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. However, the Trust will not file a Kansas return for the 2021 tax year because the Trust had no
revenues, income or deductions in 2021 attributable to properties located in Kansas. The Trust did not file a Kansas income
tax return for the 2020 and 2019 tax years for the same reason.
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. However, the arbitration matter is stayed. 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
38
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
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.
If a sale of the assets of the Trust is consummated, each unitholder generally will realize gain or loss equal to the
difference between such unitholder’s amount realized on such sale and such unitholder’s adjusted basis in the assets of the
Trust. Gain or loss realized by a unitholder who is not a dealer with respect to such assets and who has a holding period for
the assets of more than one year generally will be treated as long-term capital gain or loss except to the extent of any
depletion recapture amount, which will be treated as ordinary income.
Each unitholder should consult their own tax advisor regarding income tax requirements, if any, applicable to such
person’s ownership of Trust units.
7. Related Party Transactions
XTO Energy operates approximately 95% of the underlying properties. In computing net proceeds, XTO Energy deducts
reimbursement of administrative expenses on the underlying properties it operates. As of
an overhead charge for
December 31, 2021, the monthly overhead charge, based on the number of operated wells, was approximately $989,000
($791,200 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. 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 $2.8 million for 2021,
or 7% of total gas sales, $1.9 million for 2020, or 8% of total gas sales.
On June 25, 2010, XTO Energy became a wholly-owned subsidiary of Exxon Mobil Corporation.
Simmons Bank, as Trustee of Hugoton Royalty Trust, is currently funding the expenses for the Trust, subject to its rights
to be indemnified and reimbursed pursuant to the terms of the Trust indenture. This includes reimbursement from proceeds
received from a sale of the Trust’s assets, if any. Amount funded as of December 31, 2021 is $1,217,857 as reflected in
Item 8. Financial Statements and Supplementary Data. Under the Trust indenture, the Trustee is entitled to an annual
administrative fee for services performed which was $78,255 in 2021. See Item 11. Executive Compensation, for further
information on the remuneration received by the Trustee.
The calculation of net profits income for 2021 included $96,949 ($77,559 net to the Trust) from XTO Energy due to
interest received on past due payments.
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
39
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
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
the approximately
to the Trust’s share of net proceeds. However, XTO Energy contended that
$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 Oklahoma conveyance is already currently subject to excess costs that will need to be recovered prior to any
distribution to unitholders. Therefore, 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 additional excess costs
under the Oklahoma conveyance that would likely result in no distributions under the Oklahoma conveyance for several
additional years while these additional excess costs are recovered. This award completes the portion of the arbitration
related to the Chieftain settlement.
Other Trustee claims related to disputed amounts on the computation of the Trust’s net proceeds for 2014 through
2016 were bifurcated from the initial arbitration and will be heard at a later date, which is still to be determined should the
arbitration proceed. Pursuant to the purchase and sale agreement entered into between the Trustee and XTO Energy, the
parties have agreed to stay the arbitration from the date of execution of the purchase and sale agreement to the earlier of
the termination of the purchase and sale agreement or closing date of the sale of assets. The Panel has stayed proceedings.
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
40
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
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 reserves, including recovery of
cumulative excess costs remaining at year end. Future net cash flows are discounted at an annual rate of 10%. 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 $3.61 per Mcf in 2021, and $1.34
per Mcf in 2020. Oil prices used to determine the standardized measure were based on average realized oil prices of
$64.60 per Bbl in 2021, and $36.41 per Bbl in 2020.
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
41
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
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
Gas (Mcf)
Oil (Bbls)
Balance, December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance, December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
80,173
115
(17,309)
(11,373)
—
51,606
818
78,244
(10,193)
—
1,580
9
(185)
(317)
—
1,087
78
529
(233)
—
—
13
(13)
—
—
—
363
23,198
—
—
Balance, December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120,475
1,461
23,561
—
1
(1)
—
—
—
35
299
—
—
334
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.
Proved Developed Reserves
(in thousands)
Underlying Properties
Oil (Bbls)
Gas (Mcf)
Net Profits Interests
Gas (Mcf)
Oil (Bbls)
December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
51,606
1,087
—
—
December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120,475
1,461
23,561
334
42
—
—
—
—
—
—
—
—
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
December 31
2021
2020
Underlying Properties
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $529,515 $108,957
Future costs:
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
407,471
—
122,044
52,440
108,882
75
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 69,604 $
Net Profits Interests
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $106,297 $
Future production taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,662
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
97,635
41,952
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 55,683 $
43
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
Underlying Properties
Standardized measure, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
— $
—
2021
2020
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35,217
34,789
—
(2,895)
(128)
66,983
2,621
(2,967)
2,967
—
69,604
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 69,604 $
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
— $
2,096
—
53,587
—
—
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 55,683 $
(3,242)
3,519
—
(338)
11
(50)
50
(1,031)
1,031
—
—
—
—
40
—
(40)
—
—
—
10. Quarterly Financial Data (Unaudited)
The following is a summary of net profits income, distributable income and distributable income per unit by quarter for
2021 and 2020:
2021
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020
First Quarter
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
44
Net Profits
Income
Distributable
Income
$ —
—
—
—
$ —
$ —
—
—
—
$ —
$ —
—
—
—
$ —
$ —
—
—
—
$ —
Distributable
Income per
Unit
$0.000000
0.000000
0.000000
0.000000
$0.000000
$0.000000
0.000000
0.000000
0.000000
$0.000000
Hugoton Royalty Trust
NOTES TO FINANCIAL STATEMENTS—(Continued)
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,
2021.
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,
2021 that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial
reporting.
ITEM 9B. OTHER INFORMATION
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
45
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% 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, 2021.
(c) Code of Ethics. Because the Trust has no employees, it does not have a code of ethics. Employees of the Trustee,
Simmons Bank, must comply with the bank’s code of ethics which may be found at ir.simmonsbank.com/govdocs.
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, 2021 and 2020 as specified in the Trust indenture:
Simmons Bank, Trustee (1) . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 78,255
$ 76,012
2021
2020
(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.
(c) Pay Ratio Disclosure. The Trust does not have a principal executive officer or employees and therefore, the pay
ratio disclosure is not applicable.
46
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 2021.
(b) Security Ownership of Certain Beneficial Owners. Based on the Trustee’s review of information filed with the SEC as
of March 10, 2022, the following table sets forth information with respect to each person known to the Trustee to
beneficially own more than 5% of the outstanding units.
Name and Address
Amount and Nature
of Beneficial Ownership
Percent
of Class
Christopher John Heck
2100 E. 377, Unit B
Granbury, TX 76049 . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wells Fargo & Company
420 Montgomery Street
San Francisco, CA 94163 . . . . . . . . . . . . . . . . . . . . . . .
6,439,000 (1)
16.09%
2,035,612 (2)
5.09%
(1) Pursuant to a Schedule 13G filed January 3, 2022, Christopher John Heck reported as of December 31, 2021, he directly owned 6,439,000 Units, of
which he had sole voting and dispositive power with respect to 6,415,300 Units and shared voting and dispositive power with respect to 23,700
Units.
(2) Pursuant to a Schedule 13G filed January 28, 2022, Wells Fargo & Company reported as of December 31, 2021, it owned 2,035,612 Units, of
which Wells Fargo & Company had sole voting and dispositive power with respect to 1 Unit, shared voting power with respect to 400 Units, and
shared dispositive power with respect to 2,035,211 Units, and Wells Fargo Financial Advisors Network, LLC had shared voting power with respect to
2,034,482 Units.
(c) Security Ownership of Management. The Trust has no directors or executive officers. The Trustee does not
beneficially own any units in the Trust.
(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.
Simmons Bank, as Trustee of Hugoton Royalty Trust, is currently paying the expenses for the Trust, subject to its rights
to be indemnified and reimbursed pursuant to the terms of the Trust indenture. This includes reimbursement from proceeds
received from a sale of the Trust’s assets, if any. For further information, see Note 7 to Financial Statements under Item 8.
Financial Statements and Supplementary Data.
As of March 10, 2022, 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, 2020 through December 31, 2021.
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.
47
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Fees for services performed by PricewaterhouseCoopers LLP for the years ended December 31, 2021 and 2020 are:
Audit fees-PwC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Audit-related fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All other fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021
2020
$ 190,200
—
—
—
$190,200
$ 175,800
—
—
—
$ 175,800
As referenced in Item 10. Directors, Executive Officers and Corporate Governance, above, the Trust has no audit
to fees paid to
committee pre-approval policy with respect
committee, and as a result, has no audit
PricewaterhouseCoopers LLP.
48
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, 2021 and 2020
Statements of Distributable Income for the years ended December 31, 2021 and 2020
Statements of Changes in Trust Corpus for the years ended December 31, 2021 and 2020
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)
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.
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.
(23)
(31)
(32)
Consent of Miller and Lents, Ltd.
Rule 13a-14(a)/15d-14(a) Certification
Section 1350 Certification
(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 Trustee, Simmons Bank, 2911 Turtle Creek Blvd, Suite 850, Dallas, Texas 75219.
49
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 SIMMONS BANK, TRUSTEE
By
/s/ NANCY WILLIS
Nancy Willis
Vice President
EXXON MOBIL CORPORATION
By
/s/ DAVID LEVY
David Levy
Vice President – Upstream Business Services
(The Trust has no directors or executive officers.)
Date: March 30, 2022
50
Mr. Max Boone
Unconventional Reservoir Engineering Manager
XTO Energy Inc.
22777 Springwoods Village Parkway
Spring, TX 77389-1425
January 21, 2022
EXHIBIT 99.1
Re:
Underlying Properties (100%)
Relating to the Hugoton Royalty Trust
Reserves and Future Net Revenues
As of December 31, 2021
SEC Price Case
Dear Mr. Boone:
At your request, Miller and Lents, Ltd. (M&L) estimated the proved reserves and future net revenues as of December 31,
2021, attributable to the XTO Energy Inc. (XTO) interest in certain oil and gas properties prior to inclusion in the Hugoton
Royalty Trust, i.e., Underlying Properties (100%). The Underlying Properties (100%) include working interest properties from
which net profits interests were conveyed to the Hugoton Royalty Trust. The properties consist of approximately 1,357 leases
and 1,477 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
50
50
8,960
8,960
14,267
14,267
8,058
8,058
Oklahoma
Proved Developed Producing . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,355
1,355
73,874
190,957
105,338
73,874
190,957
105,338
Wyoming
Proved Developed Producing . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
56
56
37,641
37,641
64,963
64,963
38,487
38,487
Total Underlying Properties (100%)
Proved Developed Producing . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,461
1,461
120,475
270,187
151,882
120,475
270,187
151,882
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 January 21, 2022.
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
Underlying Properties (100%)
Relating to the Hugoton Royalty Trust
January 21, 2022
reserves is shown on Appendix 2 (not included). Gas volumes for each property are stated at 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
this report. M&L employed all methods, data,
as represented and were considered appropriate for
procedures, and assumptions considered necessary and appropriate in utilizing the data provided to prepare this report.
the purpose of
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 utilization of analogous or indirect data
judgments. Government policies and market conditions different from those
and (2) the application of professional
Underlying Properties (100%)
Relating to the Hugoton Royalty Trust
January 21, 2022
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 ten 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
A.
Oil Price
B.
Gas Price
Appendix 1
Hugoton Royalty Trust (100%)
SEC PRICE CASE
Average price during the 12-month period prior
to 12/31/21 determined as the
arithmetic average of the first-day-of-the-month price for each month during the year
2021. 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 $66.56 per
barrel and is held constant through the life of the property. The average realized price,
after appropriate adjustments, is $64.60 per barrel.
Average price during the 12-month period prior
to 12/31/21 determined as the
arithmetic average of the first-day-of-the-month price for each month during the year
2021. The average price was based on the Henry Hub benchmark price. The arithmetic
average of the first-day-of-the-month benchmark price is $3.598 per MMBTU and is held
constant through the life of the property. The average realized price, after appropriate
adjustments is $3.61 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
Simmons Bank, Trustee
2911 Turtle Creek Blvd, Suite 850
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
American Stock Transfer and Trust Company LLC
www.astfinancial.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, 2021.
Hugoton Royalty Trust
Simmons Bank
2911 Turtle Creek Blvd, Suite 850
Dallas, Texas 75219
1-855-588-7839
www.hgt-hugoton.com