Hugoton Royalty Trust2018Annual Report and Form 10-K Glossary of Terms
Bbl
Bcf
BOE
Mcf
Barrel (of oil)
Billion cubic feet (of natural gas)
Barrel of oil equivalent
Thousand cubic feet (of natural gas)
MMBtu
One million British Thermal Units, a common energy measurement
net proceeds
Gross proceeds received by XTO Energy from sale of production from the underlying
properties, less applicable costs, as defined in the net profits interest conveyances.
net profits income
Net proceeds multiplied by the net profits percentage of 80%, which is paid to the
Trust by XTO Energy. “Net profits income” is referred to as “royalty income” for 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
2018
Years Ended December 31,
Net Profits Income ..................... $ 1,590,949
370,040
Distributable Income .................
Distributable Income per Unit .. 0.009251
Distributions per Unit................. 0.009251
Total Assets at Year End ........... 16,945,147
2017
$ 5,317,931
4,520,240
0.113006
0.113006
17,813,389
2016
$ 2,617,640
1,855,400
0.046385
0.046385
28,143,303
2015
$ 8,243,917
7,753,240
0.193831
0.193831
88,185,111
2014
$ 44,446,473
43,809,680
1.095242
1.095242
93,920,959
Inside front cover. 2-color.
PMS#301U and black.
The Trust
Hugoton Royalty Trust was created on
December 1, 1998 when XTO Energy Inc.
conveyed 80% net profits interests in certain
Net profits income received by the Trust
on the last business day of each month is
calculated and paid by XTO Energy based on
predominantly gas-producing properties
net proceeds received from the underlying
located in Kansas, Oklahoma and Wyoming
properties in the prior month. Distributions,
to the Trust. The net profits interests are the
as calculated by the Trustee, are paid to
only assets of the Trust, other than cash held
month-end unitholders of record within ten
for Trust expenses and for distribution to
business days.
unitholders.
Summary
The Trust was created to collect and
distribute to unitholders monthly net
profits income related to the 80% net
($14.4 million NPI), including accrued interest
of $0.2 million ($0.1 million NPI). For further
information on excess costs, see Note 4 to
profits interests. Such net profits income
Financial Statements under Item 8, “Financial
is calculated as 80% of the net proceeds
Statements and Supplementary Data” of the
received from certain working interests in
accompanying Form 10-K.
predominantly gas-producing properties
in Kansas, Oklahoma and Wyoming. Net
proceeds from properties in each state
Cost Depletion is generally available to
unitholders as a deduction from royalty
are calculated by deducting production
income. Available depletion is dependent
expense, development costs and overhead
upon the unitholder’s cost of units, purchase
from revenues. If monthly costs exceed
revenues from the underlying properties
date and prior allowable depletion. It may
be more beneficial for unitholders to deduct
in any state, such excess costs must be
percentage depletion. Please see the
recovered, with accrued interest, from
2018 tax booklet for specific instructions.
future net proceeds of that state and cannot
Unitholders should consult their tax advisors
reduce net profits income from another state.
for further information.
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, 2018 totaled $18.0 million
To Unitholders:
We are pleased to present the 2018
Annual Report on Form 10-K of the
Hugoton Royalty Trust as filed with the
Results of Operations” under Item 7 of the
accompanying Form 10-K.
XTO Energy is a party to legal
Securities and Exchange Commission.
proceedings that may affect future Trust
This report contains important
distributions. For further information,
information about the Trust’s net profits
see Note 8 to Financial Statements
interests, including information provided
under Item 8, “Financial Statements
to the Trustee by XTO Energy.
and Supplementary Data” of the
For the year ended December 31,
accompanying Form 10-K.
2018, net profits income totaled $1,590,949.
Natural gas prices averaged $2.69
After adding interest income of $23,152,
per Mcf for 2018, 8% lower compared to
net cash reserve activity of $128,157 and
the 2017 average price of $2.92 per Mcf.
deducting Trust administration expense
The average 2018 oil price was $62.69 per
of $1,115,904, distributable income was
Bbl, 35% higher compared to the 2017
$370,040 or $0.009251 per unit. Net profits
average price of $46.47 per Bbl.
income and distributions were 70% and
Gas sales volumes from the
91.8%, respectively, lower than 2017
underlying properties for 2018 were
amounts primarily because of higher
12,994,466 Mcf, or 35,601 Mcf per day,
development costs, lower gas prices,
a decrease of 7% from 38,091 Mcf per
lower oil and gas production, higher
day in 2017. Oil sales volumes from the
expenses, partially offset by excess
underlying properties were 155,334 Bbls,
costs and higher oil prices. For further
or 426 Bbls per day in 2018, a decrease
information, see “Trustee’s Discussion
of 1% from 428 Bbls per day in 2017. For
and Analysis of Financial Condition and
further information on sales volumes and
To Unitholders: Continued
product prices, see “Trustee’s Discussion
profits interests. All reserve information
and Analysis of Financial Condition and
prepared by independent engineers has
Results of Operations” under Item 7 of the
been provided to the Trustee by
accompanying Form 10-K.
XTO Energy.
As of December 31, 2018, proved
Estimated future net cash flows
reserves for the underlying properties
from proved reserves of the net profits
were estimated by independent
interests at December 31, 2018 were $54.1
engineers to be 121.2 Bcf of natural gas
million. Using an annual discount factor
and 2.0 million Bbls of oil. From year-
of 10%, the present value of estimated
end 2017 to 2018, gas and oil reserves
future net cash flows at December 31,
for the underlying properties increased
2018 was $30.3 million. Proved reserve
2% and 52%, respectively, primarily
estimates and related future net cash
due to additions for new development
flows have been determined based on a
activity and higher oil prices used to
12-month average gas price of $2.36 per
estimate reserves. Based on an allocation
Mcf and a 12-month average oil price of
of these reserves, proved reserves
$63.30 per Bbl, based on the first-day-of-
attributable to the net profits interests
the-month price for each month in the
were estimated to be 12.8 Bcf of natural
period, and year end costs, including
gas and 443,000 Bbls of oil. Because Trust
recovery of cumulative excess costs
reserve quantities are determined using
remaining at year end. Other guidelines
an allocation formula, any fluctuations
used in estimating proved reserves, as
in actual or assumed prices or costs
prescribed by the Financial Accounting
will result in revisions to the estimated
Standards Board, are described
reserve quantities allocated to the net
in Note 9 to Financial Statements
To Unitholders: Continued
under Item 8, “Financial Statements
income. Unitholders should consult their
and Supplementary Data” of the
tax advisors for further information.
accompanying Form 10-K. The present
value of estimated future net cash flows
is computed based on SEC guidelines and
is not necessarily representative of the
market value of Trust units.
As disclosed in the tax instructions
provided to unitholders in February
2019, Trust distributions are considered
portfolio income, rather than passive
Hugoton Royalty Trust
By: Simmons Bank, Trustee
By: Nancy Willis
Vice President
March 29, 2019
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, 2018
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: Units of Beneficial Interest
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ‘ No Í
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes ‘ No Í
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 Í 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. Í
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 Í
Accelerated filer
‘
Smaller reporting company Í
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 is a shell company (as defined in Rule 12b-2 of the Act). Yes ‘ No Í
The aggregate market value of units of beneficial interest held by non-affiliates of the registrant at June 30, 2018 (the last business day of the
registrant’s most recently completed second fiscal quarter) was approximately $26.0 million.
The number of units of beneficial interest outstanding as of February 15, 2019 was 40,000,000.
HUGOTON ROYALTY TRUST
2018 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
Page
Glossary of Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
Part I
Item 1.
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Item 3.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4. Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part II
Item 5. Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units . . . . . . . . .
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . .
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part III
Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 11.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder
Item 12.
Item 13.
Item 14.
Item 15.
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . . .
Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part IV
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2
4
10
10
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22
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24
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32
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46
46
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48
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i
HUGOTON ROYALTY TRUST
GLOSSARY OF TERMS
The following are definitions of significant terms used in this Annual Report on Form 10-K:
Bbl
Bcf
BOE
Mcf
MMBtu
net proceeds
net profits income
net profits interest
underlying properties
Barrel (of oil)
Billion cubic feet (of natural gas)
Barrel of oil equivalent
Thousand cubic feet (of natural gas)
One million British Thermal Units, a common energy measurement
Gross proceeds received by XTO Energy from sale of production from the
underlying properties, less applicable costs, as defined in the net profits interest
conveyances.
Net proceeds multiplied by the net profits percentage of 80%, which is paid to
the Trust by XTO Energy. “Net profits income” is referred to as “royalty income”
for 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.
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), as grantor, and NationsBank, N.A., as Trustee. On January 9, 2014, the successor of
NationsBank, N.A., U.S. Trust, Bank of America Private Wealth Management, a division of Bank of America, N.A.,
gave notice to unitholders that it would resign as Trustee. At a special meeting of the Trust’s unitholders held on
May 23, 2014, the unitholders of the Trust voted to approve the proposal to appoint Southwest Bank as successor
Trustee of the Trust effective May 30, 2014.
Effective October 19, 2017, Simmons First National Corporation (“SFNC”) completed its acquisition of First
Texas BHC, Inc., the parent company of Southwest Bank, the Trustee of the Trust. SFNC is the parent of Simmons
Bank. SFNC merged Southwest Bank with Simmons Bank effective February 20, 2018. 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 web site is www.hgt-hugoton.com. We make available free of charge,
through our web site, 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 web site 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.”
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.
2
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
terms reasonably obtainable in the
under existing sales contracts, or new arrangements on the best
circumstances. See “Pricing and Sales Information” under Item 2, Properties.
Net profits income received by the Trust on or before the last business day of the month is related to net
proceeds received by XTO Energy in the preceding month, and is generally attributable to oil and gas production
two months prior. The amount to be distributed to unitholders each month by the Trustee is determined by:
Adding –
1. net profits income received;
2. interest income and any other cash receipts; and
3. cash available as a result of reduction of cash reserves; then
Subtracting –
1. liabilities paid; and
2. the reduction in cash available related to establishment of or increase in any cash reserve.
The monthly distribution amount is distributed to unitholders of record within ten business days after the
monthly record date. The monthly record date is generally the last business day of the month. The Trustee
calculates the monthly distribution amount and announces the distribution per unit at least ten days prior to the
monthly record date.
The Trustee may establish cash reserves for contingencies. Cash held for such reserves, as well as for
pending payment of the monthly distribution amount, may be invested in federal obligations or certificates of
deposit of major banks.
The Trustee’s function is to collect the net profits income from the net profits interests, to pay all Trust
expenses, and to pay the monthly distribution amount to unitholders. The Trustee’s powers are specified by the
terms of the Trust indenture. The Trust cannot engage in any business activity or acquire any assets other than
the net profits interests and specific short-term cash investments. The Trust has no employees since all
administrative functions are performed by the Trustee.
Approximately 75% of the net profits income received by the Trust during 2018 was attributable to natural
gas, as well as 64% of the Trust’s estimated future net cash flows from proved reserves at December 31, 2018
(based on estimated future net cash flows using 12-month average oil and gas prices, based on the
first-day-of-the-month price for each month in the period). 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.
3
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.
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.
Increases in excess costs for the Kansas, Oklahoma and Wyoming conveyances have resulted in no net
proceeds to the Trust for the last nine months of 2018 and a reduction in the Trust’s expense reserve. These
conditions raise substantial doubt about the Trust’s ability to continue as a going concern as the Trust may not
have, based on the current estimated administrative expenses, 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 more 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 tends to be tied to the recent and expected levels of cash
distributions on the Trust units. 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.
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, to a lesser extent, oil. Oil and natural gas prices can fluctuate widely on a month-to-month basis in
response to a variety of factors that are beyond the control of the Trust and XTO Energy. Factors that contribute to
price fluctuations include instability in oil-producing regions, worldwide economic conditions, weather conditions,
the supply of domestic and foreign oil, natural gas and natural gas liquids, consumer demand, the price and
availability of alternative fuels, the proximity to, and capacity of, transportation facilities and the effect of
worldwide energy conservation measures. Moreover, government regulations, such as regulation of natural gas
4
transportation and price controls, can affect product prices. Oil and natural gas prices have declined substantially
from historical highs and may not return to those levels in the foreseeable future, if ever. A significant decline in
current oil or natural gas 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. 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 the Kansas net profits interest for all of 2017
and 2018 and with respect to the properties underlying the Wyoming net profits interests for the first three
quarters of 2017, and all of 2018, and with respect to the properties underlying the Oklahoma net profits interest,
the second, third, and fourth quarters of 2018 due to the drilling of four horizontal wells in Major County,
Oklahoma), 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
$2 million and $4 million for 2019 which could continue to exceed revenues for the underlying conveyance. 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, plaintiffs submitted their final plan of
allocation which was approved by the court on the same date. XTO Energy has advised the Trustee that it believes
approximately $24.3 million in additional production costs should be allocated to the Trust. The Trustee has
submitted a demand for arbitration and the arbitration panel has been selected. The hearing on the claims related
to the Chieftain settlement has been scheduled for October 7, 2019. The remaining claims related to the
computation of the Trust’s net proceeds were bifurcated and will be heard at a later date, which is still to be
determined. If the approximately $24.3 million allocated portion of the Chieftain settlement results in an adjustment
to the Trust’s share of net proceeds, it would result in additional excess costs under the Oklahoma conveyance
that would likely result in no distributions under the Oklahoma conveyance for several years, or more depending
on the results of operations of the underlying properties, while these additional excess costs are recovered. See
Item 8 — Financial Statements and Supplementary Data — Notes to Financial Statements — Note 8 —
Contingencies for additional information.
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.” Trading on the OTCQX 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 our 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. We currently expect the
Trust units will continue to trade on the OTCQX.
5
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,
leakage of oil or natural gas,
including without limitation natural disasters, blowouts, explosions, fires,
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.
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.
6
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 on 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 expected
to be completed and begin producing during 2019. There is no guarantee that these wells will produce or produce
in commercial quantities sufficient to recoup the investment.
Terrorism and geopolitical hostilities could adversely affect Trust distributions or the market price of the Trust
units.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other
actions taken in response, cause instability in the global financial and energy markets. 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 an act of terror.
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
7
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 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
and Note 5 Development Costs 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.
8
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 or natural disasters; and
costs of, or shortages or delays in the availability of, drilling rigs, 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.
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. 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 and lacks administrative guidance, thus, Trust unitholders should consult
their tax advisor regarding the TCJA and its effect on an investment in Trust units.
9
For taxable years beginning after 2017, the highest marginal U.S. federal income tax rates applicable to
ordinary income and long-term capital gains of individuals are 37% and 20%, respectively. 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, 2018, 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 average reserve-to-production index for the underlying properties as of December 31, 2018 is
approximately 11 years. This index is calculated using total proved reserves and estimated 2019 production for the
underlying properties. The projected 2019 production is from proved developed producing reserves as of
December 31, 2018. 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 64% natural gas and 36% 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 Trustee’s Discussion and Analysis of
Financial Condition and Results of Operations, under Item 7. Total 2018 development costs deducted for the
underlying properties were $21.8 million, an increase of 679% from the prior year. XTO Energy has informed the
Trustee that total 2019 budgeted development costs for the underlying properties are between $2 million and
$4 million. Changes in oil or natural gas prices could impact future development plans on the underlying
properties.
XTO Energy has advised the Trustee that, effective April 1, 2017, Cross Timbers Energy Services, Inc.
(“CTES”), a wholly owned marketing subsidiary of XTO Energy, has assigned all gas sales contracts for production
from the underlying properties to XTO Energy. XTO Energy will directly market and sell the gas to third parties. XTO
Energy has advised the Trustee that there are no changes to the terms of the contracts related to the assignment
and no impact on Trust distributions.
10
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 2018, daily sales volumes from the underlying properties in the Hugoton area averaged
approximately 9,700 Mcf of gas and 41 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 wells but did perform 3 workovers in 2018. XTO Energy has
informed the Trustee that it does not plan to drill any new wells but may perform up to 5 workovers during 2019.
XTO Energy’s future development plans for the underlying properties in the Hugoton area 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. The system collects the majority of its throughput from
underlying properties, which XTO Energy has advised the Trustee has been approximately 9,100 Mcf per day. 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 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. is
in force from May 1, 2014 until March 31, 2019, and from year to year thereafter until 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.
11
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 15,100 Mcf of gas and 364 Bbls of oil in 2018.
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 drilled 4 wells and performed 32 workovers in 2018.
XTO Energy has informed the Trustee that it plans to complete the four new horizontal wells in the first half of 2019
and may perform up to 30 workovers in Major County during 2019.
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 but did perform 10 workovers in 2018. XTO Energy
has informed the Trustee that it does not plan to drill any new wells but may perform up to 10 workovers in
Woodward County during 2019.
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 but did perform 5 workovers in 2018. XTO Energy has informed the
Trustee that it does not plan to drill any new wells but may perform up to 10 workovers within the Elk City field
during 2019.
XTO Energy plans to further develop the underlying properties in the Anadarko Basin primarily through:
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 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. During 2018, the gathering system collected approximately 6,100 Mcf per day,
approximately 50% of which XTO Energy operates. Estimated capacity of the gathering system is 24,000 Mcf per
day. The gathering subsidiary also provides contract operating services to properties in Woodward County,
collecting approximately 2,900 Mcf per day, for an average fee of approximately $0.11 per Mcf. The fee is subject
12
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 2018 sales volumes from the underlying properties in the Fontenelle field averaged 10,800 Mcf of natural
gas and 21 Bbls of oil. XTO Energy did not drill any wells or perform any workovers in the Green River Basin in
2018. 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 2019. 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 2019 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 2018, the
fuel charge was approximately 1% of the volumes produced and the fee was approximately $0.12 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.
13
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
is
interest owned by XTO Energy. Although many of XTO Energy’s wells produce both oil and gas, a well
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, 2018. Undeveloped acreage is not significant.
Hugoton Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Anadarko Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Green River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
203,154
157,648
32,194
191,091
122,535
25,541
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
392,996
339,167
Gross
Net
The following is a summary of the producing wells on the underlying properties as of December 31, 2018:
Operated
Wells
Non-operated
Wells
Total(a)
Gross
Net
Gross
Net
Gross
Net
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil
1,103.0
42.0
985.3
39.0
248.0
6.0
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,145.0
1,024.3
254.0
53.4
0.8
54.2
1,351.0
48.0
1,038.7
39.8
1,399.0
1,078.5
(a) During 2018, 2017 and 2016 there were no exploratory or dry wells drilled on the underlying properties. There
were 2 gross (0.11 net), 1 gross (0.0 net) and zero gross developmental wells drilled in 2018, 2017 and 2016,
respectively. Not included in the totals are 4 gross (2.83 net) operated wells and 2 gross (0.20 net) non-
operated wells in process of drilling at December 31, 2018.
14
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, 2018:
Underlying Properties
Proved Reserves(a)
Oil
Gas
(Bbls)
(Mcf)
Net Profits Interests
Proved Reserves(a)(b)
Gas
(Mcf)
Oil
(Bbls)
Future Net Cash Flows
from Proved Reserves(a)(c)
Undiscounted
Discounted
(in thousands)
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
87,208
26,219
7,763
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . .
121,190
1,896
41
68
2,005
12,035
59
696
12,790
437
—
6
443
$52,296
130
1,686
$54,112
$29,350
99
842
$30,291
(a) Based on 12-month average oil price of $63.30 per Bbl and $2.36 per Mcf
for gas, based on the
first-day-of-the-month price for each month in the period.
(b) Since the Trust has defined net profits interests, the Trust does not own a specific percentage of the oil and
gas reserves. Oil and gas reserves are allocated to the net profits interests by dividing Trust net cash inflows
by 12-month average oil and gas prices. As such, reserves allocated to the Trust have been reduced to
reflect recovery of the Trust’s portion of applicable production and development costs, which includes
overhead and excess costs. Any conveyance where costs exceed revenues will result in zero allocated net
profits interests reserves for that conveyance.
(c) Before income taxes, since future net cash flows are not subject to taxation at the trust level. Future net cash
flows are discounted at an annual rate of 10%.
Proved reserves at December 31, 2018 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 reserves . . . . . . . . . . . . . . . . . . . . . . .
Proved undeveloped reserves . . . . . . . . . . . . . . . . . . . . .
Proved non-producing reserves . . . . . . . . . . . . . . . . . . .
110,953
9,956
281
Total proved reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . .
121,190
1,339
666
—
2,005
7,944
4,811
35
12,790
121
322
—
443
Approximately 90% of the underlying proved reserves are proved developed reserves.
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, 2018, 2017, 2016 and 2015. Miller and Lents’
15
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.
Oil and gas production and average sales prices attributable to the underlying properties and the net profits
interests for each of the two years ended December 31 were as follows:
2018
2017
Production
Underlying Properties
Gas – Sales (Mcf) . . . . . . . . . . . . . . . . . . . . . . . .
Average per day (Mcf) . . . . . . . . . . . . . . . . . .
Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . .
Average per day (Bbls)
12,994,466
35,601
155,334
426
Net Profits Interests
Gas – Sales (Mcf) . . . . . . . . . . . . . . . . . . . . . . . .
Average per day (Mcf) . . . . . . . . . . . . . . . . . .
Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . .
Average per day (Bbls)
Average Sales Price
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas (per Mcf)
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
447,961
1,227
7,627
21
$ 2.69
$ 62.69
13,903,368
38,091
156,352
428
1,628,427
4,461
26,775
73
$ 2.92
$ 46.47
Average Production
Cost per BOE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$12.83
$ 11.60
16
Oil and gas production by conveyance attributable to the underlying properties for each of the two years
ended December 31 were as follows:
Conveyance
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Underlying Gas Production (Mcf)
2018
1,077,152
7,988,035
3,929,279
2017
1,225,165
8,584,930
4,093,273
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,994,466
13,903,368
Conveyance
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Underlying Oil Production (Bbls)
2018
8,621
138,880
7,833
155,334
2017
7,049
143,099
6,204
156,352
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 2019. If new contracts are entered with unaffiliated third parties, the proceeds from sales under those
new contracts will be included in gross proceeds from the underlying properties. If new contracts are entered
with any subsidiary of XTO Energy, it may charge XTO Energy a fee that may not exceed 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.
17
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.
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. Impairment 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
18
natural gas produced from the underlying properties. During 2018, the Trust incurred administration expenses and
earned 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 percent 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 his or her 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 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. The Internal Revenue Service likely will take the position that a unitholder must recapture
depletion upon the disposition of a unit.
Interest and net profits income attributable to ownership of units and any gain on the sale thereof are
considered portfolio income, and not income from a “passive activity,” to the extent a unitholder acquires and
holds units as an investment and not in the ordinary course of a trade or business. Therefore, interest and net
profits income attributable to ownership of units generally may not be offset by losses from any passive activities.
Under the recently enacted “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.
For tax years beginning before January 1, 2018, the highest marginal U.S. federal income tax rate applicable
to ordinary income of individuals is 39.6%, and the highest marginal U.S. federal income tax rate applicable to
long-term capital gains and qualified dividends of individuals is 20%. For such pre-2018 tax years, such marginal
tax rates may be effectively increased by up to 1.2% due to the phaseout of personal exemptions and the
limitations on itemized deductions. For such pre-2018 tax years, the highest marginal U.S. federal income tax rate
applicable to corporations is 35%, and such rate applies to both ordinary income and capital gains.
19
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, 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
institutions located in jurisdictions that have an intergovernmental
imposed by FATCA. Foreign financial
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 advisors 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
including the issuance of IRS Forms 1099 and certain written tax statements.
respect to such Trust units,
20
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 advisors 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 2018 tax year because the Trust had no revenues, income or deductions
in 2018 attributable to properties located in Kansas. The Trust did not file a return with Kansas for the 2017 and
2016 tax years for the same reason.
Wyoming does not impose a state income tax.
Each unitholder should consult his or her 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
In December 2010, a royalty class action lawsuit was filed against XTO Energy styled Chieftain Royalty
Company v. XTO Energy Inc. in Coal County District Court, Oklahoma. XTO Energy removed the case to federal
court in the Eastern District of Oklahoma. The plaintiffs allege that XTO Energy wrongfully deducted fees from
royalty payments on Oklahoma wells, failed to make diligent efforts to secure the best terms available for the sale
of gas and its constituents, and demanded an accounting to determine whether they have been fully and fairly
paid gas royalty interests. The case was certified as a class action in April 2012, then decertified in July 2013.
21
XTO Energy advised the Trustee that in December 2017, it reached a tentative settlement with the plaintiffs
for $80 million and up to an additional $750 thousand for costs to administer the settlement following final
approval. In March 2018, XTO Energy advised the Trustee that it believed the portion of the settlement that relates
to the Trust could be as much as $20 million, but the settlement allocable to the Trust could not be finally
determined until after the judge approved the plaintiffs’ final plan of allocation. On July 27, 2018, plaintiffs
submitted their final plan of allocation which was approved by the court on the same date. Based on the final plan
of allocation XTO Energy has 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
styled Simmons Bank (successor to Southwest Bank and Bank of America, N.A.) vs. XTO Energy Inc. (the
“Arbitration”) through the American Arbitration Association 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. In the Arbitration, the Trustee also made claims for disputed amounts on the computation of
the Trust’s net proceeds for 2014 through 2016 in excess of $5 million. XTO Energy filed its answer denying the
Trustee’s claims. The Arbitration panel has been selected. The hearing on the claims related to the Chieftain
settlement has been scheduled for October 7, 2019. The remaining claims related to the computation of the Trust’s
net proceeds were bifurcated and will be heard at a later date, which is still to be determined.
If the approximately $24.3 million allocated portion of the Chieftain settlement results in an adjustment to the
Trust’s share of net proceeds, it would result in additional excess costs under the Oklahoma conveyance that
would likely result in no distributions under the Oklahoma conveyance for several years, or more depending on the
results of operations of the underlying properties, while these additional excess costs are recovered.
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 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.” Any quotations on
the OTCQX reflect inter-dealer prices, without retail mark-up, mark-down, or commission and may not necessarily
reflect actual transactions.
At December 31, 2018, there were 40,000,000 units outstanding and approximately 593 unitholders of record;
39,427,406 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. Selected Financial Data
Not required for smaller reporting companies; the Trust has elected to omit this information.
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)
2017
2018
Three Months Ended December 31(a)
2018
2017
Sales Volumes
Gas (Mcf)(b)
Underlying properties . . . . . . . . . . . . . . . . . .
Average per day . . . . . . . . . . . . . . . . . . . .
Net profits interests . . . . . . . . . . . . . . . . . . .
12,994,466
35,601
447,961
13,903,368
38,091
1,628,427
Oil (Bbls)(b)
Underlying properties . . . . . . . . . . . . . . . . . .
Average per day . . . . . . . . . . . . . . . . . . . .
Net profits interests . . . . . . . . . . . . . . . . . . .
155,334
426
7,627
156,352
428
26,775
3,265,229
35,492
—
34,666
377
—
3,405,474
37,016
341,493
37,061
403
5,554
Average Sales Prices
Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil (per Bbl)
$
$
2.69
62.69
$
$
2.92
46.47
$
$
2.68
67.99
$
$
2.88
47.05
Revenues
Gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 34,963,154
9,737,686
$40,650,478
7,264,995
$ 8,765,079
2,356,923
$ 9,823,346
1,743,585
Total Revenues . . . . . . . . . . . . . . . . . . . . . . .
44,700,840
47,915,473
11,122,002
11,566,931
Costs
Taxes, transportation and other . . . . . . . . . . . .
Production expense . . . . . . . . . . . . . . . . . . . . .
Development costs(c)
. . . . . . . . . . . . . . . . . . . .
Overhead . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Excess costs(d) . . . . . . . . . . . . . . . . . . . . . . . . . .
8,178,584
18,131,944
21,802,500
11,636,835
(17,037,709)
Total Costs . . . . . . . . . . . . . . . . . . . . . . . . . . .
42,712,154
Net Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Profits Percentage . . . . . . . . . . . . . . . . . . . . .
1,988,686
80%
8,259,657
17,128,387
2,800,000
11,570,344
1,509,671
41,268,059
6,647,414
80%
Net Profits Income . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,590,949
$ 5,317,931
$
2,060,152
4,349,947
7,837,500
2,917,565
(6,043,162)
1,990,343
4,193,695
840,000
2,919,732
271,652
11,122,002
10,215,422
—
80%
—
1,351,509
80%
$ 1,081,207
(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 5 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
(d) See Note 4 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
24
Results of Operations
Years Ended December 31, 2018 and 2017
Net profits income for 2018 was $1,590,949, as compared with $5,317,931 for 2017. The 70% decrease in net
profits income from 2017 to 2018 was primarily the result of higher development costs ($15.2 million), lower gas
prices ($2.5 million), lower oil and gas production ($2.0 million), higher production expenses ($0.8 million), partially
offset by excess costs ($14.8 million) and higher oil prices ($2.0 million). Approximately 75% in 2018 and 78% in
2017 of net profits income was derived from natural gas sales.
Trust administration expense was $1,115,904 in 2018 as compared to $804,719 in 2017. Net cash reserve
activity was $128,157 in 2018 and $0 in 2017. Cash reserve activity for 2018 included additions of $922,409 which the
Trustee reserved for administrative expenses, offset by reductions of $794,252 for the payment of trust expenses.
Interest income was $23,152 in 2018 and $7,028 in 2017. Changes in interest income are attributable to fluctuations
in net profits income and interest rates. Distributable income was $370,040 or $0.009251 per unit in 2018 and
$4,520,240 or $0.113006 per unit in 2017.
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.
From 2017 to 2018, underlying gas sales volumes decreased 7% primarily due to natural production
decline.
Oil.
From 2017 to 2018, underlying oil sales volumes decreased 1% primarily due to natural production
decline, partially offset by timing of cash receipts.
The estimated rate of natural production decline on the underlying oil and gas properties is approximately 6%
to 8% a year.
Prices
Gas. The 2018 average gas price was $2.69 per Mcf, an 8% decrease from the 2017 average gas price of
$2.92 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 import levels of liquefied natural gas. Natural gas
prices are expected to remain volatile. The average NYMEX price for November 2018 through January 2019 was
$3.85 per MMBtu. At March 1, 2019, the average NYMEX gas price for the following 12 months was $2.99 per
MMBtu.
Oil. The average oil price for 2018 was $62.69 per Bbl, a 35% increase from the average oil price for 2017 of
$46.47 per Bbl. Oil prices are expected to remain volatile. The average NYMEX price for November 2018 through
January 2019 was $52.44 per Bbl. At March 1, 2019, the average NYMEX oil price for the following 12 months was
$57.30 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.
25
Taxes, transportation and other.
Taxes, transportation and other generally fluctuates with changes in total
revenues. Taxes, transportation and other decreased 1% from 2017 to 2018 primarily because of decreased
production taxes related to lower gas revenues, partially offset by increased gas deductions related to gathering
fees and increased production taxes on higher oil revenues.
Production expense. Production expense increased 6% from 2017 to 2018 primarily because repairs and
maintenance, partially offset by decreased other field goods and services.
Development costs. Development costs, which were deducted based on budgeted development costs,
were $21.8 million in 2018 and $2.8 million in 2017. In 2018, actual development costs were $8.4 million. At
December 31, 2018, cumulative budgeted costs deducted exceeded cumulative actual costs by approximately
$13.9 million.
The monthly deduction is based on the current
level of development expenditures, budgeted future
development costs and the cumulative actual costs under (over) previous deductions. Changes in oil or natural
gas prices could impact future development plans on the underlying properties. XTO Energy has advised the
Trustee that this monthly deduction will continue to be evaluated and revised as necessary. For further
information on development costs, see Note 5 to Financial Statements under Item 8, Financial Statements and
Supplementary Data.
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 accrued interest, from future net proceeds of that conveyance and cannot reduce net profits
income from another conveyance. Underlying cumulative excess costs for the Kansas, Oklahoma and Wyoming
conveyances remaining as of December 31, 2018 totaled $18.0 million ($14.4 million NPI), including accrued
interest of $0.2 million ($0.1 million NPI). For further information on excess costs, including the balance and
accrued interest by conveyance, see Note 4 to Financial Statements under Item 8, Financial Statements and
Supplementary Data.
Fourth Quarter 2018 and 2017
During fourth quarter 2018 the Trust received net profits income totaling $0 compared with fourth quarter
2017 net profits income of $1,081,207 primarily due to higher development costs ($5.6 million), lower gas prices
($0.5 million), decreased oil and gas production ($0.4 million),
increased production expenses ($0.1 million),
increased taxes, transportation and other costs ($0.1 million), partially offset by excess costs activity ($5.0 million)
and higher oil prices ($0.6 million).
After adding interest income of $6,697 and deducting administration expense of $230,245, and reducing the
cash reserve $223,548 for the payment of Trust expenses, distributable income for fourth quarter 2018 was $0 or
$0.000000 per unit. Distributable income for fourth quarter 2017 was $985,960 or $0.024649 per unit.
Distributions to unitholders for the quarter ended December 31, 2018 were:
Record Date
Payment Date
October 31, 2018
November 30, 2018
December 31, 2018
November 15, 2018
December 14, 2018
January 15, 2019
26
Per Unit
$0.000000
0.000000
0.000000
$0.000000
Volumes
Fourth quarter underlying gas sales volumes decreased 4% from 2017 to 2018 primarily due to natural
production decline. Underlying oil sales volumes decreased 6% from 2017 to 2018 primarily due to natural
production decline.
Prices
The average fourth quarter 2018 gas price was $2.68 per Mcf, or 7% lower than the fourth quarter 2017
average price of $2.88 per Mcf. The average fourth quarter 2018 oil price was $67.99 per Bbl, or 45% higher than
the fourth quarter 2017 average price of $47.05 per Bbl. For further information about product prices, see “Years
Ended December 31, 2018 and 2017 – Prices” above.
Costs
Taxes, transportation and other.
Taxes, transportation and other increased 4% from fourth quarter 2017 to
2018 primarily because of increased property taxes, production taxes on higher oil revenues and increased gas
deductions related to gathering fees, partially offset by decreased production taxes on lower gas revenues.
Production expense.
Fourth quarter production expense increased 4% from 2017 to 2018 primarily because
of increased repairs and maintenance.
Development costs. Development costs deducted are based on the current
level of development
expenditures, budgeted future development costs and the cumulative actual costs under (over) previous
deductions. The development costs increased 833% from fourth quarter 2017 to 2018, primarily due to the increase
in the development budget for the active drilling of four horizontal wells in Major County, Oklahoma, with
completions currently scheduled for early 2019. For further information on development costs, see Note 5 to
Financial Statements under Item 8, Financial Statements and Supplementary Data.
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 accrued interest, from future net proceeds of that conveyance and cannot reduce net profits
income from another 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
27
settlement of liabilities in the normal course of business. Increases in excess costs for the Kansas, Oklahoma and
Wyoming conveyances have resulted in no net proceeds to the Trust for the last nine months of 2018 and a
reduction in the Trust’s expense reserve. These conditions raise substantial doubt about the Trust’s ability to
continue as a going concern as the Trust may not have, based on the current estimated administrative expenses,
sufficient cash to meet its obligations during the one year period after the date the financial statements are
issued. Factors attributable to the potential cash shortage are primarily the previously disclosed increase in the
2018 development budget to include drilling costs of four horizontal wells in Major County, Oklahoma ($19.6 million
net to the Trust) which have created an excess cost position on the Oklahoma conveyance. Additionally, excess
cost positions on the Kansas and Wyoming conveyances have resulted in no net proceeds to the Trust for 2018.
The Trustee has prepared a preliminary budget estimating the administrative expenses for the next 12 months
which assumes no cash inflow from either net profits income or from other sources. This budget estimates that
the expense reserve will be depleted by approximately February 2020. If either income or expenses differ from the
assumptions in the Trustee’s preliminary budget, this date may be sooner or later than the estimate. Both the
Trustee and XTO Energy believe the Trust could obtain additional financing, including by borrowing under one or
more debt instruments, in an amount sufficient to pay its obligations for the next year. This outcome would ensure
that the Trust could continue as a going concern; however, there is no assurance that such additional financing
could be obtained. If the Trust obtains debt financing, any funds borrowed must be repaid in full, including
accrued interest, before distributions to unitholders could be made. Subsequent to December 31, 2018, the Trust
received net profits income from the Wyoming conveyance in an amount that covered all of the Trust’s
administrative expenses in March 2019 and allowed for a partial replenishment of the expense reserve. However,
the net profits income in March 2019 is not necessarily indicative of future cash inflows for the next 12 months.
The Trust’s consolidated financial statements do not include any adjustments that might result from the outcome
of this uncertainty.
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. 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. 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 in order to comply with climate change or GHG emissions legislation, which costs
could reduce 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.
Contractual Obligations
Not required for smaller reporting companies; the Trust has elected to omit this information.
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, 2018, the monthly overhead charge, based on the number of operated wells, was
28
approximately $938,000 ($750,400 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. 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 $5.8 million
for 2018, or 16% of total gas sales, $12.3 million for 2017, or 30% of total gas sales.
XTO Energy has advised the Trustee that, effective April 1, 2017, Cross Timbers Energy Services, Inc.
(“CTES”), a wholly owned marketing subsidiary of XTO Energy, has assigned all gas sales contracts for production
from the underlying properties to XTO Energy. XTO Energy will directly market and sell the gas to third parties. XTO
Energy has advised the Trustee that there are no changes to the terms of the contracts related to the assignment
and no impact on Trust distributions.
On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.
Critical Accounting Policies
The financial statements of the Trust are significantly affected by its basis of accounting and estimates
related to its oil and gas properties and proved reserves, as summarized below.
Basis of Accounting
The Trust’s financial statements are prepared on a modified cash basis, which is a comprehensive basis of
accounting other than U.S. GAAP. This method of accounting is consistent with reporting of taxable income to
Trust unitholders. The most significant differences between the Trust’s financial statements and those prepared in
accordance with U.S. GAAP are:
1.
2.
3.
Net profits income is recognized in the month received rather than accrued in the month of production.
Expenses are recognized when paid rather than when incurred.
Cash reserves may be established by the Trustee for certain contingencies that would not be recorded
under U.S. GAAP.
This comprehensive basis of accounting other than U.S. GAAP corresponds to the accounting permitted for
royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin
Topic 12:E, Financial Statements of Royalty Trusts. For further information regarding the Trust’s basis of
accounting, see Note 2 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
All amounts included in the Trust’s financial statements are based on cash amounts received or disbursed, or
on the carrying value of the net profits interests, which was derived from the historical cost of the interests at the
date of their transfer from XTO Energy, less accumulated amortization to date. Accordingly, there are no fair value
estimates included in the financial statements based on either exchange or non-exchange trade values.
Impairment of Net Profits Interest
The Trustee reviews the Trust’s net profits interests (“NPI”) in oil and gas properties for impairment
whenever events or circumstances indicate that the carrying value of the NPI may not be recoverable. In general,
29
the Trustee does not view temporarily low prices as an indication of impairment. The markets for crude oil and
natural gas have a history of significant price volatility and though prices will occasionally drop significantly,
industry prices over the long term will continue to be driven by market supply and demand. If events and
circumstances indicated that the carrying value may not be recoverable, the Trustee would use the estimated
undiscounted future net cash flows from the NPI to evaluate the recoverability of the Trust assets. If the
undiscounted future net cash flows from the NPI are less than the NPI carrying value, the Trust would recognize
an impairment loss for the difference between the NPI carrying value and the estimated fair value of the NPI. The
determination as to whether the NPI is impaired requires a significant amount of judgment by the Trustee and is
based on the best information available to the Trustee at the time of the evaluation. During the second half of 2018,
excess costs on properties attributable to the NPI have continued to accumulate, primarily due to the increase in
the development budget for the drilling of four horizontal wells in Major County, Oklahoma, which are currently
scheduled to be completed in early 2019. The Trustee has considered the accumulation of these excess costs as
part of its monitoring process and has concluded that there have been no events or changes in circumstances to
indicate the carrying value of the NPI may not be recoverable, and there was no impairment of the assets as of
December 31, 2018.
Oil and Gas Reserves
The proved oil and gas reserves for the underlying properties are estimated by independent petroleum
engineers. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the
estimated oil and gas reserves attributable to the net profits interests. Reserve engineering is a subjective
process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different
engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing
and production subsequent to the date of an estimate, as well as economic factors such as changes in product
prices, may justify revision of such estimates. Because proved reserves are required to be estimated using
12-month average prices, based on the first-day-of-the-month price for each month in the period, estimated
reserve quantities can be significantly impacted by changes in product prices. Accordingly, oil and gas quantities
ultimately recovered and the timing of production may be substantially different from original estimates.
The standardized measure of discounted future net cash flows and changes in such cash flows, as reported
in Note 9 to Financial Statements under Item 8, Financial Statements and Supplementary Data, is prepared using
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, reserve-to-production ratios,
future
production, development activities and associated operating expenses, future development plans by area,
increased density drilling, maintenance projects, development, production and other costs, oil and gas prices,
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
30
policy, 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 “expects,”
“intends,” “plans,” “projects,” “anticipates,” “predicts,” “believes,” “goals,” “estimates,” “should,” “could,”
“would,” and similar words that convey the uncertainty of future events. These statements are not guarantees of
future performance and involve certain risks, uncertainties and assumptions that are difficult to predict.
Therefore, actual
financial and operational results may differ materially from expectations, estimates or
assumptions expressed in, implied in, or forecasted in such forward-looking statements. Some of the risk factors
that could cause actual results to differ materially are explained in Item 1A, Risk Factors.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Not required for smaller reporting companies; the Trust has elected to omit this information.
31
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statements of Assets, Liabilities and Trust Corpus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statements of Distributable Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statements of Changes in Trust Corpus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
33
34
34
34
35
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.
32
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, 2018 and 2017, and the related statements of distributable income and of
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, 2018 and 2017, 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, increases in excess costs have led to a reduction in
net profits income available to the Trust. These factors have resulted in a decline to the expense reserve available
to the Trust for the payment of its obligations which 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 Trust’s management. Our responsibility is to express
an opinion on the Trust’s financial statements based on our audits. We are a public accounting firm registered
with the Public Company Accounting Oversight Board (United States)
(PCAOB) and are required to be
independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules
and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these financial statements in accordance with the standards of the PCAOB.
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to
have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our
audits we are required to obtain an understanding of internal control over financial reporting but not for the
purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting.
Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, 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.
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
March 29, 2019
We have served as the Trust’s auditor since 2011.
33
HUGOTON ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
December 31
2018
2017
Assets
Cash and short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net profits interests in oil and gas properties – net
$ 1,128,157
$ 1,433,640
(Notes 1 and 2)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15,816,990
16,379,749
$16,945,147
$17,813,389
Liabilities and Trust Corpus
Distribution payable to unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expense reserve(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trust corpus (40,000,000 units of beneficial interest authorized and
$
— $
1,128,157
433,640
1,000,000
outstanding)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15,816,990
16,379,749
$16,945,147
$17,813,389
(a) The expense reserve allows the Trustee to pay its obligations should it be unable to pay them out of the net
profits income.
STATEMENTS OF DISTRIBUTABLE INCOME
Year Ended December 31
2018
2017
Net profits income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,590,949
23,152
$5,317,931
7,028
Total income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Administration expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash reserves withheld (used) for Trust expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,614,101
1,115,904
128,157
5,324,959
804,719
—
Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 370,040
$4,520,240
Distributable income per unit (40,000,000 units) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 0.009251
$ 0.113006
STATEMENTS OF CHANGES IN TRUST CORPUS
Year Ended December 31
2018
2017
Trust corpus, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of net profits interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions declared . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$16,379,749
(562,759)
370,040
(370,040)
$ 26,885,503
(10,505,754)
4,520,240
(4,520,240)
Trust corpus, end of year
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$15,816,990
$ 16,379,749
See accompanying notes to financial statements.
34
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”). 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).
35
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
The most significant differences between the Trust’s financial statements and those prepared in accordance
with U.S. GAAP are:
1.
2.
3.
Net profits income is recognized in the month received rather than accrued in the month of production.
Expenses are recognized when paid rather than when incurred.
Cash reserves may be established by the Trustee for certain contingencies that would not be recorded
under U.S. GAAP.
This comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the
U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial
Statements of Royalty Trusts.
Most accounting pronouncements apply to entities whose financial statements are prepared in accordance
with U.S. GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when
such revenues were received or expenses were paid. Because the Trust’s financial statements are prepared on
the modified cash basis, as described above, most accounting pronouncements are not applicable to the Trust’s
financial statements.
Impairment of Net Profits Interest
The Trustee reviews the Trust’s net profits interests (“NPI”) in oil and gas properties for impairment
whenever events or circumstances indicate that the carrying value of the NPI may not be recoverable. In general,
the Trustee does not view temporarily low prices as an indication of impairment. The markets for crude oil and
natural gas have a history of significant price volatility and though prices will occasionally drop significantly,
industry prices over the long term will continue to be driven by market supply and demand. If events and
circumstances indicated that the carrying value may not be recoverable, the Trustee would use the estimated
undiscounted future net cash flows from the NPI to evaluate the recoverability of the Trust assets. If the
undiscounted future net cash flows from the NPI are less than the NPI carrying value, the Trust would recognize
an impairment loss for the difference between the NPI carrying value and the estimated fair value of the NPI. The
determination as to whether the NPI is impaired requires a significant amount of judgment by the Trustee and is
based on the best information available to the Trustee at the time of the evaluation. During the second half of 2018,
excess costs on properties attributable to the NPI have continued to accumulate, primarily due to the increase in
the development budget for the drilling of four horizontal wells in Major County, Oklahoma, which are currently
scheduled to be completed in early 2019. The Trustee has considered the accumulation of these excess costs as
part of its monitoring process and has concluded that there have been no events or changes in circumstances to
indicate the carrying value of the NPI may not be recoverable, and there was no impairment of the assets as of
December 31, 2018.
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. Increases in excess costs for the Kansas, Oklahoma and
Wyoming conveyances have resulted in no net proceeds to the Trust for the last nine months of 2018 and a
reduction in the Trust’s expense reserve. These conditions raise substantial doubt about the Trust’s ability to
continue as a going concern as the Trust may not have, based on the current estimated administrative expenses,
sufficient cash to meet its obligations during the one year period after the date the financial statements are
36
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
issued. Factors attributable to the potential cash shortage are primarily the previously disclosed increase in the
2018 development budget to include drilling costs of four horizontal wells in Major County, Oklahoma ($19.6 million
net to the Trust) which have created an excess cost position on the Oklahoma conveyance. Additionally, excess
cost positions on the Kansas and Wyoming conveyances have resulted in no net proceeds to the Trust for 2018.
The Trustee has prepared a preliminary budget estimating the administrative expenses for the next 12 months
which assumes no cash inflow from either net profits income or from other sources. This budget estimates that
the expense reserve will be depleted by approximately February 2020. If either income or expenses differ from the
assumptions in the Trustee’s preliminary budget, this date may be sooner or later than the estimate. Both the
Trustee and XTO Energy believe the Trust could obtain additional financing, including by borrowing under one or
more debt instruments, in an amount sufficient to pay its obligations for the next year. This outcome would ensure
that the Trust could continue as a going concern; however, there is no assurance that such additional financing
could be obtained. If the Trust obtains debt financing, any funds borrowed must be repaid in full, including
accrued interest, before distributions to unitholders could be made. Subsequent to December 31, 2018, the Trust
received net profits income from the Wyoming conveyance in an amount that covered all of the Trust’s
administrative expenses in March 2019 and allowed for a partial replenishment of the expense reserve. However,
the net profits income in March 2019 is not necessarily indicative of future cash inflows for the next 12 months.
The Trust’s consolidated financial statements do not include any adjustments that might result from the outcome
of this uncertainty.
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. Amortization of the net profits interests is calculated on a
unit-of-production basis and charged directly to Trust corpus. Accumulated amortization was $173,943,434 as of
December 31, 2018 and $173,380,675 as of December 31, 2017.
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, transportation, legal and marketing
charges, production expense, development and drilling costs, and overhead.
XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the
three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming). If costs exceed revenues for
any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that
conveyance and cannot reduce net profits income from the other conveyances (Note 4).
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.
37
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:
KS
OK
WY
Total
Underlying
Cumulative excess costs remaining at
12/31/17 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 771,556
$
— $
— $
771,556
Net excess costs (recovery) for the quarter
ended 3/31/18 . . . . . . . . . . . . . . . . . . . . . . . . .
72,191
—
32,365
104,556
Net excess costs (recovery) for the quarter
ended 6/30/18 . . . . . . . . . . . . . . . . . . . . . . . . .
20,283
4,665,654
486,350
5,172,287
Net excess costs (recovery) for the quarter
ended 9/30/18 . . . . . . . . . . . . . . . . . . . . . . . . .
90,361
5,145,818
481,526
5,717,705
Net excess costs (recovery) for the quarter
ended 12/31/18 . . . . . . . . . . . . . . . . . . . . . . . . .
(57,813)
5,764,759
336,215
6,043,161
Cumulative excess costs remaining at
12/31/18 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . .
Accrued interest at 12/31/18(a)
896,578
161,314
15,576,231
—
1,336,456
25,158
17,809,265
186,472
Total remaining to be recovered at 12/31/18 . . .
$1,057,892
$15,576,231
$1,361,614
$17,995,737
KS
OK
WY
Total
NPI
Cumulative excess costs remaining at
12/31/17 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 617,246
$
— $
— $
617,246
Net excess costs (recovery) for the quarter
ended 3/31/18 . . . . . . . . . . . . . . . . . . . . . . . . .
57,752
—
25,892
83,644
Net excess costs (recovery) for the quarter
ended 6/30/18 . . . . . . . . . . . . . . . . . . . . . . . . .
16,226
3,732,523
389,080
4,137,829
Net excess costs (recovery) for the quarter
ended 9/30/18 . . . . . . . . . . . . . . . . . . . . . . . . .
72,289
4,116,655
385,221
4,574,165
Net excess costs (recovery) for the quarter
ended 12/31/18 . . . . . . . . . . . . . . . . . . . . . . . . .
(46,250)
4,611,807
268,972
4,834,529
Cumulative excess costs remaining at
12/31/18 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . .
Accrued interest at 12/31/18(a)
717,263
129,051
12,460,985
—
1,069,165
20,126
14,247,413
149,177
Total remaining to be recovered at 12/31/18 . . .
$ 846,314
$12,460,985
$1,089,291
$14,396,590
(a) XTO has advised the Trustee that it has determined not to accrue interest on the OK excess costs balance at
this time.
For the quarter ended December 31, 2018, higher revenues in relation to costs resulted in the net recovery of
excess costs on properties underlying the Kansas net profits interests. Increased budgeted development costs
caused costs to exceed revenues on properties underlying the Oklahoma net profits interests. Lower gas prices
and increased budgeted development costs caused costs to exceed revenues on properties underlying the
Wyoming net profits interests.
Underlying cumulative excess costs for the Kansas, Oklahoma and Wyoming conveyances remaining as of
December 31, 2018 totaled $18.0 million ($14.4 million NPI), including accrued interest of $0.2 million ($0.1 million
NPI).
38
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
5. Development Costs
The following summarizes actual development costs, budgeted development costs deducted in the
calculation of net profits income, and the cumulative actual costs compared to the amount deducted:
Cumulative actual costs under (over) the amount deducted
– beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actual costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Budgeted costs deducted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
537,144
(8,426,453)
21,802,500
$
56,243
(2,319,099)
2,800,000
Cumulative actual costs under (over) the amount deducted
– end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$13,913,191
$
537,144
Year Ended December 31
2017
2018
The monthly deduction is based on the current
level of development expenditures, budgeted future
development costs and the cumulative actual costs under (over) previous deductions. Changes in oil or natural
gas prices could impact future development plans on the underlying properties. XTO Energy has advised the
Trustee that this monthly deduction will continue to be evaluated and revised as necessary.
The monthly development cost deduction was $200,000 from the October 2016 distribution through the July
2017 distribution. Due to increased non-operated development activity on properties underlying the Oklahoma net
profits interests, the monthly development deduction was increased to $280,000 beginning with the August 2017
distribution through the March 2018 distribution. Due to increased operated development activity on properties
underlying the Oklahoma net profits interests, the monthly development deduction was increased to $2,188,000
beginning with the April 2018 distribution through the October 2018 distribution, and increased to $2,825,000
beginning with the November 2018 distribution through the end of 2018.
For further information on 2019 budgeted development costs, see Properties, under Item 2.
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. Impairment 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 2018 tax year because the Trust had no revenues, income or deductions in 2018 attributable to
properties located in Kansas. The Trust did not file a return with Kansas for the 2017 tax year for the same reason.
Wyoming does not impose a state income tax.
39
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
The Trust could potentially be required to bear a portion of the legal settlement costs arising from
the Chieftain settlement. For information on contingencies, see Note 8 to Financial Statements. In the event that
the Trust is determined to be responsible for such costs, XTO will 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 legal
settlement costs will be reflected through a reduction in net profits income received from the Trust and thus in a
reduction in the gross royalty income reported by and taxable to the unitholders. In the event that the Trustee
objects to such claimed reductions, the Trustee may also incur legal fees in representing the Trust’s interests. For
unitholders, such costs would be reflected through an increase in the Trust’s administrative expenses, which
would be deductible by unitholders in determining the net royalty income from the Trust.
Each unitholder should consult his or her own tax advisor regarding income tax requirements,
if any,
applicable to such person’s ownership of Trust units.
7. XTO Energy Inc.
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, 2018, the monthly overhead charge, based on the number of operated wells, was
approximately $938,000 ($750,400 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 $5.8 million
for 2018, or 16% of total gas sales, $12.3 million for 2017, or 30% of total gas sales.
XTO Energy has advised the Trustee that, effective April 1, 2017, Cross Timbers Energy Services, Inc.
(“CTES”), a wholly owned marketing subsidiary of XTO Energy, has assigned all gas sales contracts for production
from the underlying properties to XTO Energy. XTO Energy will directly market and sell the gas to third parties. XTO
Energy has advised the Trustee that there are no changes to the terms of the contracts related to the assignment
and no impact on Trust distributions.
On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.
8. Contingencies
Litigation
Royalty Class Action and Arbitration
In December 2010, a royalty class action lawsuit was filed against XTO Energy styled Chieftain Royalty
Company v. XTO Energy Inc.
in Coal County District Court, Oklahoma. The plaintiffs allege that XTO Energy
wrongfully deducted fees from royalty payments on Oklahoma wells, failed to make diligent efforts to secure the
best terms available for the sale of gas and its constituents, and demand an accounting to determine whether they
have been fully and fairly paid gas royalty interests.
40
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
The case was settled in December 2017, and approved by the court in July 2018. The settlement was
$80 million and up to an additional $750 thousand for costs to administer the settlement. Based on the final plan of
allocation approved by the court, XTO Energy advised the Trustee that it believes approximately $24.3 million in
additional production costs should be allocated to the Trust. Based on preliminary information provided to the
Trustee by XTO Energy, on May 2, 2018, the Trustee submitted a demand for arbitration styled Simmons Bank
(successor to Southwest Bank and Bank of America, N.A.) vs. XTO Energy Inc. (the “Arbitration”) through the
American Arbitration Association 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. Additionally,
in the Arbitration, the Trustee also made claims for disputed amounts on the computation of the Trust’s net
proceeds for 2014 through 2016 in excess of $5 million. XTO Energy filed its answer denying the Trustee’s claims.
The Arbitration panel has been selected. The hearing on the claims related to the Chieftain settlement has been
scheduled for October 7, 2019. The remaining claims related to the computation of the Trust’s net proceeds were
bifurcated and will be heard at a later date, which is still to be determined.
If the approximately $24.3 million allocated portion of the Chieftain settlement results in an adjustment to the
Trust’s share of net proceeds, it would result in additional excess costs under the Oklahoma conveyance that
would likely result in no distributions under the Oklahoma conveyance for several years, or more depending on the
results of operations of the underlying properties, while these additional excess costs are recovered.
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 it does not believe that the
ultimate resolution of these claims will have a material effect on the financial position or liquidity of the Trust, but
may have an effect on annual distributable income.
Other
Several states have enacted legislation requiring state income tax withholding from payments made to
nonresident recipients of oil and gas proceeds. After consultation with its tax counsel, the Trustee believes that it
is not required to withhold on payments made to the unitholders. However, regulations are subject to change by
the various states, which could change this conclusion. Should amounts be withheld on payments made to the
Trust or the unitholders, distributions to the unitholders would be reduced by the required amount, subject to the
filing of a claim for refund by the Trust or unitholders for such amount.
9. Supplemental Oil and Gas Reserve Information (Unaudited)
Oil and Natural Gas Reserves
Proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are
those quantities of oil and natural gas, which, by analysis of geoscience and engineering data can be estimated
with reasonable certainty to be economically producible from a given date forward, from known reservoirs and
under existing economic conditions, operating methods, and government regulation before the time at which
contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
Proved developed reserves are the quantities expected to be recovered through existing wells with existing
equipment and operating methods in which the cost of the required equipment is relatively minor compared with
the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates
are subject to change as additional information becomes available. The reserves actually recovered and the
41
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
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 management’s estimate of future cash flows or the value of
proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are
excluded from the calculations. Furthermore, prices used to determine the standardized measure are influenced
by supply and demand as affected by recent economic conditions as well as other factors and may not be the
most representative in estimating future revenues or reserve data.
Estimated costs to plug and abandon wells on the underlying working interest properties at the end of their
productive lives have not been deducted from cash flows since this is not a legal obligation of the Trust. These
costs are the legal obligation of XTO Energy as the owner of the underlying working interests and will only be
deducted from net proceeds payable to the Trust if net proceeds from the related conveyance exceed such costs
when paid, subject to excess cost carryforward provisions (Notes 3 and 4).
The average realized gas prices used to determine the standardized measure were $2.36 per Mcf in 2018,
$2.40 per Mcf in 2017, $1.94 per Mcf in 2016 and $2.10 per Mcf in 2015. Oil prices used to determine the
standardized measure were based on average realized oil prices of $63.30 per Bbl in 2018, $47.91 per Bbl in 2017,
$39.08 per Bbl in 2016 and $46.56 per Bbl in 2015.
Reserve quantities and revenues for the net profits interests were estimated from projections of reserves
and revenues attributable to the underlying properties. Since the Trust has defined net profits interests, the Trust
does not own a specific percentage of the oil and gas reserves. Oil and gas reserves are allocated to the net
profits interests by dividing Trust net cash inflows by 12-month average oil and gas prices. Any fluctuations in
12-month average prices or estimated costs will result in revisions to the estimated reserve quantities allocated to
the net profits interests, which may not correlate with revisions of underlying proved reserves.
42
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Proved Reserves
(in thousands)
Underlying Properties
Oil (Bbls)
Gas (Mcf)
Net Profits Interests
Oil (Bbls)
Gas (Mcf)
Balance, December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance, December 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance, December 31, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
103,962
—
3,361
(14,855)
—
92,468
5
39,851
(13,903)
—
118,421
9,388
6,375
(12,994)
—
Balance, December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
121,190
1,186
—
90
(179)
—
1,097
33
345
(156)
—
1,319
674
167
(155)
—
2,005
14,487
—
(9,224)
(1,096)
—
4,167
3
10,496
(1,628)
—
13,038
2,513
(2,313)
(448)
—
12,790
179
—
(95)
(18)
—
66
17
109
(27)
—
165
180
106
(8)
—
443
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
Oil (Bbls)
Gas (Mcf)
December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
102,683
December 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
91,734
December 31, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
117,667
December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
111,234
1,178
1,097
1,319
1,339
14,411
4,167
12,844
7,979
178
66
165
121
43
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
Underlying Properties
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future costs:
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31
2017
2016
2018
$413,046
$347,055
$222,625
338,719
6,687
67,640
29,776
301,930
795
44,330
13,125
209,820
795
12,010
2,474
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 37,864
$ 31,205
$
9,536
Net Profits Interests
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future production taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 58,139
4,027
$ 38,655
3,192
$ 10,353
745
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
54,112
23,821
35,463
10,499
9,608
1,980
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 30,291
$ 24,964
$
7,628
Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
2018
2017
2016
Underlying Properties
Standardized measure, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 31,205
$ 9,536
$ 29,605
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11,684
14,205
2,731
(27,592)
687
1,715
6,932
(23,791)
21,803
—
25,717
4,667
784
(2,667)
(586)
27,915
401
(9,447)
2,800
—
(18,980)
988
2,569
(738)
(636)
(16,797)
—
(4,947)
1,675
—
Net change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,659
21,669
(20,069)
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 37,864
$31,205
$ 9,536
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 24,964
5,545
2,185
(812)
—
(1,591)
$ 7,628
321
628
21,705
—
(5,318)
$ 23,683
—
2,055
(15,492)
—
(2,618)
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 30,291
$24,964
$ 7,628
44
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
10. Quarterly Financial Data (Unaudited)
The following is a summary of net profits income, distributable income and distributable income per unit by
quarter for 2018 and 2017:
Net Profits
Income
Distributable
Income
Distributable
Income
per Unit
2018
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,590,949
—
—
—
$ 370,040
—
—
—
$0.009251
0.000000
0.000000
0.000000
$1,590,949
$ 370,040
$0.009251
2017
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,223,626
1,324,846
688,252
1,081,207
$1,886,680
1,150,280
497,320
985,960
$0.047167
0.028757
0.012433
0.024649
$5,317,931
$4,520,240
$0.113006
45
11. Subsequent Events
None.
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, 2018.
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, 2018 that have materially affected, or are reasonably likely to materially affect, the Trust’s internal
control over financial reporting.
Item 9B. Other Information
None.
46
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, 2018.
(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 and Southwest Bank, the prior trustee, received the following
annual compensation for the fiscal years ended December 31, 2017 through December 31, 2018 as specified
in the Trust indenture:
Simmons, Trustee (1)
Southwest Bank, Trustee (1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
$52,261
17,318
$ —
67,926
2018
2017
(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 pay ratio disclosure is not applicable.
The Trust does not have a principal executive officer or employees and therefore,
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
(a) Equity Compensation Plans and Trust Repurchases.
Trust has not repurchased any units during the fourth quarter of fiscal 2018.
The Trust has no equity compensation plans. The
(b) Security Ownership of Certain Beneficial Owners. The Trustee is not aware of any person who
beneficially owns more than 5% of the outstanding 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.
47
Item 13. Certain Relationships and Related Transactions, and Director Independence
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. This
charge at December 31, 2018 was approximately $938,000 per month, or $11,256,000 annually (net to the Trust of
$750,400 per month or $9,004,800 annually), and is subject to annual adjustment based on an oil and gas industry
index as defined in the Trust agreement.
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.
See Item 11, Executive Compensation, for the remuneration received by the Trustee for the fiscal years
ended December 31, 2017 through December 31, 2018.
As noted in Item 10, Directors, Executive Officers and Corporate Governance, the Trust has no directors,
executive officers, audit committee, audit committee financial expert, compensation committee or nominating
committee. The Trustee is a corporate trustee which may be removed, with or without cause, by the affirmative
vote of the holders of a majority of all the units then outstanding.
Item 14. Principal Accountant Fees and Services
Fees for services performed by PricewaterhouseCoopers LLP for the years ended December 31, 2018
and 2017 are:
Audit fees-PwC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Audit-related fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All other fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$157,000
—
—
—
$158,000
—
—
—
2018
2017
$157,000
$158,000
As referenced in Item 10, Directors, Executive Officers and Corporate Governance, above, the Trust has no
audit committee, and as a result, has no audit committee pre-approval policy with respect to fees paid to
PricewaterhouseCoopers LLP.
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, 2018 and 2017
Statements of Distributable Income for the years ended December 31, 2018 and 2017
Statements of Changes in Trust Corpus for the years ended December 31, 2018 and 2017
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 29, 2019
50
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 web site at www.hgt-hugoton.com.
Hugoton Royalty Trust
Simmons Bank, Trustee
2911 Turtle Creek Blvd, Ste 850
Dallas, TX 75219
Attention: Annual Reports
1-855-588-7839
Web site
www.hgt-hugoton.com
Auditors
PricewaterhouseCoopers LLP
Dallas, Texas
Legal and Tax Counsel
Thompson & 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, 2018.
Hugoton Royalty Trust
Simmons Bank
2911 Turtle Creek Blvd, Ste 850
Dallas, TX 75219
1-855-588-7839
www.hgt-hugoton.com