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UNITED STATES SECURITIES AND EXCHANGE
COMMISSION Washington, D.C. 20549 Form 10-K  ☑
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the
fiscal year ended December 31, 2017 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

58-6379215(State or other jurisdiction of
incorporation or organization)

(I.R.S. Employer Identification No.)c/o Corporate Trustee:
Simmons Bank
P.O. Box 962020
Fort Worth, Texas
(Address of principal executive offices)

76162-2020
(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:  Title of each class

Name of each exchange on which
registeredunits of Beneficial Interest

New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is
a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    
Yes  ☐    No  ☑ 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  ☑ 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  ☑    No  ☐ Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File
required to be submitted and posted 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 and post 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.☑ 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. (Check one):  Large accelerated filer  ☐

Accelerated filer  ☑

Non-accelerated filer  ☐

Smaller reporting company  ☐

Emerging Growth Company  ☐(Do not check if a smaller reporting 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  ☑ The
aggregate market value of units of beneficial interest held by non-affiliates of the registrant at June 30, 2017 (the last business day of the registrants most recently completed second fiscal quarter) was approximately $72.0 million. The number of units of beneficial interest outstanding as of February 15, 2018 was 40,000,000.




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HUGOTON ROYALTY TRUST 2017 ANNUAL REPORT ON FORM 10-K TABLE OF CONTENTS  PageGlossary of Terms


1Part IItem 1.

Business


2Item 1A.

Risk Factors


3Item 1B.

Unresolved Staff Comments


8Item 2.

Properties


9Item 3.

Legal Proceedings


19Item 4.

Mine Safety Disclosures


20Part IIItem 5.

Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units


21Item 6.

Selected Financial Data


21Item 7.

Trustees Discussion and Analysis of Financial Condition and Results of Operations


22Item 7A.

Quantitative and Qualitative Disclosures about Market Risk


29Item 8.

Financial Statements and Supplementary Data


30Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure


46Item 9A.

Controls and Procedures


46Item 9B.

Other Information


46Part IIIItem 10.

Directors, Executive Officers and Corporate Governance


47Item 11.

Executive Compensation


47Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related
 Unitholder Matters


47Item 13.

Certain Relationships and Related Transactions, and Director Independence


48Item 14.

Principal Accountant Fees and Services


48Part IVItem 15.

Exhibits and Financial Statement Schedules


49




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HUGOTON ROYALTY TRUST GLOSSARY OF TERMS The following are definitions of significant terms used in this Annual Report on Form 10-K:  Bbl
Barrel (of oil)  Bcf
Billion cubic feet (of natural gas)  BOE
Barrel of oil equivalent  Mcf
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.  1




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PART I Item 1.Business 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. The principal office of the Trust is P.O. Box 962020, Fort Worth, TX 76162-2020. (telephone
number 855-588-7839). 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 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. Units are listed and traded on the New York Stock Exchange under the symbol HGT. 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. On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation. The net profits interests entitle the Trust to receive 80% of the net proceeds from the sale of oil and gas from the underlying properties. Each month
XTO Energy determines the amount of cash received from the sale of production and deducts property and production taxes, production expense, development costs and overhead. Net proceeds payable to the Trust depend upon production quantities, sales prices of oil and gas and costs to develop and produce oil and gas in the
prior month. If monthly costs exceed revenues for any of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and
cannot reduce net proceeds from other conveyances. For further information on excess costs, see Note 4 to Financial Statements under Item 8, Financial Statements and Supplementary Data. The Trust is not liable for any production costs or liabilities attributable to the underlying properties. If at any time the Trust receives net profits
income in excess of the amount due, the Trust is not obligated to return such overpayment, but future net profits income payable to the Trust will be reduced until the overpayment, plus interest at the prime rate, is recovered. As a working interest owner, XTO Energy can generally decline participation in any operation and allow consenting parties to conduct such operations, as
provided under the operating agreements. XTO Energy also can assign, sell, or otherwise transfer its interest in the underlying properties, subject to the net profits interests, or can abandon an underlying property if it is incapable of producing
in paying quantities, as determined by XTO Energy.  2




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To the extent allowed, XTO Energy is responsible for marketing its production from the underlying
properties under existing sales contracts, or new arrangements on the best terms reasonably obtainable in the circumstances. See Pricing and Sales Information under Item 2, Properties. 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 78% of the net profits income received by the Trust during 2017 was attributable to natural gas, as well as 79% of the Trusts
estimated future net cash flows from proved reserves at December 31, 2017 (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. 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.  3




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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 transportation and price controls, can affect product prices. A significant decline in 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 2016 and 2017 and with respect to the properties underlying the
Wyoming net profits interests for all of 2016 and the first three quarters of 2017), 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 $30 million and $35 million for 2018 which could 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 of up to $20 million relates to the Trust. Although the Trustee has indicated it intends to review any claimed reductions in payment to the
Trust based on the facts and circumstances of the settlement, if $20 million of the Chieftain settlement is required to be borne by the Trust, it would result in excess costs under the Oklahoma conveyance that, based on recent distribution
levels under such conveyance, would likely result in no distributions under the Oklahoma conveyance for several years; however, changes in oil or natural gas prices or expenses could cause the time period to increase or decrease correspondingly. See
Item 8  Financial Statements and Supplementary Data  Notes to Financial Statements  Note 8  Contingencies for additional information.  4




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Proved reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material
inaccuracies in reserve estimates or underlying assumptions could cause the quantities and net present value of the reserves to be overstated. Estimating proved oil and gas reserves is inherently uncertain. Petroleum engineers consider many factors and make assumptions in estimating reserves and
future net cash flows. Those factors and assumptions include historical production from the area compared with production rates from similar producing areas, the effects of governmental regulation, assumptions about future commodity prices,
production expense and development costs, taxes and capital expenditures, the availability of enhanced recovery techniques and relationships with landowners, working interest partners, pipeline companies and others. Lower oil and gas prices
generally cause lower estimates of proved reserves. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variances could be material. Because the Trust owns net profits interests,
it does not own a specific percentage of the oil and gas reserves. Estimated proved reserves for the net profits interests are based on estimates of reserves for the underlying properties and an allocation method that considers estimated future net
proceeds and oil and gas prices. Because Trust reserve quantities are determined using an allocation formula, increases or decreases in oil and gas prices can significantly affect estimated reserves of the net profits interests. Operational risks and hazards associated with the development and operations of the underlying properties may decrease Trust distributions. There are operational risks and hazards associated with the production and transportation of oil and natural gas, including without limitation natural
disasters, blowouts, explosions, fires, leakage of oil or natural gas, releases of other hazardous materials, mechanical failures, cratering, and pollution. Any of these or similar occurrences could result in the interruption or cessation of
operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the environment or natural resources, or cleanup obligations. The operation of oil and gas properties is also subject to various
laws and regulations. Non-compliance with such laws and regulations could subject the operator to additional costs, sanctions or liabilities. The uninsured costs resulting from any of the above or similar occurrences could be deducted as a
production expense or development cost in calculating the net proceeds payable to the Trust, and would therefore reduce Trust distributions by the amount of such uninsured costs. Future net profits may be subject to risks relating to the creditworthiness of third parties. The Trust does not lend money and has limited ability to borrow money, which the Trustee believes limits the Trusts risk from exposure to credit
markets. The Trusts future net profits, however, may be subject to risks relating to the creditworthiness of the operators of the underlying properties and other purchasers of crude oil and natural gas produced from the underlying properties.
This creditworthiness may be impacted by the price of crude oil and natural gas. Trust unitholders and the Trustee have no influence over the operations on,
or future development of, the underlying properties. Neither the Trustee nor the Trust unitholders can influence or control the operation or
future development of the underlying properties. The failure of an operator to conduct its operations or discharge its obligations in a proper manner could have an adverse effect on the net proceeds payable to the Trust. Although XTO Energy and
other operators of the underlying properties must adhere to the standard of a prudent operator, they are under no obligation to continue operating the properties. Neither the Trustee nor Trust unitholders have the right to replace an operator. The assets of the Trust represent interests in depleting assets and, if XTO Energy or any other operators developing the underlying properties do not perform
additional successful development projects, the assets may deplete faster than expected. Eventually, the assets of the Trust will cease to produce in commercial quantities and the Trust will cease to receive proceeds from such assets. The net proceeds payable to the Trust are derived from the sale of hydrocarbons from depleting assets. Future
maintenance and development projects on the underlying properties will affect the quantity of proved reserves and can  5




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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. 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 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. 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.  6




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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. The limited liability of Trust unitholders is uncertain. The Trust unitholders are not protected from the liabilities of the Trust to the same extent that a shareholder would be protected from a
corporations liabilities. The structure of the Trust does not include the interposition of a limited liability entity such as a corporation or limited partnership which would provide further limited liability protection to Trust unitholders.
While the Trustee is liable for any excess liabilities incurred if the Trustee fails to ensure that such liabilities are to be satisfied only out of Trust assets, under the laws of Texas, which are unsettled on this point, a unitholder may be
jointly and severally liable for any liability of the Trust if the satisfaction of such liability was not contractually limited to the assets of the Trust and the assets of the Trust and the Trustee are not adequate to satisfy such liability. As a
result, Trust unitholders may be exposed to personal liability. The Trust, however, is not liable for production costs or other liabilities of the underlying properties. Drilling oil and natural gas wells is a high-risk activity and subjects the Trust to a variety of factors that it cannot control. Drilling oil and natural gas wells involves numerous risks, including the risk that commercially productive oil and natural gas reservoirs are not
encountered. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause drilling activities to be unsuccessful. In addition, there is often uncertainty as to the future cost or timing of drilling,
completing and operating wells. Further, development activities may be curtailed, delayed or canceled as a result of a variety of factors, including:  1.
reduced oil or natural gas prices; 2.
unexpected drilling conditions; 3.
title problems; 4.
restricted access to land for drilling or laying pipeline; 5.
pressure or irregularities in formations; 6.
equipment failures or accidents; 7.
adverse weather conditions or natural disasters; and 8.
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.  7




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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 Regulation on pp. 15-19 and Greenhouse Gas Emissions and Climate Change Regulations on p. 26. 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. If the Trust
fails to regain and maintain compliance with the continued listing standards of the NYSE, it may result in the delisting of the Trusts units from the NYSE. The Trust units are currently and have been listed for trading on the NYSE, and the continued listing of the Trust units on the NYSE is subject to the
Trusts compliance with a number of listing standards. To maintain compliance with these continued listing standards, the Trust is required, among other things, to maintain an average closing price per unit of $1.00 or more over a successive 30
trading-day period. On February 26, 2018, the Trustee received written notification from the NYSE that the average closing price of the Trust units had fallen below $1.00 per unit over a successive 30 trading-day period as of February 22,
2018, and, as a result, the average closing price per unit of the units was below the minimum average closing price required to maintain listing on the NYSE. The Trust can regain compliance if at any time in the six-month period following receipt of the notice, the closing price of its units on the last
trading day of any month is as least $1.00 and the 30 trading-day average closing price of its units on such day is also at least $1.00. Even if the Trust does regain compliance, it might be unable to maintain compliance, and would again become
subject to the NYSE delisting procedures. In addition, the Trust units could be delisted if the trading price of the Trust units on the NYSE is
abnormally low, which has generally been interpreted to mean at levels below $0.16 per unit. In this event, the Trust would not have an opportunity to cure the deficiency, and the Trust units would be delisted immediately and suspended from trading
on the NYSE. The commencement of delisting procedures by the NYSE remains, at all times, at the discretion of the NYSE. If the Trust is unable
to cure any event of noncompliance with any continued listing standard of the NYSE within the applicable timeframe and any other parameters set by the NYSE, or if the Trust fails to maintain compliance with certain continued listing standards that
do not provide for a cure period, it will result in the delisting of the Trust units from the NYSE, which could negatively impact the trading volume and liquidity of the Trust units. Additionally, delisting from the NYSE may decrease the
attractiveness of the Trust units to investors, which could result in a further decline in the market price of the Trust units. Item 1B.Unresolved Staff Comments As of December 31, 2017, the Trust did not have any unresolved Securities and Exchange Commission staff comments.  8




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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, 2017 is approximately 10 years. This index
is calculated using total proved reserves and estimated 2018 production for the underlying properties. The projected 2018 production is from proved developed producing reserves as of December 31, 2017. 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 79% natural gas and 21% 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 2017 development costs deducted for the underlying properties were $2.8 million, an increase of 67% from the prior year. XTO Energy has informed the Trustee that total 2018 budgeted
development costs for the underlying properties are between $30 million and $35 million, primarily due to the projected drilling of four horizontal wells in Major County, Oklahoma during the second half of 2018. Changes in oil or natural gas prices
could impact future development plans on the underlying properties. Increased development costs will be deducted beginning with the April 2018 distribution. 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. 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 2017, daily sales volumes from the underlying properties
in the Hugoton area averaged approximately 10,500 Mcf of gas and 31 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 5 workovers in 2017. XTO Energy
has informed the Trustee that it does not plan to drill any new wells but may perform up to 5 workovers during 2018.  9




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XTO Energys future development plans for the underlying properties in the Hugoton area include:  1.
additional compression to lower line pressures; 2.
installing artificial lift; 3.
opening new producing zones in existing wells; 4.
restimulating producing intervals in existing wells utilizing new technology; 5.
deepening existing wells to new producing zones; and 6.
future drilling of additional wells. Prior to May 1, 2014, XTO Energy delivered most of its
Hugoton gas production to a gathering and processing system owned by a subsidiary, Timberland Gathering & Processing Company, Inc. (Timberland). Most of the gas was sold under the terms of a contract that was entered into in
March 1996, predating the existence of the Trust. Timberland purchased the gas from XTO Energy at the wellhead, gathered and transported the gas to its plant, and treated and processed the gas at the plant. Timberland had been taking all of the gas
produced for over ten years. Timberland paid XTO Energy for wellhead volumes at a price of 80% to 85% of the net residue price received by XTO Energys marketing affiliate, which amount was adjusted for the BTU content of the gas. This
marketing affiliate sold the residue to a pipeline at a price based on a monthly pipeline index less actual third party fees. XTO Energy advised
the Trustee that Timberland permanently shut down the processing portion of its facilities as of May 1, 2014 due to reliability issues. XTO Energy then advised the Trustee that Timberland believed that investments and repairs were not
economically feasible; however, Timberland continued to gather and compress gas from the Hugoton area. 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 9,500 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
and a helium processing fee of $0.05 per Delivery Point MMBtu 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, 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. 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 16,400 Mcf of gas and 380 Bbls of oil in 2017. 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  10




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##### Table of Contents

Arbuckle formations. Within this area, XTO Energy did not drill any wells but did perform 18 workovers in 2017. XTO Energy has informed the Trustee that it plans to drill four new horizontal
wells in the second half of 2018 and may perform up to 20 workovers in Major County during 2018. 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 2 workovers in 2017. XTO Energy has informed the Trustee that it does not plan to drill any new wells but may perform up to 5 workovers in Woodward County during 2018. 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 8 workovers in 2017. 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 2018. XTO Energy plans to further develop the underlying properties in the Anadarko
Basin primarily through:  1.
mechanical stimulation of existing wells; 2.
installing artificial lift; 3.
opening new producing zones in existing wells; 4.
deepening existing wells to new producing zones; and 5.
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 and is unlikely to change. During 2017, the gathering system collected approximately 6,523 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 5,000 Mcf
per day, for an average fee of approximately $0.11 per Mcf. The fee is subject to an annual price renegotiation under which either party can request that the price provided under the contract be renegotiated. The contract continues on a yearly
basis, and it is subject to termination upon written notice prior to its annual renewal or in the event the parties fail to agree upon a pricing renegotiation. XTO Energy also sells gas directly to third parties. The price paid to XTO Energy is
based upon the weighted average price of several published indices, which price varies upon market conditions, and includes a deduction for any transportation fees charged by the third party. Neither party has a firm obligation to sell or purchase
any specific minimum quantity of gas. Green River Basin The Green River Basin is located in southwestern Wyoming. Natural gas was discovered in the Fontenelle field of the Green River Basin in the early
1970s. The producing reservoirs are the Frontier, Baxter and Dakota sandstones. Daily 2017 sales volumes from the underlying properties in
the Fontenelle field averaged 11,200 Mcf of natural gas and 17 Bbls of oil. XTO Energy did not drill any wells or perform any workovers in the Green River Basin in 2017. XTO  11




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##### Table of Contents

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 2018. 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 2018 to assist
with disposal in the Fontenelle field. Potential development activities for the underlying properties in this area include:  1.
installing artificial lift; 2.
restimulating producing intervals utilizing new technology; 3.
additional compression to lower line pressures; and 4.
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 2017, the fuel charge was 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. Producing Acreage, Drilling and Well Counts For the following data, gross refers to the total wells or acres on the underlying properties in which XTO Energy owns a working interest and
net refers to gross wells or acres multiplied by the percentage working interest owned by XTO Energy. Although many of XTO Energys wells produce both oil and gas, a well is categorized as an oil well or a gas well based upon the
ratio of oil to natural gas production. Operated wells are managed by XTO Energy, while non-operated wells are managed by others. The underlying
properties are interests in developed properties located primarily in gas producing regions of Kansas, Oklahoma and Wyoming. The following is a summary of the approximate producing acreage of the underlying properties at December 31, 2017.
Undeveloped acreage is not significant.  Gross


NetHugoton Area


203,903



191,640Anadarko Basin


157,998



122,906Green River Basin


33,634



25,621Total


395,535



340,167  12




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##### Table of Contents

The following is a summary of the producing wells on the underlying properties as of December 31,
2017:  OperatedWells


Non-operatedWells


TotalGross


Net


Gross


Net


Gross


NetGas


1,131.0



1,008.2



245.0



52.8



1,376.0



1,061.0Oil


43.0



39.9



4.0



0.7



47.0



40.6Total(a)


1,174.0



1,048.1



249.0



53.5



1,423.0



1,101.6 (a)
Included in totals are 1 gross (0.0 net) wells in 2017, zero wells in 2016 and zero wells in 2015 drilled on the non-operated interests. There were 2 gross (0.11 net) wells in process of drilling at December 31,
2017. 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, 2017:  Underlying Properties


Net Profits InterestsProved Reserves(a)


Proved Reserves(a)(b)


Future Net Cash Flowsfrom Proved Reserves(a)(c)Gas(Mcf)


Oil    (Bbls)


Gas    (Mcf)


Oil    (Bbls)Undiscounted


Discounted(in thousands)Oklahoma


81,786



1,224



10,546



156


$
29,674


$
20,749Wyoming


28,504



38



1,524



2



3,638



2,980Kansas


8,131



57



968



7



2,151



1,235Total


118,421



1,319



13,038



165


$
35,463


$
24,964 (a)
Based on 12-month average oil price of $47.91 per Bbl and $2.40 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, 2017 consist of the following:  Underlying Properties


Net Profits InterestsProved Reserves


Proved ReservesGas(Mcf)


Oil    (Bbls)


Gas    (Mcf)


Oil    (Bbls)(in thousands)Proved developed reserves


117,667



1,319



12,844



165Proved undeveloped reserves


754







194



Total proved reserves


118,421



1,319



13,038



165 Approximately 99% of the underlying proved reserves are proved developed reserves.  13




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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, 2017, 2016, 2015 and 2014. Miller and Lents primary technical person responsible for calculating the
Trusts reserves has more than nine years of experience as a reserve engineer. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits
interests. Numerous uncertainties are inherent in estimating reserve volumes and values, and such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these
reserves may be substantially different from the original estimates. Reserve quantities and revenues for the net profits interests were estimated
from projections of reserves and revenues attributable to the underlying properties. Since the Trust has defined net profits interests, the Trust does not own a specific percentage of the oil and gas reserves. Oil and gas reserves are allocated to
the net profits interests by dividing Trust net cash inflows by 12-month average oil and gas prices. Oil and Natural Gas Production Trust production is recognized in the period net profits income is received, which is the month following receipt by XTO Energy, and generally two months
after the time of production. Oil and gas sales volumes are allocated to the net profits interests based upon a formula that considers oil and gas prices and the total amount of production expense and development costs. As such, the underlying
property production volume changes may not correlate with the Trusts net profit share of those volumes in any given period. Oil and gas
production and average sales prices attributable to the underlying properties and the net profits interests for each of the three years ended December 31 were as follows:  2017


2016


2015ProductionUnderlying PropertiesGas  Sales (Mcf)


13,903,368



14,855,263



15,736,066Average per day (Mcf)


38,091



40,588



43,113Oil  Sales (Bbls)


156,352



179,259



194,381Average per day (Bbls)


428



490



533Net Profits InterestsGas  Sales (Mcf)


1,628,427



1,095,601



2,292,205Average per day (Mcf)


4,461



2,993



6,280Oil  Sales (Bbls)


26,775



18,367



40,817Average per day (Bbls)


73



50



112Average Sales PriceGas (per Mcf)


$  2.92



$  2.09



$  2.72Oil (per Bbl)


$46.47



$37.59



$49.90Average ProductionCost per BOE


$11.60



$10.24



$11.87  14




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##### Table of Contents

Oil and gas production by conveyance attributable to the underlying properties for each of the three
years ended December 31 were as follows:  Underlying Gas Production (Mcf)Conveyance

2017


2016


2015Kansas


1,225,165



1,169,372



1,267,647Oklahoma


8,584,930



9,443,712



9,933,308Wyoming


4,093,273



4,242,179



4,535,111Total


13,903,368



14,855,263



15,736,066Underlying Oil Production (Bbls)Conveyance

2017


2016


2015Kansas


7,049



7,004



5,938Oklahoma


143,099



163,679



180,129Wyoming


6,204



8,576



8,314Total


156,352



179,259



194,381 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.  15




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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 natural gas produced from the underlying properties. During 2017, 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 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  16




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##### Table of Contents

greater, through percentage depletion equal to 15 percent of gross income. 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. 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 2017 Tax Cuts and Jobs Act (the
TCJA), for tax years beginning after December 31, 2017 and before January 1, 2026, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37%, and the highest marginal U.S. federal
income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is 20%. Under 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. 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.  17




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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 imposed by FATCA. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing
FATCA may be subject to different rules. The Treasury Department issued guidance providing that the FATCA withholding rules described above
generally will apply to qualifying payments made after June 30, 2014. Foreign unitholders are encouraged to consult their own tax 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, Post Office Box 962020, Fort Worth, Texas, 76162-2020, telephone number 1-855-588-7839, email address Trustee@hgt-hugoton.com, is the representative of the
Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.hgt-hugoton.com.
Notwithstanding the foregoing, the middlemen holding Trust units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with
respect to such Trust units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose Trust units are held by middlemen should consult with such middlemen regarding the information that will be reported to them
by the middlemen with respect to the Trust units. Unitholders should consult their tax 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 2017 tax year because the Trust had no revenues, income or deductions in 2017 attributable to properties located in Kansas.
The Trust did not file a return with Kansas for the 2016 and 2015 tax years for the same reason. Wyoming does not impose a state income tax.  18




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##### Table of Contents

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 Minerals Management
Service of the United States Department of the Interior amended the crude oil valuation regulations in July 2004 and the natural gas valuation regulations in June 2005 for oil and natural gas produced from federal oil and natural gas leases. The
principal effect of the oil regulations pertains to which published market prices are most appropriate to value crude oil not sold in an arms-length transaction and what transportation deductions should be allowed. The principal effect of the
natural gas valuation regulations pertains to the calculation of transportation deductions and changes necessitated by judicial decisions since the regulations were last amended. Seven percent of the net acres of the underlying properties, primarily
located in Wyoming, involve federal leases. Neither of these changes have had a significant effect on Trust distributions. 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 demand 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. XTO Energy
filed an appeal of the class certification to the 10th Circuit Court of Appeals on April 26, 2012, which was granted on June 26, 2012. The court reversed the certification of the class and remanded the case back to the trial court for
further proceedings. A non-binding mediation occurred September 1, 2016, but was unsuccessful. XTO Energy has advised the Trustee that in
December 2017, it reached a tentative settlement with the plaintiffs for $80 million and an additional $750 thousand for costs to administer the settlement following final approval. Preliminary Court approval was obtained in January 2018. The
settlement requires final approval by the judge after a fairness hearing, which is expected to be in the late first quarter of 2018. XTO Energy has advised the Trustee that it believes that a portion of the settlement that relates to the Trust is as
much as $20 million. The Trustee has asked to be advised as the matter progresses and; once additional information is made available to the Trustee, intends to review any claimed reductions in payment to the Trust based on the facts and
circumstances of the settlement. In light of a 2014 arbitration decision in which a three panel tribunal decided that the settlement in Fankhouser v. XTO Energy, Inc., including a new royalty calculation for future royalty payments, could not
be charged to the Trust, to the extent that the claims in Chieftain are similar to those in Fankhouser the Trustee would likely object to such claimed reductions. Should there be a disagreement as to whether the Trust should bear its
share of a settlement or judgment, the matter will be resolved by binding arbitration through the American Arbitration Association under the indenture creating the Trust. If $20 million of the Chieftain settlement is required to be borne by
the Trust, it would result in excess costs under the Oklahoma conveyance that, based on recent  19




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##### Table of Contents

distribution levels under such conveyance, would likely result in no distributions under the Oklahoma conveyance for several years. 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.  20




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##### Table of Contents

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. The following are the high and low intraday unit sales prices and total cash distributions per unit paid by the Trust during each
quarter of 2017 and 2016:  Sales Price


Distributionsper UnitQuarter

High


Low2017First

$
2.30


$
1.65


$
0.047167Second


2.35



1.70



0.028757Third


1.95



1.55



0.012433Fourth


1.90



1.30



0.024649$
0.1130062016First

$
1.97


$
0.98


$
0.000000Second


2.60



1.25



0.000000Third


2.75



1.91



0.019798Fourth


2.75



1.90



0.026587$
0.046385 At December 31, 2017, there were 40,000,000 units outstanding and approximately 617 unitholders of record;
39,398,268 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  Year Ended December 312017


2016


2015


2014


2013Net Profits Income

$
5,317,931


$
2,617,640


$
8,243,917


$
44,446,473


$
37,333,595Distributable Income


4,520,240



1,855,400



7,753,240



43,809,680



34,507,280Distributable Income per Unit


0.113006



0.046385



0.193831



1.095242



0.862682Distributions per Unit


0.113006



0.046385



0.193831



1.095242



0.862682Total Assets at Year-End


17,813,389



28,143,303



88,185,111



93,920,959



102,501,095  21




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##### Table of Contents

Item 7.Trustees Discussion and Analysis of Financial Condition and
Results of Operations Calculation of Net Profits Income The following is a summary of the calculation of net profits income received by the Trust:  Year Ended December 31(a)


Three Months Ended December 31(a)2017


2016


2015


2017


2016Sales VolumesGas (Mcf)(b)Underlying properties


13,903,368



14,855,263



15,736,066



3,405,474



3,591,313Average per day


38,091



40,588



43,113



37,016



39,036Net profits interests


1,628,427



1,095,601



2,292,205



341,493



388,766Oil (Bbls)(b)Underlying properties


156,352



179,259



194,381



37,061



39,906Average per day


428



490



533



403



434Net profits interests


26,775



18,367



40,817



5,554



6,162Average Sales PricesGas (per Mcf)

$
2.92


$
2.09


$
2.72


$
2.88


$
2.74Oil (per Bbl)

$
46.47


$
37.59


$
49.90


$
47.05


$
43.06RevenuesGas sales

$
40,650,478


$
31,025,713


$
42,864,131


$
9,823,346


$
9,826,058Oil sales


7,264,995



6,737,833



9,699,090



1,743,585



1,718,212Total Revenues


47,915,473



37,763,546



52,563,221



11,566,931



11,544,270CostsTaxes, transportation and other


8,259,657



6,284,951



7,554,245



1,990,343



1,640,684Production expense


17,128,387



16,762,302



20,898,895



4,193,695



4,135,755Development costs(c)


2,800,000



1,675,000



2,800,000



840,000



600,000Overhead


11,570,344



10,355,802



12,542,488



2,919,732



2,889,156Excess costs(d)


1,509,671



(586,559
)


(1,537,304
)


271,652



902,381Total Costs


41,268,059



34,491,496



42,258,324



10,215,422



10,167,976Net Proceeds


6,647,414



3,272,050



10,304,897



1,351,509



1,376,294Net Profits Percentage


80%



80%



80%



80%



80%Net Profits Income

$
5,317,931


$
2,617,640


$
8,243,917


$
1,081,207


$
1,101,035  (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.  22




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##### Table of Contents

Results of Operations Years Ended December 31, 2017, 2016 and 2015 Net profits
income for 2017 was $5,317,931, as compared with $2,617,640 for 2016 and $8,243,917 for 2015. The 103% increase in net profits income from 2016 to 2017 was primarily the result of higher oil and gas prices ($11.2 million partially offset by
decreased oil and gas production ($3.1 million), excess costs on the Kansas and Wyoming net profit interests in 2016 ($1.7 million), increased taxes, transportation and other costs ($1.6 million), higher overhead ($1.0 million), higher development
costs ($0.9 million), and higher production expenses ($0.3 million). The 68% decrease in net profits income from 2015 to 2016 is primarily the result of lower oil and gas prices ($9.9 million), decreased oil and gas production ($1.9 million), and
excess costs on the Kansas and Wyoming net profit interests in 2015 ($0.8 million), partially offset by decreased production expense ($3.3 million), lower overhead ($1.7 million), decreased taxes, transportation and other costs ($1.0 million) and
lower development costs ($0.9 million). Approximately 78% in 2017, 73% in 2016 and 76% in 2015 of net profits income was derived from natural gas sales. Trust administration expense was $804,719 in 2017 as compared to $805,482 in 2016 and $842,810 in 2015. Net cash reserve activity was $0 in 2017 and $0
in 2016 as compared to a reduction of $351,920 in 2015. Reductions to the cash reserve during the first half of 2016 for the payment of Trust expenses were offset by the increase to the reserve in July 2016, which fully replenished the reserve to
the $1,000,000 level. Cash reserve activity for 2015 included additions of $250,000 which the Trustee reserved for administrative expenses, offset by a refund of $601,920 which represents the remaining balance of the legal reserve that was included
in the November 2015 distribution. Interest income was $7,028 in 2017, $43,242 in 2016 and $213 in 2015. Interest income for 2016 included $42,291 related to a one-time prior period revenue adjustment. Other changes in interest income are
attributable to fluctuations in net profits income and interest rates. Distributable income was $4,520,240 or $0.113006 per unit in 2017, $1,855,400 or $0.046385 per unit in 2016 and $7,753,240 or $0.193831 per unit in 2015. 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.
oil and gas sales volumes; 2.
oil and gas sales prices; and 3.
costs deducted in the calculation of net profits income. Volumes Gas. From 2016 to 2017, underlying gas sales volumes decreased 6% primarily due to natural production decline and workovers, partially offset by
increased volumes due to repairs and maintenance at a third party gas processing system in the Hugoton area in 2016 and the timing of cash receipts. From 2015 to 2016, underlying gas sales volumes decreased 6% primarily due to natural production
decline, partially offset by completion of repairs and maintenance at a third party gas processing system in the Hugoton area following a force majeure incident. XTO Energy advised the Trustee that repairs and maintenance in the first half of 2015 at a third party gas processing system in the Hugoton area
following a force majeure incident resulted in decreased underlying gas volumes of approximately 5,000 Mcf per day. After being advised by the third party processor that the repairs were completed, XTO Energy then received notice that the force
majeure event was being extended to the processing portion of the third party plant due to an equipment malfunction. The processor was able to bypass the plant and take gas; however, the plant was not able to process gas for NGLs or helium for a
period of time. XTO Energy received notice that the plant returned to full capacity at the end of October 2015, including the processing of gas for NGLs and helium. Oil. From 2016 to 2017, underlying oil sales volumes decreased 13% primarily due to natural production decline and increased downtime. From 2015
to 2016, underlying oil sales volumes decreased 8% primarily due to natural production decline.  23




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##### Table of Contents

The estimated rate of natural production decline on the underlying oil and gas properties is
approximately 6% to 8% a year. Prices Gas.    The 2017 average gas price was $2.92 per Mcf, a 40% increase from the 2016 average gas price of $2.09 per Mcf, which
was a 23% decrease from the 2015 average gas price of $2.72 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 2017 through January 2018 was $2.86 per MMBtu. At March 1, 2018, the average NYMEX gas price for the following 12 months was $2.86
per MMBtu. Oil.    The average oil price for 2017 was $46.47 per Bbl, a 24% increase from the average oil price for 2016
of $37.59 per Bbl, which was a 25% decrease from the average oil price for 2015 of $49.90 per Bbl. Oil prices are expected to remain volatile. The average NYMEX price for November 2017 through January 2018 was $59.50 per Bbl. At March 1, 2018,
the average NYMEX oil price for the following 12 months was $59.05 per Bbl. Costs The calculation of net profits income includes deductions for production expense, development costs and overhead since the related underlying properties
are working interests. Taxes, transportation and other.    Taxes, transportation and other generally fluctuates with
changes in total revenues. Taxes, transportation and other increased 31% from 2016 to 2017 primarily because of increased production taxes related to higher oil and gas revenues and increased gas deductions related to increased gathering fees. For
further information on gathering fees, see Note 12 to Financial Statements under Item 8, Financial Statements and Supplementary Data. Taxes, transportation and other decreased 17% from 2015 to 2016 primarily because of decreased production and
property taxes related to lower oil and gas revenues, partially offset by increased gas deductions related to increased gathering fees. Production expense.    Production expense increased 2% from 2016 to 2017 primarily because of increased salt water disposal,
field costs, and repairs and maintenance, partially offset by decreased labor and compression costs. Production expense decreased 20% from 2015 to 2016 primarily because of decreased repairs and maintenance, labor, salt water disposal, compression
and field costs. Development costs.Development costs, which were deducted based on budgeted development costs, were
$2.8 million in 2017, $1.7 million in 2016 and $2.8 million in 2015. In 2017, actual development costs were $2.3 million. At December 31, 2017, cumulative budgeted costs deducted exceeded cumulative actual costs by approximately $537,000. 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 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. For further information on overhead, see Note 11 to Financial Statements under
Item 8, Financial Statements and Supplementary Data. 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 conveyance remaining
as of December 31, 2017 totaled  24




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##### Table of Contents

$883,736, including accrued interest of $112,180. Cumulative excess costs for the NPI remaining as of December 31, 2017 totaled $706,990, including accrued interest of $89,744. 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 2017 and 2016 During fourth quarter 2017 the
Trust received net profits income totaling $1,081,207 compared with fourth quarter 2016 net profits income of $1,101,035. This 2% decrease in net profits income was primarily due to decreased oil and gas production ($0.5 million), increased taxes,
transportation and other costs ($0.3 million), and higher development costs ($0.2 million), partially offset by higher oil and gas prices ($0.5 million) and excess costs activity ($0.5 million). After adding interest income of $2,412 and deducting administration expense of $97,659, distributable income for fourth quarter 2017 was $985,960 or
$0.024649 per unit. Distributable income for fourth quarter 2016 was $1,063,480 or $0.026587 per unit. Fourth quarter 2016 interest income included $42,291 related to a one-time prior period revenue adjustment. Distributions to unitholders for the quarter ended December 31, 2017 were:  Record Date

Payment Date

Per UnitOctober 31, 2017

November 14, 2017

$
0.006859November 30, 2017

December 14, 2017


0.006949December 29, 2017

January 16, 2018


0.010841$
0.024649 Volumes Fourth
quarter underlying gas sales volumes decreased 5% from 2016 to 2017 primarily due to natural production decline and the timing of cash receipts, partially offset by increased volumes due to repairs and maintenance at a third party gas processing
system in the Hugoton area in 2016. Underlying oil sales volumes decreased 7% from 2016 to 2017 primarily due to natural production decline and the timing of cash receipts. XTO Energy advised the Trustee that repairs and maintenance at a third party gas processing system in the Hugoton area resulted in decreased underlying
gas volumes of approximately 4,000 Mcf per day for the month of October 2016. The third party notified XTO Energy that maintenance was completed by the end of October 2016. Prices The average fourth quarter 2017 gas price was
$2.88 per Mcf, or 5% higher than the fourth quarter 2016 average price of $2.74 per Mcf. The average fourth quarter 2017 oil price was $47.05 per Bbl, or 9% higher than the fourth quarter 2016 average price of $43.06 per Bbl. For further information
about product prices, see Years Ended December 31, 2017, 2016 and 2015  Prices above. Costs Taxes, transportation and other.    Taxes, transportation and other increased 21% from fourth quarter 2016 to 2017 primarily
because of increased gas deductions related to increased gathering fees. Production expense.    Fourth quarter
production expense increased 1% from 2016 to 2017 primarily because of increased salt water disposal costs.  25




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##### Table of Contents

Development costs.    Development costs, which were deducted based on
budgeted development costs, increased 40% from fourth quarter 2016 to 2017. 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 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. For further information on overhead, see Note 11 to Financial Statements under
Item 8, Financial Statements and Supplementary Data. 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. Impairment of Net Profits
Interest In light of lower long term prices used to develop projections of future cash flows, continued excess costs on two conveyances and zero
distributions to unitholders for the six months ended June 30, 2016, the Trustee concluded in the second quarter of 2016 that the events or circumstances indicated the carrying value may not be recoverable and an assessment of the forecasted
net cash flows was performed for the NPI. The fair value of the NPI was developed using estimates for future oil and gas production attributable to the Trust, future crude oil and natural gas commodity prices published by third-party industry
experts (adjusted for basis differentials), estimated taxes, development and operating expenses, and a risk-adjusted discount rate. The result of the assessment indicated that the estimated undiscounted future net cash flows from the NPI were below
the carrying value of the NPI. The NPI was written down to its fair value of $28.8 million, resulting in a $57.3 million impairment charged directly to Trust corpus, which did not affect distributable income. There have been no events or
changes in circumstances to indicate the carrying value of the NPI may not be recoverable, and there is no further impairment of the assets as of December 31, 2017. Purchaser Adjustment XTO Energy advised the Trustee that the
February 2015 distribution included a one-time prior period adjustment for the recoupment of natural gas liquids revenue from the Trust in the amount of $353,069 ($282,455 net to the Trust) which was deducted from net proceeds in the first quarter
of 2015. Liquidity and Capital Resources The
Trusts only cash requirement is the 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. 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  26




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##### Table of Contents

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 As shown below,
the Trust had no obligations and commitments to make future contractual payments as of December 31, 2017, other than the December distribution payable to unitholders in January 2018, as reflected in the statement of assets, liabilities and
trust corpus.  Payments due by PeriodTotal


Less than1 Year


1 - 3 Years


3 - 5 Years


More than5 YearsDistribution payable to unitholders

$
433,640


$
433,640


$



$



$
 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, 2017, the monthly overhead charge, based on the number of operated wells, was approximately $956,000 ($764,800 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 Gathering & Processing Company, Inc. (TGPC) 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 and Note 7 to the Financial Statements under Item 8,
Financial Statements and Supplementary Data. Total gas sales from the underlying properties to XTO Energys wholly owned subsidiaries were
$12.3 million for 2017, or 30% of total gas sales, $15.0 million for 2016, or 48% of total gas sales and $16.4 million for 2015, or 38% 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.  27




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##### Table of Contents

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.
Net profits income is recognized in the month received rather than accrued in the month of production. 2.
Expenses are recognized when paid rather than when incurred. 3.
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, 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. In light of lower long term prices used to develop projections of future
cash flows, continued excess costs on two conveyances and zero distributions to unitholders for the six months ended June 30, 2016, the Trustee concluded in the second quarter of 2016 that the events or circumstances indicated the carrying
value may not be recoverable and an assessment of the forecasted net cash flows was performed for the NPI. The fair value of the NPI was developed using estimates for future oil and gas production attributable to the Trust, future crude oil and
natural gas commodity prices published by third-party industry experts (adjusted for basis differentials), estimated taxes, development and operating expenses, and a risk-adjusted discount rate. The result of the assessment indicated that the
estimated undiscounted future net cash flows from the NPI were below the carrying value of the NPI. The NPI was written down to its fair value of $28.8 million, resulting in a $57.3 million impairment charged directly to Trust corpus, which did not
affect distributable income. There have been no events or changes in circumstances to indicate the carrying value of the NPI may not be recoverable, and there is no further impairment of the assets as of December 31, 2017. 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.  28




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##### Table of Contents

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, 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, litigation, political and regulatory matters and competition. Such forward-looking statements are based on XTO Energy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, 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 The only assets of and sources of income to the Trust are the net profits interests, which generally entitle the Trust to
receive a share of the net profits from oil and gas production from the underlying properties. Consequently, the Trust is exposed to market risk from fluctuations in oil and gas prices. A significant decline in 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 proved reserves attributable to the Trusts interests. The Trust is a passive entity and, other than the Trusts ability to
periodically borrow money as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. The amount of any such borrowings is
unlikely to be material to the Trust. In addition, the Trustee is prohibited by the Trust indenture from engaging in any business activity or causing the Trust to enter into any investments other than investing cash on hand in specific short-term
cash investments. Therefore, the Trust cannot hold any derivative financial instruments. As a result of the limited nature of its borrowing and investing activities, the Trust is not subject to any material interest rate market risk. The Trust does
not engage in transactions in foreign currencies which could expose the Trust to any foreign currency related market risk.  29




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##### Table of Contents

Item 8.Financial Statements and Supplementary Data  PageReport of Independent Registered Public Accounting Firm


31Statements of Assets, Liabilities and Trust Corpus


33Statements of Distributable Income


33Statements of Changes in Trust Corpus


33Notes to Financial Statements


34 All financial statement schedules are omitted as they are inapplicable or the required information has been included in
the consolidated financial statements or notes thereto.  30




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##### Table of Contents

Report of Independent Registered Public Accounting Firm To the Unitholders of Hugoton Royalty Trust and Simmons Bank, as Trustee Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the accompanying statements of assets, liabilities and trust corpus of Hugoton Royalty Trust (the Trust) as of
December 31, 2017 and 2016, and the related statements of distributable income and of changes in trust corpus for each of the three years in the period ended December 31, 2017, including the related notes (collectively referred to as the
financial statements). We also have audited the Trusts internal control over financial reporting as of December 31, 2017, based on criteria established in Internal ControlIntegrated Framework (2013) issued by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the financial statements referred to above present
fairly, in all material respects, the assets, liabilities and trust corpus of the Trust as of December 31, 2017 and 2016,and its distributable income and its changes in trust corpus for each of the three years in the period ended
December 31, 2017 in conformity with the modified cash basis of accounting described in Note 2. Also in our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31,
2017, based on criteria established in Internal Control  Integrated Framework (2013) issued by the COSO. Basis for Opinions The Trusts management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for
its assessment of the effectiveness of internal control over financial reporting, included in the Trustees Report on Internal Control Over Financial Reporting, appearing under Item 9A. Our responsibility is to express opinions on the
Trusts financial statements and on the Trusts internal control over financial reporting 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 in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable
assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements 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. Our audit of internal control over financial reporting included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such
other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. 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 accounting principles generally accepted in the United States of America.  31




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##### Table of Contents

Definition and Limitations of Internal Control over Financial Reporting A trusts internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A trusts internal control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the trust; (ii) provide reasonable assurance that transactions are recorded as necessary
to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the trust are being made only in accordance with authorizations of management and the Trustee; and
(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trusts assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ PricewaterhouseCoopers LLP Dallas, Texas March 12, 2018 We have served as the Trusts auditor since 2011.  32




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##### Table of Contents

HUGOTON ROYALTY TRUST STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS  December 312017


2016AssetsCash and short-term investments

$
1,433,640


$
1,257,800Net profits interests in oil and gas properties  net(Notes 1 and 2)


16,379,749



26,885,503$
17,813,389


$
28,143,303Liabilities and Trust CorpusDistribution payable to unitholders

$
433,640


$
257,800Expense reserve(a)


1,000,000



1,000,000Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)


16,379,749



26,885,503$
17,813,389


$
28,143,303  (a)
The expense reserve allows the Trustee to pay its obligations should it be unable to pay them out of the net profits income. The reserve is fully funded at $1,000,000. STATEMENTS OF DISTRIBUTABLE INCOME  Year Ended December 312017


2016


2015Net profits income

$
5,317,931


$
2,617,640


$
8,243,917Interest income(a)(b)


7,028



43,242



213Total income


5,324,959



2,660,882



8,244,130Administration expense


804,719



805,482



842,810Cash reserves withheld (used) for Trust
expenses(a)










(351,920
)Distributable income

$
4,520,240


$
1,855,400


$
7,753,240Distributable income per unit (40,000,000 units)

$
0.113006


$
0.046385


$
0.193831  (a)
Cash reserves for the period ended December 31, 2015 includes a refund of $601,920 which represents the remaining balance of the legal reserve that was included in the November 2015 distribution. (b)
Interest income for the period ended December 31, 2016, includes $42,291 related to a one-time prior period revenue adjustment. STATEMENTS OF CHANGES IN TRUST CORPUS  Year Ended December 312017


2016


2015Trust corpus, beginning of year

$
26,885,503


$
86,900,231


$
89,596,828Amortization of net profits interests


(10,505,754
)


(2,708,201
)


(2,696,597
)Impairment of net profits interest (Note 1)






(57,306,527
)


Distributable income


4,520,240



1,855,400



7,753,240Distributions declared


(4,520,240
)


(1,855,400
)


(7,753,240
)Trust corpus, end of year

$
16,379,749


$
26,885,503


$
86,900,231 See accompanying notes to financial statements.  33




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##### Table of Contents

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.
the Trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments;  2.
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;  3.
the Trustee may establish a cash reserve for payment of any liability that is contingent or not currently payable;  4.
the Trustee may borrow funds to pay Trust liabilities if repaid in full prior to further distributions to unitholders;  5.
the Trustee will make monthly cash distributions to unitholders (Note 3); and  6.
the Trust will terminate upon the first occurrence of:  a)
disposition of all net profits interests pursuant to terms of the Trust indenture,  b)
gross proceeds from the underlying properties falling below $1 million per year for two successive years, or  c)
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.
Net profits income is recorded in the month received by the Trustee (Note 3);  2.
Trust expenses are recorded based on liabilities paid and cash reserves established by the Trustee for liabilities and contingencies.  3.
Distributions to unitholders are recorded when declared by the Trustee (Note 3); The most significant
differences between the Trusts financial statements and those prepared in accordance with U.S. GAAP are:  1.
Net profits income is recognized in the month received rather than accrued in the month of production.  2.
Expenses are recognized when paid rather than when incurred.  3.
Cash reserves may be established by the Trustee for contingencies that would not be recorded under U.S. GAAP.  34




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##### Table of Contents

HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS(Continued)   This comprehensive basis of
accounting corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with U.S. GAAP, directing such entities to accrue
or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the Trusts financial statements are prepared on the modified cash basis, as described above, most accounting pronouncements
are not applicable to the Trusts financial statements. 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. In light of lower long term prices used to develop projections of future cash
flows, continued excess costs on two conveyances and zero distributions to unitholders for the first and second quarters of 2016, the Trustee concluded in the second quarter of 2016 that the events or circumstances indicated the carrying value may
not be recoverable and an assessment of the forecasted net cash flows was performed for the NPI. The fair value of the NPI was developed using estimates for future oil and gas production attributable to the Trust, future crude oil and natural gas
commodity prices published by third-party industry experts (adjusted for basis differentials), estimated taxes, development and operating expenses, and a risk-adjusted discount rate. The result of the assessment indicated that the estimated
undiscounted future net cash flows from the NPI were below the carrying value of the NPI. The NPI was written down to its fair value of $28.8 million, resulting in a $57.3 million impairment charged directly to Trust corpus, which did not
affect distributable income. There have been no events or changes in circumstances to indicate the carrying value of the NPI may not be recoverable, and there is no further impairment of the assets as of December 31, 2017. 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 $173,380,675 as of December 31, 2017 and $162,874,921 as of December 31, 2016. Revenue Recognition In May 2014, the FASB issued
updated guidance for recognizing revenue from contracts with customers. This update amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of goods and
services to a customer at an amount that reflects the consideration a  35




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##### Table of Contents

HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS(Continued)  company expects to receive in exchange for those goods or services. The Trustee and XTO Energy do not believe the adoption of this standard will have a significant impact on the Trusts
financial statements due to the modified cash basis of reporting used by the Trust. 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 (Note 7). 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. The following
summarizes excess costs activity, cumulative excess costs balance and accrued interest to be recovered by conveyance:  UnderlyingKS


OK


WY


TotalCumulative excess costs remaining at 12/31/16

$
1,049,601


$



$
1,158,205


$
2,207,806Net excess costs (recovery) for the quarter ended 3/31/17


(76,669
)






(686,923
)


(763,592
)Net excess costs (recovery) for the quarter ended 6/30/17


10,426







44,584



55,010Net excess costs (recovery) for the quarter ended 9/30/17


(125,539
)






(403,898
)


(529,437
)Net excess costs (recovery) for the quarter ended 12/31/17


(86,263
)






(111,968
)


(198,231
)Cumulative excess costs remaining at 12/31/17


771,556











771,556Accrued interest at 12/31/17


112,180











112,180Total remaining to be recovered at 12/31/17

$
883,736


$



$



$
883,736  36




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##### Table of Contents

HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS(Continued)  NPIKS


OK


WY


TotalCumulative excess costs remaining at 12/31/16

$
839,681


$



$
926,564


$
1,766,245Net excess costs (recovery) for the quarter ended 3/31/17


(61,335
)






(549,538
)


(610,873
)Net excess costs (recovery) for the quarter ended 6/30/17


8,341







35,667



44,008Net excess costs (recovery) for the quarter ended 9/30/17


(100,431
)






(323,118
)


(423,549
)Net excess costs (recovery) for the quarter ended 12/31/17


(69,010
)






(89,575
)


(158,585
)Cumulative excess costs remaining at 12/31/17


617,246











617,246Accrued interest at 12/31/17


89,744











89,744Total remaining to be recovered at 12/31/17

$
706,990


$



$



$
706,990 XTO Energy advised the Trustee that net excess cost activity on properties underlying the Kansas net profits interest
for the year ended December 31, 2017 was $278,045 ($222,436 net to the Trust). Improved gas prices in relation to costs resulted in the partial recovery of excess costs of $347,091 ($277,672 net to the Trust), for the year ended
December 31, 2017. Additional excess costs on properties underlying the Kansas net profits interest for the year ended December 31, 2017 were $69,046 ($55,237 net to the Trust). XTO Energy advised the Trustee that improved gas prices in relation to costs resulted in the full recovery of excess costs, plus accrued interest of
$73,422 ($58,737 net to the Trust), on properties underlying the Wyoming net profits interests for the quarter ended December 31, 2017. XTO
Energy advised the Trustee that a one-time reimbursement for overhead corrections and a one-time prior period revenue adjustment resulted in the partial recovery of excess costs of $91,851 ($73,481 net to the Trust) on properties underlying the
Kansas net profits interest for the year ended December 31, 2016. This included the partial recovery of excess costs of $369,582 ($295,666 net to the Trust) related to the quarter ended December 31, 2016. XTO Energy advised the Trustee that a one-time reimbursement for overhead corrections led to full recovery of excess costs, plus accrued interest of
$1,059 ($847 net to the Trust), on properties underlying the Oklahoma net profits interest for the year ended December 31, 2016. XTO Energy
advised the Trustee that lower gas prices in the first half of 2016, partially offset by a one-time reimbursement for overhead corrections and improved gas prices in the second half of 2016 resulted in net excess costs of $679,470 ($543,576 net to
the Trust) on properties underlying the Wyoming net profits interest for the year ended December 31, 2016. This included the partial recovery of excess costs of $532,798 ($426,238 net to the Trust) related to the quarter ended December 31,
2016. Underlying cumulative excess costs for the Kansas conveyance remaining as of December 31, 2017 totaled $0.9 million, including accrued
interest of $0.1 million.  37




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##### Table of Contents

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:  Year Ended December 312017


2016


2015Cumulative actual costs under (over) the amount deducted  beginning of period

$
56,243


$
239,528


$
1,242,998Actual costs


(2,319,099
)


(1,858,285
)


(3,803,470
)Budgeted costs deducted


2,800,000



1,675,000



2,800,000Cumulative actual costs under (over) the amount deducted  end of period

$
537,144


$
56,243


$
239,528 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 December 2014 through the August 2015
distribution. Due to the anticipated level of actual costs and the 2015 development budget, the development cost deduction was increased to $300,000 beginning with the September 2015 distribution and was maintained at that level through January
2016. Due to the level of actual development costs, the monthly development cost deduction was decreased to $187,500 beginning in February 2016 and was maintained at that level through March 2016. Due to the revised 2016 budget, the monthly
development cost deduction was decreased to $100,000 beginning in April 2016. Due to the level of actual development costs, the monthly development cost deduction was further decreased to $50,000 beginning in June 2016. Based on an increased level
of development activity and costs, the deduction was increased from $50,000 to $200,000 beginning with the October 2016 distribution and was maintained at that level through July 2017. 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 and was maintained at that level through the end of 2017. For further information on 2018 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 2017 tax year because the Trust had no revenues, income or deductions
in 2017 attributable to properties located in Kansas. The Trust did not file a return with Kansas for the 2016 tax year for the same reason.  38




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HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS(Continued)  Wyoming does not impose a state income tax. 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, 2017, the monthly
overhead charge, based on the number of operated wells, was approximately $956,000 ($764,800 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 Gathering & Processing Company, Inc. (TGPC) 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 $12.3 million for 2017, or 30% of total gas sales,
$15.0 million for 2016, or 48% of total gas sales and, $16.4 million for 2015, or 38% 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 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 demand 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. XTO Energy
filed an appeal of the class certification to the 10th Circuit Court of Appeals on April 26, 2012, which was granted on June 26, 2012. The court reversed the certification of the class and remanded the case back to the trial court for
further proceedings. A non-binding mediation occurred September 1, 2016, but was unsuccessful. XTO Energy has advised the Trustee that in
December 2017, it reached a tentative settlement with the plaintiffs for $80 million and an additional $750 thousand for costs to administer the settlement following final approval. Preliminary Court approval was obtained in January 2018. The
settlement requires final approval by the judge after a fairness hearing, which is expected to be in the late first quarter of 2018. XTO Energy has advised the Trustee that it believes that a portion of the settlement that relates to the Trust is as
much as $20 million. The Trustee has asked to be advised as the matter  39




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HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS(Continued)  progresses and; once additional information is made available to the Trustee, intends to review any claimed reductions in payment to the Trust based on the facts and circumstances of the
settlement. In light of a 2014 arbitration decision in which a three panel tribunal decided that the settlement in Fankhouser v. XTO Energy, Inc., including a new royalty calculation for future royalty payments, could not be charged to the
Trust, to the extent that the claims in Chieftain are similar to those in Fankhouser the Trustee would likely object to such claimed reductions. Should there be a disagreement as to whether the Trust should bear its share of a
settlement or judgment, the matter will be resolved by binding arbitration through the American Arbitration Association under the indenture creating the Trust. If $20 million of the Chieftain settlement is required to be borne by the Trust,
it would result in excess costs under the Oklahoma conveyance that, based on recent distribution levels under such conveyance, would likely result in no distributions under the Oklahoma conveyance for several years. 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 nonresident recipients of oil and gas proceeds. After consultation with its tax counsel, the Trustee believes that it is not required to withhold on payments made to the unitholders. However, regulations are subject to change by
the various states, which could change this conclusion. Should amounts be withheld on payments made to the Trust or the unitholders, distributions to the unitholders would be reduced by the required amount, subject to the filing of a claim for
refund by the Trust or unitholders for such amount. 9. Supplemental Oil and Gas Reserve Information (Unaudited) Oil and Natural Gas Reserves Proved oil and gas
reserves have been estimated by independent petroleum engineers. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically
producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that
renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with
the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of
these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors. Standardized Measure The standardized measure of
discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month average prices for oil and gas, based on the
first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures to produce the proved 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.  40




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##### Table of Contents

HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS(Continued)  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 $2.40 per Mcf in 2017, $1.94 per Mcf in 2016, $2.10 per Mcf in 2015 and $4.35 per Mcf in 2014. Oil prices used to determine the standardized measure were based on average realized oil prices of $47.91
per Bbl in 2017, $39.08 per Bbl in 2016, $46.56 per Bbl in 2015 and $92.70 per Bbl in 2014. Reserve quantities and revenues for the net profits
interests were estimated from projections of reserves and revenues attributable to the underlying properties. Since the Trust has defined net profits interests, the Trust does not own a specific percentage of the oil and gas reserves. Oil and gas
reserves are allocated to the net profits interests by dividing Trust net cash inflows by 12-month average oil and gas prices. Any fluctuations in 12-month average prices or estimated costs will result in revisions to the estimated reserve
quantities allocated to the net profits interests, which may not correlate with revisions of underlying proved reserves. Proved Reserves  Underlying Properties


Net Profits Interests(in thousands)

Gas (Mcf)


Oil (Bbls)


Gas (Mcf)


Oil (Bbls)Balance, December 31, 2014


210,188



2,219



76,163



856Extensions, additions and discoveries


71



2



5



Revisions of prior estimates


(90,561
)


(841
)


(59,389
)


(636
)Production  sales volumes


(15,736
)


(194
)


(2,292
)


(41
)Sales in place














Balance, December 31, 2015


103,962



1,186



14,487



179Extensions, additions and discoveries














Revisions of prior estimates


3,361



90



(9,224
)


(95
)Production  sales volumes


(14,855
)


(179
)


(1,096
)


(18
)Sales in place














Balance, December 31, 2016


92,468



1,097



4,167



66Extensions, additions and discoveries


5



33



3



17Revisions of prior estimates


39,851



345



10,496



109Production  sales volumes


(13,903
)


(156
)


(1,628
)


(27
)Sales in place














Balance, December 31, 2017


118,421



1,319



13,038



165 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. Positive revisions for the underlying properties during the year ended  41




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HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS(Continued)  December 31, 2017 are primarily due to higher 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  Underlying Properties


Net Profits Interests(in thousands)

Gas (Mcf)


Oil (Bbls)


Gas (Mcf)


Oil (Bbls)December 31, 2014


177,389



1,847



68,335



767December 31, 2015


102,683



1,178



14,411



178December 31, 2016


91,734



1,097



4,167



66December 31, 2017


117,667



1,319



12,844



165 Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves  December 31(in thousands)

2017


2016


2015Underlying PropertiesFuture cash inflows

$
347,055


$
222,625


$
273,346Future costs:Production


301,930



209,820



227,298Development


795



795



1,704Future net cash flows


44,330



12,010



44,34410% discount factor


13,125



2,474



14,739Standardized measure

$
31,205


$
9,536


$
29,605Net Profits InterestsFuture cash inflows

$
38,655


$
10,353


$
38,668Future production taxes


3,192



745



3,192Future net cash flows


35,463



9,608



35,47610% discount factor


10,499



1,980



11,793Standardized measure

$
24,964


$
7,628


$
23,683  42




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##### Table of Contents

HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS(Continued)  Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves  (in thousands)2017


2016


2015Underlying PropertiesStandardized measure, January 1

$
9,536


$
29,605


$
246,596Revisions:Prices and costs


25,717



(18,980
)


(259,248
)Quantity estimates


4,667



988



(30,036
)Accretion of discount


784



2,569



21,887Future development costs


(2,667
)


(738
)


60,798Production rates and other


(586
)


(636
)


(104
)Net revisions


27,915



(16,797
)


(206,703
)Extensions, additions and discoveries


401







16Production


(9,447
)


(4,947
)


(13,104
)Development costs


2,800



1,675



2,800Sales in place










Net change


21,669



(20,069
)


(216,991
)Standardized measure, December 31

$
31,205


$
9,536


$
29,605Net Profits InterestsStandardized measure, January 1

$
7,628


$
23,683


$
197,278Extensions, additions and discoveries


321







13Accretion of discount


628



2,055



17,510Revisions of prior estimates, changes in price and other


21,705



(15,492
)


(182,874
)Sales in place










Net profits income


(5,318
)


(2,618
)


(8,244
)Standardized measure, December 31

$
24,964


$
7,628


$
23,683  43




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##### Table of Contents

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 2017 and 2016:  Net ProfitsIncome


DistributableIncome


DistributableIncomeper Unit2017First Quarter

$
2,223,626


$
1,886,680


$
0.047167Second Quarter


1,324,846



1,150,280



0.028757Third Quarter


688,252



497,320



0.012433Fourth Quarter


1,081,207



985,960



0.024649$
5,317,931


$
4,520,240


$
0.1130062016First Quarter

$
63,562


$



$
0.000000Second Quarter


199,545







0.000000Third Quarter


1,253,498



791,920



0.019798Fourth Quarter


1,101,035



1,063,480



0.026587$
2,617,640


$
1,855,400


$
0.046385 11. Operated Overhead XTO
Energy advised the Trustee that the August 2016 distribution included a one-time reimbursement of approximately $450,000 related to operated overhead corrections for the period of January 2014 through May 2016. This reimbursement affected the net
profits income under the Oklahoma conveyance. XTO Energy advised the Trustee that the May 2016 distribution included a one-time reimbursement of
$788,000 related to operated overhead corrections for the period of January 2014 through February 2016. This reimbursement affected the net profits income under the Kansas, Oklahoma and Wyoming conveyances by approximately $186,000, $320,000 and
$282,000 respectively. 12. Taxes, Transportation and Other Deductions XTO Energy advised the Trustee that net profits income for August 2016 included approximately $500,000 in additional gathering fees for the period of
December 2015 through May 2016 related to a renegotiated gas purchase contract that included production from properties underlying the Oklahoma conveyance. The current contract term is December 1, 2015 until November 30, 2017, and is now
on a month-to-month basis. 13. Purchaser and Other Adjustments XTO Energy advised the Trustee that the February 2015 distribution included a one-time prior period adjustment for the recoupment of natural gas liquids
revenue from the Trust in the amount of $353,069 ($282,455 net to the Trust) which was deducted from net proceeds in the first quarter of 2015. XTO
Energy advised the Trustee that the December 2016 distribution included a one-time prior period adjustment of approximately $230,000 in additional gas revenue from properties underlying the Kansas net profits interest.  44




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##### Table of Contents

HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS(Continued)  14. Subsequent Events Subsequent to December 31, 2017, the Trustee reserved $508,000 that would have been payable in the January 2018 and February 2018 distributions. The
Trustee announced that after reviewing claimed reductions in payments to the Trust relating to the Chieftain settlement and a determination whether the Trustee will object to any such reductions, a determination will be made as to what amount
of reserve will be maintained for anticipated future Trust expenses. (Note 8).  45




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##### Table of Contents

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, 2017. The effectiveness of the Trusts internal control over financial reporting as of December 31,
2017 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report under Item 8, Financial Statements and Supplementary Data. 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, 2017 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




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##### Table of Contents

PART III Item 10.Directors, Executive Officers and Corporate Governance (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, 2017. (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.    Southwest Bank, the prior trustee, received the following annual compensation for the
fiscal years ended December 31, 2015 through December 31, 2017 as specified in the Trust indenture:  2017


2016


2015Southwest Bank, Trustee(1)

$
67,926


$
65,032


$
68,288 Under the Trust indenture, the trustee is entitled to an annual administrative fee, paid in equal monthly installments.
Such fee can be adjusted annually based on an oil and gas industry index. Upon termination of the Trust, the trustee is entitled to a termination fee of $15,000. (c) Pay Ratio Disclosure.    The Trust does not have a principal executive officer or employees and therefore, the pay ratio
disclosure is not applicable. Item 12.Security Ownership of Certain Beneficial Owners and Management and Related
Unitholder Matters (a) Equity Compensation Plans and Trust Repurchases.    The Trust has no equity
compensation plans. The Trust has not repurchased any units during the fourth quarter of fiscal 2017. (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




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##### Table of Contents

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, 2017 was approximately $956,000 per month, or $11,472,000 annually (net to the Trust of $764,800 per month or $9,177,600 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,
2015 through December 31, 2017. 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, 2017 and 2016 are:  2017


2016Audit fees-PwC

$
158,000


$
148,129Audit-related fees






Tax fees






All other fees






$
158,000


$
148,129 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




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##### Table of Contents

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, 2017 and 2016 Statements of Distributable Income for the years ended December 31, 2017, 2016 and 2015 Statements of Changes in Trust Corpus for the years ended December 31, 2017, 2016 and 2015 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)
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.  (b)
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.  (c)
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.  (d)
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)
Consent of Miller and Lents, Ltd.  (31)
Rule 13a-14(a)/15d-14(a) Certification  (32)
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, P.O. Box 962020, Fort Worth, Texas 76162-2020.  49




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##### Table of Contents

SIGNATURES 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.  HUGOTON ROYALTY TRUSTBy SIMMONS BANK, TRUSTEEBy

/S/ LEE ANN ANDERSONLee Ann AndersonSenior Vice PresidentEXXON MOBIL CORPORATIONDate: March 12, 2018



By

/S/ DAVID LEVYDavid LevyVice President  Upstream Business Services (The Trust has no directors or executive officers.)  50