Hugoton Royalty Trust
Annual Report 2019

Plain-text annual report

Hugoton Royalty Trust 2019 Annual Report and Form 10-K Glossary of Terms Bbl Bcf BOE Mcf Barrel (of oil) Billion cubic feet (of natural gas) Barrel of oil equivalent Thousand cubic feet (of natural gas) MMBtu One million British Thermal Units, a common energy measurement net proceeds Gross proceeds received by XTO Energy from sale of production from the underlying properties, less applicable costs, as defined in the net profits interest conveyances. net profits income Net proceeds multiplied by the net profits percentage of 80%, which is paid to the Trust by XTO Energy. “Net profits income” is referred to as “royalty income” for tax reporting purposes. net profits interest An interest in an oil and gas property measured by net profits from the sale of production, rather than a specific portion of production. The following defined net profits interests were conveyed to the Trust from the underlying properties: 80% net profits interests – interests that entitle the Trust to receive 80% of the net proceeds from the underlying properties. underlying properties XTO Energy’s interest in certain oil and gas properties from which the net profits interests were conveyed. The underlying properties include working interests in predominantly gas-producing properties located in Kansas, Oklahoma and Wyoming. working interest An operating interest in an oil and gas property that provides the owner a specified share of production that is subject to all production expense and development costs. Selected Financial Data 2019 Years Ended December 31, Net Profits Income ..................... $ 369,458 Distributable Income ................. 0 Distributable Income per Unit .. 0.000000 Distributions per Unit................. 0.000000 Total Assets at Year End ........... 605,646 2018 $ 1,590,949 370,040 0.009251 0.009251 16,945,147 2017 $ 5,317,931 4,520,240 0.113006 0.113006 17,813,389 2016 $ 2,617,640 1,855,400 0.046385 0.046385 28,143,303 2015 $ 8,243,917 7,753,240 0.193831 0.193831 88,185,111 Inside front cover. 2-color. PMS#301U and black. The Trust Hugoton Royalty Trust was created on December 1, 1998 when XTO Energy Inc. conveyed 80% net profits interests in certain predominantly gas-producing Net profits income received by the Trust on the last business day of each month is calculated and paid by XTO Energy based on net proceeds received from the underlying properties located in Kansas, Oklahoma properties in the prior month. Distributions, and Wyoming to the Trust. The net profits as calculated by the Trustee, are paid to interests are the only assets of the Trust, month-end unitholders of record within ten other than cash held for Trust expenses and business days. for distribution to unitholders. Summary The Trust was created to collect and distribute to unitholders monthly net profits income related to the 80% net profits interests. Such net profits income ($25.0 million NPI), including accrued interest of $1.0 million ($0.8 million NPI). For further information on excess costs, see Note 4 to Financial Statements under Item 8, “Financial is calculated as 80% of the net proceeds Statements and Supplementary Data” of the received from certain working interests in accompanying Form 10-K. predominantly gas-producing properties in Kansas, Oklahoma and Wyoming. Net proceeds from properties in each state Cost Depletion is generally available to unitholders as a deduction from royalty are calculated by deducting production income. Available depletion is dependent expense, development costs and overhead upon the unitholder’s cost of units, purchase from revenues. If monthly costs exceed date and prior allowable depletion. It may revenues from the underlying properties be more beneficial for unitholders to deduct in any state, such excess costs must be percentage depletion. Please see the recovered, with accrued interest, from 2019 tax booklet for specific instructions. future net proceeds of that state and cannot Unitholders should consult their tax advisors reduce net profits income from another state. for further information. Excess costs generally can occur during periods of higher development activity and/ or lower gas prices. Underlying cumulative excess costs for the Kansas, Oklahoma and Wyoming conveyances remaining as of December 31, 2019 totaled $31.2 million Page 1 of 4 pages of text which will be added to the beginning of the Form 10-K. One book of text pages. Single stitch. To Unitholders: We are pleased to present the 2019 Annual Report on Form 10-K of the Hugoton Royalty Trust as filed with the Securities and Exchange Commission. costs, and higher gas prices. For further information, see “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” under Item 7 of the This report contains important accompanying Form 10-K. information about the Trust’s net profits XTO Energy is a party to legal interests, including information provided proceedings that may affect future Trust to the Trustee by XTO Energy. distributions. For further information, For the year ended December 31, see Note 8 to Financial Statements 2019, net profits income totaled $369,458. under Item 8, “Financial Statements After adding interest income of $21,429, and Supplementary Data” of the net cash reserve activity of ($522,511) and accompanying Form 10-K. deducting Trust administration expense Natural gas prices averaged $2.95 of $913,398, distributable income was $0 per Mcf for 2019, 10% higher compared to or $0.000000 per unit. Net profits income the 2018 average price of $2.69 per Mcf. and distributions were 77% and 100%, The average 2019 oil price was $53.60 respectively, lower than 2018 amounts per Bbl, 14% lower compared to the 2018 primarily because of decreased gas average price of $62.69 per Bbl. production, net excess costs, increased Gas sales volumes from the production expenses, increased taxes, underlying properties for 2019 were transportation and other costs, and lower 11,112,535 Mcf, or 30,445 Mcf per day, oil prices, partially offset by increased a decrease of 14% from 35,601 Mcf per oil production, decreased development day in 2018. Oil sales volumes from the Page 2 of 4 pages of text. Black ink only. To Unitholders: Continued underlying properties were 302,040 Bbls, prices or costs will result in revisions to or 828 Bbls per day in 2019, an increase the estimated reserve quantities allocated of 94% from 426 Bbls per day in 2018. For to the net profits interests. All reserve further information on sales volumes and information prepared by independent product prices, see “Trustee’s Discussion engineers has been provided to the and Analysis of Financial Condition and Trustee by XTO Energy. Results of Operations” under Item 7 of the Estimated future net cash flows accompanying Form 10-K. from proved reserves of the net profits As of December 31, 2019, proved interests at December 31, 2019 were reserves for the underlying properties zero. Proved reserve estimates and were estimated by independent related future net cash flows have been engineers to be 80.2 Bcf of natural gas determined based on a 12-month average and 1.6 million Bbls of oil. From year-end gas price of $1.88 per Mcf and a 12-month 2018 to 2019, gas and oil reserves for the average oil price of $53.20 per Bbl, based underlying properties decreased 34% on the first-day-of-the-month price for and 21%, respectively, primarily due to each month in the period, and year end lower oil and gas prices used to estimate costs, including recovery of cumulative reserves. Based on an allocation of these excess costs remaining at year end. reserves, there were no proved reserves Other guidelines used in estimating attributable to the net profits interests. proved reserves, as prescribed by the Because Trust reserve quantities are Financial Accounting Standards Board, determined using an allocation formula, are described in Note 9 to Financial any fluctuations in actual or assumed Statements under Item 8, “Financial Page 3 of 4 pages of text. Black ink only. To Unitholders: Continued Statements and Supplementary Data” income. Unitholders should consult their of the accompanying Form 10-K. The tax advisors for further information. present value of estimated future net cash flows is computed based on SEC guidelines and is not necessarily representative of the market value of Trust units. As disclosed in the tax instructions provided to unitholders in February 2020, Trust distributions are considered portfolio income, rather than passive Hugoton Royalty Trust By: Simmons Bank, Trustee By: Nancy Willis Vice President March 30, 2020 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) È ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2019 OR ‘ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to . Commission File No. 1-10476 Hugoton Royalty Trust (Exact name of registrant as specified in its charter) Texas (State or other jurisdiction of incorporation or organization) c/o Corporate Trustee: Simmons Bank 2911 Turtle Creek Blvd, Suite 850 Dallas, Texas (Address of principal executive offices) 58-6379215 (I.R.S. Employer Identification No.) 75219 (Zip Code) Registrant’s telephone number, including area code (at the office of the Corporate Trustee): (855) 588-7839 Securities registered pursuant to Section 12(b) of the Act: None Title of each class Units of Beneficial Interest Trading Symbol HGTXU Name of each exchange on which registered OTCQX Securities registered pursuant to Section 12(g) of the Act: Units of Beneficial Interest Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES ‘ NO È Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. YES ‘ NO È Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES È NO ‘ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). YES ‘ NO ‘ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act: Large accelerated filer ‘ Non-accelerated filer È ‘ Accelerated filer Smaller reporting company È Emerging growth company ‘ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ‘ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES ‘ NO È The aggregate market value of units of beneficial interest held by non-affiliates of the registrant at June 30, 2019 (the last business day of the registrant’s most recently completed second fiscal quarter) was approximately $14.4 million. The number of units of beneficial interest outstanding as of March 4, 2020 was 40,000,000. HUGOTON ROYALTY TRUST 2019 ANNUAL REPORT ON FORM 10-K TABLE OF CONTENTS Page Glossary of Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Part I Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 2. Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 4. Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Part II Item 5. Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units . . . . . . . . . Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 6. Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . Item 7A. Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 8. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Part III Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 11. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Item 12. Item 13. Item 14. Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . . . Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 15. Part IV Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 3 10 10 21 22 23 23 24 31 32 46 46 46 47 47 47 48 48 49 i HUGOTON ROYALTY TRUST GLOSSARY OF TERMS The following are definitions of significant terms used in this Annual Report on Form 10-K: Bbl Bcf BOE Mcf MMBtu net proceeds net profits income net profits interest underlying properties Barrel (of oil) Billion cubic feet (of natural gas) Barrel of oil equivalent Thousand cubic feet (of natural gas) One million British Thermal Units, a common energy measurement Gross proceeds received by XTO Energy from sale of production from the underlying properties, less applicable costs, as defined in the net profits interest conveyances. Net proceeds multiplied by the net profits percentage of 80%, which is paid to the Trust by XTO Energy. “Net profits income” is referred to as “royalty income” for tax reporting purposes. An interest in an oil and gas property measured by net profits from the sale of production, rather than a specific portion of production. The following defined net profits interests were conveyed to the Trust from the underlying properties: 80% net profits interests—interests that entitle the Trust to receive 80% of the net proceeds from the underlying properties. XTO Energy’s interest in certain oil and gas properties from which the net profits interests were conveyed. The underlying properties include working interests in predominantly gas-producing properties located in Kansas, Oklahoma and Wyoming. working interest An operating interest in an oil and gas property that provides the owner a specified share of production that is subject to all production expense and development costs. 1 Item 1. Business PART I Hugoton Royalty Trust (the “Trust”) is an express trust created under the laws of Texas pursuant to the Hugoton Royalty Trust Indenture entered into on December 1, 1998 between XTO Energy Inc. (formerly known as Cross Timbers Oil Company), as grantor, and NationsBank, N.A., as Trustee. On January 9, 2014, the successor of NationsBank, N.A., U.S. Trust, Bank of America Private Wealth Management, a division of Bank of America, N.A., gave notice to unitholders that it would resign as Trustee. At a special meeting of the Trust’s unitholders held on May 23, 2014, the unitholders of the Trust voted to approve the proposal to appoint Southwest Bank as successor Trustee of the Trust effective May 30, 2014. Effective October 19, 2017, Simmons First National Corporation (“SFNC”) completed its acquisition of First Texas BHC, Inc., the parent company of Southwest Bank, the Trustee of the Trust. SFNC is the parent of Simmons Bank. SFNC merged Southwest Bank with Simmons Bank effective February 20, 2018. Simmons Bank (the “Trustee”) is now the Trustee of the Trust. The principal office of the Trust is 2911 Turtle Creek Blvd, Suite 850, Dallas, Texas 75219. (Telephone number 855-588-7839). The Trust’s internet web site is www.hgt-hugoton.com. We make available free of charge, through our web site, our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. These reports are accessible through our internet web site as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Information on our website is not incorporated into this report. Effective December 1, 1998, XTO Energy conveyed to the Trust 80% net profits interests in certain predominantly natural gas producing working interest properties in Kansas, Oklahoma and Wyoming under three separate conveyances. In exchange for these net profits interest conveyances to the Trust, 40 million units of beneficial interest were issued to XTO Energy. In April and May 1999, XTO Energy sold a total of 17 million units in the Trust’s initial public offering. In 1999 and 2000, XTO Energy also sold 1.3 million Trust units to certain of its officers. The Trust did not receive the proceeds from these sales of Trust units. In May 2006, XTO Energy distributed all of its remaining 21.7 million Trust units as a dividend to its common stockholders. XTO Energy currently is not a unitholder of the Trust. Units were listed and traded on the New York Stock Exchange under the symbol “HGT” until August 27, 2018, when the Trust units were delisted from the NYSE and began to be quoted on the OTCQX, which is maintained by the OTC Market Group Inc., under the symbol “HGTXU.” On June 25, 2010, XTO Energy became a wholly-owned subsidiary of Exxon Mobil Corporation. The net profits interests entitle the Trust to receive 80% of the net proceeds from the sale of oil and gas from the underlying properties. Each month XTO Energy determines the amount of cash received from the sale of production and deducts property and production taxes, production expense, development costs and overhead. Net proceeds payable to the Trust depend upon production quantities, sales prices of oil and gas and costs to develop and produce oil and gas in the prior month. If monthly costs exceed revenues for any of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds from other conveyances. For further information on excess costs, see Note 4 to Financial Statements under Item 8, Financial Statements and Supplementary Data. The Trust is not liable for any production costs or liabilities attributable to the underlying properties. If at any time the Trust receives net profits income in excess of the amount due, the Trust is not obligated to return such overpayment, but future net profits income payable to the Trust will be reduced until the overpayment, plus interest at the prime rate, is recovered. 2 As a working interest owner, XTO Energy can generally decline participation in any operation and allow consenting parties to conduct such operations, as provided under the operating agreements. XTO Energy also can assign, sell, or otherwise transfer its interest in the underlying properties, subject to the net profits interests, or can abandon an underlying property if it is incapable of producing in paying quantities, as determined by XTO Energy. To the extent allowed, XTO Energy is responsible for marketing its production from the underlying properties terms reasonably obtainable in the under existing sales contracts, or new arrangements on the best circumstances. See “Pricing and Sales Information” under Item 2, Properties. Net profits income received by the Trust on or before the last business day of the month is related to net proceeds received by XTO Energy in the preceding month, and is generally attributable to oil and gas production two months prior. The amount to be distributed to unitholders each month by the Trustee is determined by: Adding - 1. net profits income received; 2. interest income and any other cash receipts; and 3. cash available as a result of reduction of cash reserves; then Subtracting - 1. liabilities paid; and 2. the reduction in cash available related to establishment of or increase in any cash reserve. The monthly distribution amount is distributed to unitholders of record within ten business days after the monthly record date. The monthly record date is generally the last business day of the month. The Trustee calculates the monthly distribution amount and announces the distribution per unit at least ten days prior to the monthly record date. The Trustee may establish cash reserves for contingencies. Cash held for such reserves, as well as for pending payment of the monthly distribution amount, may be invested in federal obligations or certificates of deposit of major banks. The Trustee’s function is to collect the net profits income from the net profits interests, to pay all Trust expenses, and to pay the monthly distribution amount to unitholders. The Trustee’s powers are specified by the terms of the Trust indenture. The Trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments. The Trust has no employees since all administrative functions are performed by the Trustee. Approximately 97% of the net profits income received by the Trust during 2019 was attributable to natural gas. There has historically been a greater demand for gas during the winter months than the rest of the year. Otherwise, Trust income generally is not subject to seasonal factors, nor dependent upon patents, licenses, franchises or concessions. The Trust conducts no research activities. The oil and gas industry is highly competitive in all its phases. Operators of the properties in which the Trust holds interests encounter competition from other oil and gas companies and from individual producers and operators. Oil and natural gas are commodities, for which market prices are determined by external supply and demand factors. Current market conditions are not necessarily indicative of future conditions. Item 1A. Risk Factors The following factors could cause actual results to differ materially from those contained in forward-looking statements made in this report and presented elsewhere by the Trustee from time to time. Such factors may have a material adverse effect upon the Trust’s financial condition, distributable income and changes in trust corpus. 3 The following discussion of risk factors should be read in conjunction with the financial statements and related notes included under Item 8, Financial Statements and Supplementary Data. Because of these and other factors, past financial performance should not be considered an indication of future performance. The Trust may not have sufficient cash to meet its obligations during the one year period after the date that the financial statements are issued and may choose or be required to take other actions to satisfy its obligations by seeking additional financing, which may not be successful. With the exception of net profits income generated by the Wyoming conveyance in March, April and May 2019, all three of the Trust’s conveyances have been in excess costs for the remainder of the year resulting in no net proceeds to the Trust and a reduction in the Trust’s expense reserve. These conditions raise substantial doubt about the Trust’s ability to continue as a going concern as the Trust may not have, based on the current estimated administrative expenses, sufficient cash to meet its obligations during the one year period after the date the financial statements are issued. The Trust’s financial statements do not include any adjustments that might result from the outcome of this uncertainty. There are no assurances that the Trust will receive net profits income sufficient to pay its obligations during the one year period after the date the financial statements are issued, and as a result, may choose or be required to seek additional financing. If the Trust is unable to obtain additional financing and is unable to meet its obligations, the Trust could be forced to consider alternatives such as seeking approval from the unitholders to amend the Trust indenture either to permit the sale of some or all of the net profits interests or approve termination of the Trust. Unitholders could incur significant losses on their investment in the Trust or lose their entire investment in the Trust altogether if the funds obtained from any such sale or liquidation of the net profits interests are such that there are no funds to distribute to unitholders after all financial obligations are met. See Item 7 — Trustee’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources for more information. The market price for the Trust units may not reflect the value of the net profits interests held by the Trust. The public trading price for the Trust units has historically been tied to the recent and expected levels of cash distributions on the Trust units. However, no cash distribution has occurred for 24 months as of the date of this report, March 30, 2020. The amounts available for distribution by the Trust vary in response to numerous factors outside the control of the Trust or XTO Energy, including prevailing prices for oil and natural gas produced from the underlying properties. The market price of the Trust units is not necessarily indicative of the value that the Trust would realize if the net profits interests were sold to a third party buyer. In addition, such market price is not necessarily reflective of the fact that, since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the Trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made to a unitholder over the life of these depleting assets will equal or exceed the purchase price paid by the unitholder or that distributions from the Trust will resume in 2020 or at all. Oil and natural gas prices fluctuate due to a number of uncontrollable factors, and any decline will adversely affect the net proceeds payable to the Trust and Trust distributions. The Trust’s monthly cash distributions are highly dependent upon the prices realized from the sale of natural gas and oil. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and XTO Energy. Factors that contribute to price fluctuations include instability in oil-producing regions, worldwide economic conditions, weather conditions, trade barriers, political instability, public health concerns, the supply of domestic and foreign oil, natural gas and natural gas liquids, consumer demand, the price and availability of alternative fuels, the proximity to, and capacity of, transportation facilities and the effect of worldwide energy conservation measures. Moreover, government regulations, such as regulation of natural gas transportation and price controls, environmental regulations, or trade barriers, can affect product prices. Oil and natural gas prices have declined substantially from historical highs and may not return to those levels in the foreseeable future, if ever. A significant decline in current oil or 4 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 2018 and 2019 and with respect to the properties underlying the Wyoming net profits interests for all of 2018 and most of 2019, and with respect to the properties underlying the Oklahoma net profits interest, the second, third, and fourth quarters of 2018 and all of 2019 primarily due to the drilling of four horizontal wells in Major County, Oklahoma), the Trust will not receive net profits income for those properties until future net proceeds from production in that state exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs. Additionally, XTO Energy has advised the Trustee that total budgeted development costs for the underlying properties are between $1 million and $3 million for 2020 which could continue to exceed revenues for the underlying conveyance. See Item 2 — Properties. As described in Note 8 — Contingencies to the Notes to Financial Statements, XTO Energy has advised the Trustee that it believes a portion of the settlement it has reached in the Chieftain Royalty Company v. XTO Energy Inc. class action lawsuit relates to the Trust. On July 27, 2018, the final plan of allocation was approved by the court. Based on the final plan of allocation, XTO Energy advised the Trustee that it believes approximately $24.3 million in additional production costs should be allocated to the Trust. The Trustee has submitted a demand for arbitration and the arbitration panel has been selected. The hearing on the claims related to the Chieftain settlement has been rescheduled for April 27, 2020. The remaining claims related to the computation of the Trust’s net proceeds were bifurcated and will be heard at a later date, which is still to be determined. If the approximately $24.3 million allocated portion of the Chieftain settlement results in an adjustment to the Trust’s share of net proceeds, it would result in additional excess costs under the Oklahoma conveyance that would likely result in no distributions under the Oklahoma conveyance for several years, or more depending on the results of operations of the underlying properties, while these additional excess costs are recovered. See Item 8 — Financial Statements and Supplementary Data — Notes to Financial Statements — Note 8 — Contingencies for additional information. There may not be an active market for the Trust units. On August 27, 2018, the Trust units were delisted from the NYSE and began to be quoted on the OTCQX, which is maintained by the OTC Market Group Inc., under the symbol “HGTXU.” Trading on the OTCQX is often characterized as thin with sporadic fluctuations in price and the availability of buyers or sellers of a security. No assurance can be given that an active trading market for our Trust units will further develop or continue. The Trust units will likely be subject to greater volatility and lower trading volumes than when the Trust units were listed on the New York Stock Exchange. This could depress the trading price of the Trust units and make it more difficult to purchase, dispose of or obtain accurate quotations as to the value of the Trust units. We currently expect the Trust units will continue to trade on the OTCQX. 5 Proved reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions could cause the quantities and net present value of the reserves to be overstated. Estimating proved oil and gas reserves is inherently uncertain. Petroleum engineers consider many factors and make assumptions in estimating reserves and future net cash flows. Those factors and assumptions include historical production from the area compared with production rates from similar producing areas, the effects of governmental regulation, assumptions about future commodity prices, production expense and development costs, taxes and capital expenditures, the availability of enhanced recovery techniques and relationships with landowners, working interest partners, pipeline companies and others. Lower oil and gas prices generally cause lower estimates of proved reserves. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variances could be material. Because the Trust owns net profits interests, it does not own a specific percentage of the oil and gas reserves. Estimated proved reserves for the net profits interests are based on estimates of reserves for the underlying properties and an allocation method that considers estimated future net proceeds and oil and gas prices. Because Trust reserve quantities are determined using an allocation formula, increases or decreases in oil and gas prices can significantly affect estimated reserves of the net profits interests. Operational risks and hazards associated with the development and operations of the underlying properties may decrease Trust distributions. There are operational risks and hazards associated with the production and transportation of oil and natural gas, leakage of oil or natural gas, including without limitation natural disasters, blowouts, explosions, fires, releases of other hazardous materials, mechanical failures, cratering, and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the environment or natural resources, or cleanup obligations. The operation of oil and gas properties is also subject to various laws and regulations. Non-compliance with such laws and regulations could subject the operator to additional costs, sanctions or liabilities. The uninsured costs resulting from any of the above or similar occurrences could be deducted as a production expense or development cost in calculating the net proceeds payable to the Trust, and would therefore reduce Trust distributions by the amount of such uninsured costs. Future net profits may be subject to risks relating to the creditworthiness of third parties. The Trust does not lend money and has limited ability to borrow money, which the Trustee believes limits the Trust’s risk from exposure to credit markets. The Trust’s future net profits, however, may be subject to risks relating to the creditworthiness of the operators of the underlying properties and other purchasers of crude oil and natural gas produced from the underlying properties. This creditworthiness may be impacted by the price of crude oil and natural gas. Trust unitholders and the Trustee have no influence over the operations on, or future development of, the underlying properties. Neither the Trustee nor the Trust unitholders can influence or control the operation or future development of the underlying properties. The failure of an operator to conduct its operations or discharge its obligations in a proper manner could have an adverse effect on the net proceeds payable to the Trust. Although XTO Energy and other operators of the underlying properties must adhere to the standard of a prudent operator, they are under no obligation to continue operating the properties. Neither the Trustee nor Trust unitholders have the right to replace an operator. 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 6 deplete faster than expected. Eventually, the assets of the Trust will cease to produce in commercial quantities and the Trust will cease to receive proceeds from such assets. The net proceeds payable to the Trust are derived from the sale of hydrocarbons from depleting assets. Future maintenance and development projects on the underlying properties will affect the quantity of proved reserves and can offset the reduction in the depletion of proved reserves. The timing and size of these projects will depend on the market prices of oil and natural gas. If the operator(s) of the properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Trust. Because the net proceeds payable to the Trust are derived from the sale of hydrocarbons from depleting assets, the portion of distributions to unitholders attributable to depletion may be considered a return on capital as opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits available to the unitholders, which could reduce the market value of the units over time. Eventually, the properties underlying the Trust’s net profits interest will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any net proceeds therefrom. XTO Energy drilled four horizontal wells in Major County, Oklahoma during 2018 which are currently producing. There is no guarantee that these wells will produce in commercial quantities sufficient to recoup the investment. Terrorism, geopolitical hostilities, military actions or political instability could adversely affect Trust distributions or the market price of the Trust units. There are a number of national and international events that could cause instability in global financial and energy markets. Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response, impact the demand for and price of oil and natural gas in unpredictable ways, including increasing volatility in pricing. Actual or threatened acts of terrorism and other geopolitical hostilities could adversely affect Trust distributions or the market price of the Trust units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in oil and natural gas prices, or the possibility that the infrastructure on which the operators of the underlying properties rely could be a direct target or an indirect casualty of such an event. XTO Energy may transfer its interest in the underlying properties without the consent of the Trust or the Trust unitholders. XTO Energy may at any time transfer all or part of its interest in the underlying properties to another party. Neither the Trust nor the Trust unitholders are entitled to vote on any transfer of the properties underlying the Trust’s net profits interests, and the Trust will not receive any proceeds of any such transfer. Following any transfer, the transferred property will continue to be subject to the net profits interests of the Trust, but the calculation, reporting and remitting of net proceeds to the Trust will be the responsibility of the transferee. XTO Energy or any other operator of any underlying property may abandon the property, thereby terminating the related net profits interest payable to the Trust. XTO Energy or any other operator of the underlying properties, or any transferee thereof, may abandon any well or property without the consent of the Trust or the Trust unitholders if they reasonably believe that the well or property can no longer produce in commercially economic quantities. This could result in the termination of the net profits interest relating to the abandoned well or property. The net profits interests can be sold and the Trust would be terminated. The Trust will also be terminated if it fails to generate sufficient gross proceeds. The Trust may sell the net profits interests if the holders of 80% or more of the outstanding Trust units approve the sale or vote to terminate the Trust. The Trust will terminate if it fails to generate gross proceeds from 7 the underlying properties of at least $1,000,000 per year over any successive two-year period. Sale of all of the net profits interests will terminate the Trust. The net proceeds of any sale must be for cash with the proceeds less administrative costs promptly distributed to the Trust unitholders. The sale of the remaining net profits interests and the termination of the Trust will be taxable events to the Trust unitholders. Generally, a Trust unitholder will realize gain or loss equal to the difference between the amount realized on the sale and termination of the Trust and his adjusted basis in such units. Gain or loss realized by a Trust unitholder who is not a dealer with respect to such units and who has a holding period for the units of more than one year will be treated as long-term capital gain or loss except to the extent of any depletion recapture amount, which must be treated as ordinary income. Other federal and state tax issues concerning the Trust are discussed under Item 2 and Note 6 to the Trust’s financial statements, which are included herein. Each Trust unitholder should consult his own tax advisor regarding Trust tax compliance matters, including federal and state tax implications concerning the sale of the net profits interests and the termination of the Trust. Trust unitholders have limited voting rights and have limited ability to enforce the Trust’s rights against XTO Energy or any other operator of the underlying properties. The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. Additionally, Trust unitholders have no voting rights in XTO Energy or Exxon Mobil Corporation. The Trust indenture and related trust law permit the Trustee and the Trust to sue XTO Energy or any other operator of the underlying properties to compel them to fulfill the terms of the conveyance of the net profits interests. If the Trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of the Trust unitholders would likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. Trust unitholders probably would not be able to sue XTO Energy or any other operator of the underlying properties. Financial information of the Trust is not prepared in accordance with U.S. GAAP. The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles, or U.S. GAAP. Although this basis of accounting is permitted for royalty trusts by the Securities and Exchange Commission, the financial statements of the Trust differ from U.S. GAAP financial statements because net profits income is not accrued in the month of production, expenses are not recognized when incurred and cash reserves may be established for certain contingencies that would not be recorded in U.S. GAAP financial statements. See Item 8 – Financial Statements and Supplementary Data — Notes to Financial Statements — Note 2 Basis of Accounting and Note 5 Development Costs for additional information. The limited liability of Trust unitholders is uncertain. The Trust unitholders are not protected from the liabilities of the Trust to the same extent that a shareholder would be protected from a corporation’s liabilities. The structure of the Trust does not include the interposition of a limited liability entity such as a corporation or limited partnership which would provide further limited liability protection to Trust unitholders. While the Trustee is liable for any excess liabilities incurred if the Trustee fails to ensure that such liabilities are to be satisfied only out of Trust assets, under the laws of Texas, which are unsettled on this point, a unitholder may be jointly and severally liable for any liability of the Trust if the satisfaction of such liability was not contractually limited to the assets of the Trust and the assets of the Trust and the Trustee are not adequate to satisfy such liability. As a result, Trust unitholders may be exposed to personal liability. The Trust, however, is not liable for production costs or other liabilities of the underlying properties. 8 Drilling oil and natural gas wells is a high-risk activity and subjects the Trust to a variety of factors that it cannot control. Drilling oil and natural gas wells involves numerous risks, including the risk that commercially productive oil and natural gas reservoirs are not encountered. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause drilling activities to be unsuccessful. In addition, there is often uncertainty as to the future cost or timing of drilling, completing and operating wells. Further, development activities may be curtailed, delayed or canceled as a result of a variety of factors, including: 1. 2. 3. 4. 5. 6. 7. 8. reduced oil or natural gas prices; unexpected drilling conditions; title problems; restricted access to land for drilling or laying pipeline; pressure or irregularities in formations; equipment failures or accidents; adverse weather conditions, natural disasters or public health events; and costs of, or shortages or delays in the availability of, drilling rigs, labor, tubular materials and equipment. While these risks do not expose the Trust to liabilities of the drilling contractor or operator of the well, they can reduce net proceeds payable to the Trust and Trust distributions by decreasing oil and gas revenues or increasing production expense or development costs from the underlying properties. Furthermore, these risks may cause the costs of development activities on the underlying properties to exceed the revenues therefrom, thereby reducing net proceeds payable to the Trust and Trust distributions. The underlying properties are subject to complex federal, state and local laws and regulations that could adversely affect net proceeds payable to the Trust and Trust distributions. Extensive federal, state and local regulation of the oil and natural gas industry significantly affects operations on the underlying properties. In particular, oil and natural gas development and production are subject to stringent environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and natural gas wells and other related facilities, which costs could reduce net proceeds payable to the Trust and Trust distributions. These regulations may become more demanding in the future. See Item 2 — Properties – Regulation, and Item 7 — Trustee’s Discussion and Analysis of Financial Condition and Results of Operations – Greenhouse Gas Emissions and Climate Change Regulations. Cash held by the Trustee is not insured by the Federal Deposit Insurance Corporation. Currently, cash held by the Trust reserved for the payment of accrued liabilities and estimated future expenses and distributions to unitholders is typically held in a treasury fund that under normal market conditions invests exclusively in U.S. Treasury obligations. Although the fund’s underlying investments are obligations of the U.S. government, the fund itself is not insured by the Federal Deposit Insurance Corporation. In the event that the fund becomes insolvent, the Trustee may be unable to recover any or all such cash from the insolvent fund. Any loss of such cash may have a material adverse effect on the Trust’s cash balances and any distributions to unitholders. The tax treatment of an investment in Trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis. U.S. federal tax reform legislation informally known as the Tax Cuts and Jobs Act (the “TCJA”) was enacted December 22, 2017, and makes significant changes to the federal income tax rules applicable to both individuals and entities, including changes to the effective tax rate on a Trust unitholder’s allocable share of certain income from the Trust. The TCJA is complex and lacks administrative guidance, thus, Trust unitholders should consult their tax advisor regarding the TCJA and its effect on an investment in Trust units. 9 For taxable years beginning after 2017, the highest marginal U.S. federal income tax rates applicable to ordinary income and long-term capital gains of individuals are 37% and 20%, respectively. Any modification to the U.S. federal income tax laws or interpretations thereof (including administrative guidance relating to the TCJA) may be applied retroactively and could adversely affect our business, financial condition or results of operations. The Trust is unable to predict whether any changes or other proposals will ultimately be enacted, or whether any adverse interpretations will be used. Any such changes or interpretations could negatively impact the value of an investment in the Trust units. Item 1B. Unresolved Staff Comments As of December 31, 2019, the Trust did not have any unresolved Securities and Exchange Commission staff comments. Item 2. Properties The net profits interests are the principal asset of the Trust. The Trustee cannot acquire any other assets, with the exception of certain short-term investments as specified under Item 1, Business. The Trustee may sell or otherwise dispose of all or any part of the net profits interests if approved by a vote of holders of 80% or more of the outstanding Trust units, or upon termination of the Trust. Otherwise, the Trust is required to sell up to 1% of the value of the net profits interests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the related underlying properties. Any sale must be for cash with 80% of the proceeds distributed to the unitholders on the next declared distribution. All the underlying properties are currently owned by XTO Energy. XTO Energy may sell all or any portion of the underlying properties at any time, subject to and burdened by the net profits interests. The underlying properties are predominantly gas-producing properties with established production histories in the Hugoton area of Oklahoma and Kansas, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. The average reserve-to-production index for the underlying properties as of December 31, 2019 is approximately 8 years. This index is calculated using total proved reserves and estimated 2020 production for the underlying properties. The projected 2020 production is from proved developed producing reserves as of December 31, 2019. 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 zero. As reported in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2018, the future net cash flows from proved reserves of the underlying properties as of such date were approximately 64% natural gas and 36% oil. XTO Energy operates approximately 95% of the underlying properties. Because the underlying properties are working interests, production expense, development costs and overhead are deducted in calculating net profits income. As a result, net profits income is affected by the level of maintenance and development activity on the underlying properties. See Trustee’s Discussion and Analysis of Financial Condition and Results of Operations, under Item 7. Total 2019 development costs deducted for the underlying properties were $18.1 million, a decrease of 17% from the prior year. XTO Energy has informed the Trustee that total 2020 budgeted development costs for the underlying properties are between $1 million and $3 million. Changes in oil or natural gas prices could impact future development plans on the underlying properties. Significant Properties Hugoton Area Natural gas was discovered in the Hugoton area in 1922. With an estimated five million productive acres covering parts of Texas, Oklahoma and Kansas, the Hugoton area is one of the largest domestic natural gas producing areas. During 2019, daily sales volumes from the underlying properties in the Hugoton area averaged approximately 7,100 Mcf of gas and 26 Bbls of oil. 10 Most of the production from the underlying properties in the Hugoton area is from the Chase formation. XTO Energy has informed the Trustee that it has begun to develop other formations that underlie the 79,500 net acres held by production by the Chase formation wells, which include the Council Grove, Morrow, Chester and St. Louis formations. These formations are characterized by both oil and gas production from a variety of structural and stratigraphic traps. Prior to 2011, XTO Energy drilled wells to these formations and plans to continue this development program sometime in the future. Within this area, XTO Energy did not drill any new wells but did perform 8 workovers in 2019. XTO Energy has informed the Trustee that it does not plan to drill any new wells but may perform up to 10 workovers during 2020. XTO Energy’s future development plans for the underlying properties in the Hugoton area include: 1. 2. 3. 4. 5. 6. additional compression to lower line pressures; installing artificial lift; opening new producing zones in existing wells; restimulating producing intervals in existing wells utilizing new technology; deepening existing wells to new producing zones; and future drilling of additional wells. Effective May 1, 2014, XTO Energy entered into a gas sales and processing contract with DCP Midstream, L.P. to process all gas production from its wells attached to the Timberland Gathering System in Seward County, Kansas and in Texas and Beaver Counties, Oklahoma. The system collects the majority of its throughput from underlying properties, which XTO Energy has advised the Trustee has been approximately 9,900 Mcf per day. XTO Energy receives 100% of the net value for residue gas based upon a price per MMBtu of Panhandle Eastern Pipe Line Company index. Under this contract DCP is entitled to charge a processing fee of $0.25 per Delivery Point MMBtu and a helium processing fee of $0.05 per 97% Delivery Point Mcf in addition to other deductions such as for fuel and transportation. XTO Energy has exercised its contractual right to take in kind and sell its NGLs and helium. XTO Energy sells 100% of the net value for any recovered NGLs to ONEOK at Conway pricing as posted by Oil Price Information Services minus an adjusted base differential. XTO Energy sells the helium to Air Products and Chemicals, Inc. and Air Products Helium, Inc. under a pricing formula based upon the open market crude helium sales price established by the U.S. Bureau of Land Management. Timberland Gathering & Processing Company, Inc. (“Timberland”), an affiliate of XTO Energy, provides gathering from the wellhead to DCP’s gathering system for a fee of $0.75 per Mcf of gas delivered by XTO Energy. The sales contract with DCP Midstream, L.P. has passed its primary term date of March 31, 2019, and is currently being renewed annually on an evergreen basis, and can be canceled by either party upon 180 days written notice. Other Hugoton gas production is sold under a third party contract that remains in effect for the life of the lease. Under the contract, XTO Energy receives 74.5% of the net proceeds received by the buyer from the sale of the residue gas and liquids produced from certain underlying properties. The residue gas net proceeds are based upon the weighted average price of the gas sold by the buyer at its facilities, and the liquids net proceeds are based upon an average daily index sales price, less transportation, processing and storage fees incurred by the buyer. The buyer agrees to use its best efforts to take all of the gas produced, subject to its market requirements. The buyer has been taking all of the gas produced for over ten years. Anadarko Basin Oil and gas accumulations were discovered in the Anadarko Basin of western Oklahoma in 1945. XTO Energy is one of the largest producers in the Ringwood, Northwest Okeene and Cheyenne Valley fields of Major County, the Northeast Cedardale field of Woodward County and the Elk City field of Beckham County, the principal producing regions of the underlying properties in the Anadarko Basin. Daily sales volumes from the underlying properties in the Anadarko Basin averaged 13,200 Mcf of gas and 781 Bbls of oil in 2019. 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, 11 Hunton and Arbuckle formations. Within this area, XTO Energy completed the 4 new horizontal wells and performed 17 workovers in 2019. XTO Energy has informed the Trustee that it does not plan to drill any new wells but may perform up to 20 workovers in Major County during 2020. 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 1 workover in 2019. 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 2020. The Elk City field on the eastern edge of Beckham County produces oil and gas from a structural anticline with stratigraphic trapping features. Production zones include the Hoxbar, Atoka and Morrow formations. Within this area, XTO Energy did not drill any wells or perform any workovers in 2019. XTO Energy has informed the Trustee that it does not plan to drill any new wells but may perform up to 5 workovers within the Elk City field during 2020. XTO Energy plans to further develop the underlying properties in the Anadarko Basin primarily through: 1. mechanical stimulation of existing wells; 2. 3. 4. 5. installing artificial lift; opening new producing zones in existing wells; deepening existing wells to new producing zones; and future drilling of additional wells. A gathering subsidiary of XTO Energy operates a 300-mile gathering system and pipeline in the Major County area. The gathering subsidiary and a third-party processor purchase natural gas produced at the wellhead from XTO Energy and other producers in the area under various agreements, most of which were entered into in the 1960’s and 1970’s, and which include life-of-production terms such that the contracts will continue until there is no further production from the underlying properties, unless the production declines so that it is no longer economical to take the gas. The gathering subsidiary and the third-party processor are required to take certain minimum volumes of the gas produced but have been taking all of the volumes produced for over ten years. The gathering subsidiary gathers and transports the gas to a third-party processor, which processes the gas and pays XTO Energy and other producers for at least 50% of the liquids processed based upon a weighted average sales price less transportation charges, which price may vary in the event of inadequate markets. After the gas is processed, the gathering subsidiary transports the gas via a residue pipeline to a connection with an interstate pipeline. The gathering subsidiary pays XTO Energy for the residue gas based upon a weighted average price from downstream sales to third parties, which price will vary monthly based upon market conditions. The gathering subsidiary pays this price to XTO Energy less a compression and gathering fee of approximately $0.31 per Mcf of residue gas. This gathering fee was previously approved by the Federal Energy Regulatory Commission when the gathering subsidiary was regulated. As of December 31, 2019, the gathering system was collecting approximately 8,200 Mcf per day, approximately 70% of which are operated by XTO Energy. Estimated capacity of the gathering system is 24,000 Mcf per day. The gathering subsidiary also provides contract operating services to properties in Woodward County, collecting approximately 2,800 Mcf per day, for an average fee of approximately $0.34 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. 12 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 2019 sales volumes from the underlying properties in the Fontenelle field averaged 10,100 Mcf of natural gas and 20 Bbls of oil. XTO Energy did not drill any new wells or perform any workovers in the Green River Basin in 2019. XTO Energy has advised the Trustee that it does not plan to drill any new wells or perform any workovers in the Green River Basin during 2020. 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 2020 to assist with disposal in the Fontenelle field. Potential development activities for the underlying properties in this area include: 1. 2. 3. 4. installing artificial lift; restimulating producing intervals utilizing new technology; additional compression to lower line pressures; and opening new producing zones in existing wells. XTO Energy markets the gas produced from the Fontenelle field and nearby properties under various marketing arrangements. Under the agreement covering the majority of the gas sold, XTO Energy compresses the gas on the lease, transports it off the lease and compresses the gas again prior to entry into the gas plant pipeline. The pipeline transports the gas to the gas plant, where the gas is processed, then redelivered to XTO Energy. The owner of the gas plant and related pipeline charges XTO Energy for operational fuel and processing and has agreed to accept certain volumes, which amounts can be adjusted by the owner. The owner may be able to cease taking volumes if it has valid unaddressed concerns regarding the creditworthiness of XTO Energy. In 2019, the fuel charge was approximately 1% of the volumes produced and the fee was approximately $0.12 per MMBtu. These charges are adjusted annually based upon a published governmental economic index, and the contract renews on a year-to-year basis. XTO Energy transports and sells this gas directly to the markets based on a spot sales price on a month-to-month term, and the volumes to be sold are generally determined upon a monthly basis. These contracts may be terminated by either party if there are credit issues with the other party. The gas not sold under the above arrangement may be gathered and sold under a similar arrangement on a month-to-month term where the fee is approximately $0.20 per MMBtu and is adjusted annually. The amount of gas that the gatherer is required to gather is limited to certain maximum volumes, and the gatherer may be able to cease taking volumes if it has valid unaddressed concerns regarding the creditworthiness of XTO Energy. Alternatively, the gas may be sold under a contract where XTO Energy directly sells the gas to a third party on the lease at an adjusted index price, which price varies upon market conditions. The contract continues on a month-to-month basis, and the buyer is obligated to make a good faith effort to purchase a minimum 90% of the gas nominated by buyer for purchase. Condensate is sold to an independent third party at market rates on a month-to-month basis. The purchaser accepts all condensate delivered at the lease, but either party may suspend performance of the contract if there are credit issues with the other party. Producing Acreage, Drilling and Well Counts For the following data, “gross” refers to the total wells or acres on the underlying properties in which XTO Energy owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working is interest owned by XTO Energy. Although many of XTO Energy’s wells produce both oil and gas, a well categorized as an oil well or a gas well based upon the ratio of oil to natural gas production. Operated wells are managed by XTO Energy, while non-operated wells are managed by others. 13 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, 2019. Undeveloped acreage is not significant. Hugoton Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Anadarko Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Green River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 202,374 157,821 32,233 190,311 122,533 25,570 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 392,428 338,414 Gross Net The following is a summary of the producing wells on the underlying properties as of December 31, 2019: Operated Wells Non-operated Wells Total(a) Gross Net Gross Net Gross Net Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil 1,097.0 41.0 980.0 37.2 227.0 9.0 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,138.0 1,017.2 236.0 50.8 1.2 52.0 1,324.0 50.0 1,030.8 38.4 1,374.0 1,069.2 (a) During 2019, 2018 and 2017 there were no exploratory or dry wells drilled on the underlying properties. There were 7 gross (3.16 net), 2 gross (0.11 net) and 1 gross (0.0 net) developmental wells drilled in 2019, 2018 and 2017, respectively. 14 Estimated Proved Reserves and Future Net Cash Flows The following are proved reserves of the underlying properties, as estimated by independent engineers, and proved reserves and future net cash flows from proved reserves of the net profits interests, based on an allocation of these reserves, at December 31, 2019: Underlying Properties Proved Reserves(a) Oil Gas (Bbls) (Mcf) Net Profits Interests Proved Reserves(a)(b) Gas (Mcf) Oil (Bbls) Future Net Cash Flows from Proved Reserves(a)(c) Undiscounted Discounted (in thousands) Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50,946 26,603 2,624 TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . 80,173 1,468 40 72 1,580 – – – – – – – – $ – – – $ – $ – – – $ – (a) Based on 12-month average oil price of $53.20 per Bbl and $1.88 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, 2019 consist of the following: Underlying Properties Proved Reserves Oil (Bbls) Gas (Mcf) Net Profits Interests Proved Reserves Oil (Bbls) Gas (Mcf) (in thousands) Proved developed reserves . . . . . . . . . . . . . . . . . . . . . . . Proved undeveloped reserves . . . . . . . . . . . . . . . . . . . . . Proved non-producing reserves . . . . . . . . . . . . . . . . . . . Total proved reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79,204 716 253 80,173 1,580 – – 1,580 – – – – – – – – Approximately 99% of the underlying proved reserves are proved developed reserves. The process of estimating oil and gas reserves is complex and requires significant judgment as discussed in Item 1A, Risk Factors, and is performed by XTO Energy. As a result, XTO Energy has developed internal policies and controls for estimating and recording reserves. XTO Energy’s policies regarding booking reserves require proved reserves to be in compliance with the SEC definitions and guidance. XTO Energy’s policies assign responsibilities for compliance in reserves bookings to its reserve engineering group and require that reserve estimates be made by qualified reserves estimators, as defined by the Society of Petroleum Engineers’ standards. All qualified reserves estimators are required to receive education covering the fundamentals of SEC proved reserves assignments. The XTO Energy reserve engineering group reviews reserve estimates with third-party petroleum consultants, Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents, Ltd. estimated oil and gas reserves attributable to the underlying properties as of December 31, 2019, 2018, 2017 and 2016. Miller and Lents’ 15 primary technical person responsible for calculating the Trust’s reserves has more than ten years of experience as a reserve engineer. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests. Numerous uncertainties are inherent in estimating reserve volumes and values, and such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimates. Reserve quantities and revenues for the net profits interests were estimated from projections of reserves and revenues attributable to the underlying properties. Since the Trust has defined net profits interests, the Trust does not own a specific percentage of the oil and gas reserves. Oil and gas reserves are allocated to the net profits interests by dividing Trust net cash inflows by 12-month average oil and gas prices. Oil and Natural Gas Production Trust production is recognized in the period net profits income is received, which is the month following receipt by XTO Energy, and generally two months after the time of production. Oil and gas sales volumes are allocated to the net profits interests based upon a formula that considers oil and gas prices and the total amount of production expense and development costs. As such, the underlying property production volume changes may not correlate with the Trust’s net profit share of those volumes in any given period. Oil and gas production and average sales prices attributable to the underlying properties and the net profits interests for each of the two years ended December 31 were as follows: 2019 2018 Production Underlying Properties Gas – Sales (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . Average per day (Mcf) . . . . . . . . . . . . . . . . . . Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average per day (Bbls) 11,112,535 30,445 302,040 828 12,994,466 35,601 155,334 426 Net Profits Interests Gas – Sales (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . Average per day (Mcf) . . . . . . . . . . . . . . . . . . Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average per day (Bbls) Average Sales Price . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas (per Mcf) Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109,541 300 249 1 $ 2.95 $ 53.60 447,961 1,227 7,627 21 $ 2.69 $ 62.69 Average Production Cost per BOE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 15.13 $ 12.83 16 Oil and gas production by conveyance attributable to the underlying properties for each of the two years ended December 31 were as follows: Conveyance Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Underlying Gas Production (Mcf) 2019 868,947 6,572,242 3,671,346 2018 1,077,152 7,988,035 3,929,279 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,112,535 12,994,466 Conveyance Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Underlying Oil Production (Bbls) 2019 6,102 288,662 7,276 302,040 2018 8,621 138,880 7,833 155,334 Pricing and Sales Information XTO Energy sells most of its natural gas production directly to third parties, and a portion is sold to certain of XTO Energy’s wholly-owned subsidiaries based on a weighted average sales price. The weighted average sales price received from the subsidiary is based upon sales to third parties for the best available price. Oil production is generally marketed at the wellhead to third parties at the best available price. XTO Energy arranges for some of its natural gas to be processed by unaffiliated third parties and markets the natural gas liquids. Some of the natural gas attributable to the underlying properties is marketed under contracts existing at Trust inception. Contracts covering production from the Ringwood area of the Major County area are generally for the life of the lease. The contract with an unaffiliated third party for the majority of production from the Hugoton area is in effect through the life of the lease. If new contracts are entered with unaffiliated third parties, the proceeds from sales under those new contracts will be included in gross proceeds from the underlying properties. If new contracts are entered with any subsidiary of XTO Energy, it may charge XTO Energy a fee that may not exceed 2% of the sales price of the oil and natural gas received from unaffiliated parties. The sales price is net of any deductions for transportation from the wellhead to the unaffiliated parties and any gravity or quality adjustments. For further information on these arrangements see Significant Properties above. Regulation Natural Gas Regulation The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation and storage rates charged, tariffs, and various other matters, by the Federal Energy Regulatory Commission. Federal price controls on wellhead sales of domestic natural gas terminated on January 1, 1993. While natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act, including enforcement rules and new annual reporting requirements for certain sellers of natural gas. It is impossible to predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, such proposals might have on the operations of the underlying properties. 17 Federal Regulation of Oil Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The net price received from the sale of these products is affected by market transportation costs. Under rules adopted by FERC effective January 1995, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. On December 19, 2007, the President signed into law the Energy Independence & Security Act of 2007 (PL 110-140). The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder. XTO Energy has advised the Trustee that it cannot predict the impact of future government regulation on any crude oil, condensate or natural gas liquids facilities, sales or transportation transactions. Environmental Regulation Companies that are engaged in the oil and gas industry are affected by federal, state and local laws regulating the discharge of materials into the environment. Those laws may impact operations of the underlying properties. No material expenses have been incurred on the underlying properties in complying with environmental laws and regulations. XTO Energy does not expect that future compliance will have a material adverse effect on the Trust. There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change. Several states have adopted climate change legislation and regulations, and various other regulatory bodies have announced their intent to regulate GHG emissions or adopt climate change regulations. As these regulations are under development, XTO Energy is unable to predict the total impact of the potential regulations upon the operators of the underlying properties, and it is possible that operators of the underlying properties could face increases in operating costs in order to comply with climate change or GHG emissions legislation, which costs could reduce net proceeds payable to the Trust and Trust distributions. State Regulation The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rates of production may be regulated and the maximum daily production allowables from both oil and gas wells may be established on a market demand or conservation basis, or both. Federal Income Taxes For federal income tax purposes, the Trust constitutes a fixed investment trust that is taxed as a grantor trust. A grantor trust is not subject to tax at the trust level. The unitholders are considered to own the Trust’s income and principal as though no trust were in existence. The income of the Trust is deemed to have been received or accrued by each unitholder at the time such income is received or accrued by the Trust and not when distributed by the Trust. Impairment for book purposes will not result in a loss for tax purposes for the unitholders until the loss is recognized. Because the Trust is a grantor trust for federal tax purposes, each unitholder is taxed directly on his proportionate share of income, deductions and credits of the Trust consistent with each such unitholder’s taxable year and method of accounting and without regard to the taxable year or method of accounting employed by the 18 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 2019, the Trust incurred administration expenses and earned interest income on funds held for distribution and for the cash reserve maintained for the payment of contingent and future obligations of the Trust. The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the units each month based upon the ownership of the Trust units on the monthly record date, instead of on the basis of the date a particular unit is transferred. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the unitholders affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods. The net profits interests constitute “economic interests” in oil and gas properties for federal tax purposes. Each unitholder is entitled to amortize the cost of the units through cost depletion over the life of the net profits interests or, if greater, through percentage depletion equal to 15 percent of gross income, limited to 100% of the net income from such net profits interest. Unlike cost depletion, percentage depletion is not limited to a unitholder’s depletable tax basis in the units. Rather, a unitholder is entitled to a percentage depletion deduction as long as the applicable underlying properties generate gross income. Unitholders should compute both percentage depletion and cost depletion from each property and claim the larger amount as a deduction on their income tax returns. Unitholders must maintain records of their adjusted basis in their Trust units (generally his or her cost less prior depletion deductions), make adjustments for depletion deductions to such basis, and use the adjusted basis for the computation of gain or loss on the disposition of the Trust units. If a taxpayer disposes of any “Section 1254 property” (certain oil, gas, geothermal or other mineral property), and the adjusted basis of such property includes adjustments for depletion deductions under Section 611 of the Internal Revenue Code (the “Code”), the taxpayer generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain realized on such disposition). This depletion recapture rule applies to any disposition of Section 1254 property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury Regulations govern dispositions of property after March 13, 1995. Interest and net profits income attributable to ownership of units and any gain on the sale thereof are considered portfolio income, and not income from a “passive activity,” to the extent a unitholder acquires and holds units as an investment and not in the ordinary course of a trade or business. Therefore, interest and net profits income attributable to ownership of units generally may not be offset by losses from any passive activities. Under the “TCJA” for tax years beginning after December 31, 2017 and before January 1, 2026, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37%, and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is 20%. Under the TCJA, for such tax years, personal exemptions and miscellaneous itemized deductions are not allowed. For such tax years, the U.S. federal income tax rate applicable to corporations is 21%, and such rate applies to both ordinary income and capital gains. Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts. For these purposes, investment income generally will include a unitholder’s allocable share of the Trust’s interest and royalty income plus the gain recognized from a sale of Trust units. In the case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such individual’s federal income tax filing status. In the case of an estate or trust, the tax is imposed 19 on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins. The difference between the per-unit taxable income for any period and the per-unit cash distributions, if any, reported for such period is attributable to (i) items that reduce cash distributions but are not currently deductible, such as an increase in the cash reserve maintained by the Trust for the payment of future expenditures; (ii) the current deduction of expenses that are paid with amounts previously reserved; (iii) items that increase cash distributions but do not constitute taxable income, such as a decrease in the cash reserve maintained by the Trust and/or a return of capital; and (iv) items that constitute taxable income due to the recovery of prior period expense adjustments. Because of these types of items and when the Trustee elects to reserve amounts from monthly distributions to maintain an administrative expense reserve, the taxable income per period frequently differs from the actual amount distributed to unitholders. Individuals may also incur expenses in connection with the acquisition or maintenance of Trust units. For tax years beginning before January 1, 2018, these expenses, which are different from a unitholder’s share of the Trust’s administrative expenses discussed above, may be deductible as “miscellaneous itemized deductions” only to the extent that such expenses exceed 2 percent of the individual’s adjusted gross income. Under the TCJA, for tax years beginning after December 31, 2017 and before January 1, 2026, miscellaneous itemized deductions are not allowed. Pursuant to the Foreign Account Tax Compliance Act (commonly referred to as “FATCA”), distributions from the Trust to “foreign financial institutions” and certain other “non-financial foreign entities” may be subject to U.S. withholding taxes. Specifically, certain “withholdable payments” (including certain royalties, interest and other gains or income from U.S. sources) made to a foreign financial institution or non-financial foreign entity will generally be subject to the withholding tax unless the foreign financial institution or non-financial foreign entity complies with certain information reporting, withholding, identification, certification and related requirements 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, 2911 Turtle Creek Blvd, Suite 850, Dallas, Texas, 75219, telephone number 1-855-588-7839, email address Trustee@hgt-hugoton.com, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.hgt-hugoton.com. Notwithstanding the foregoing, the middlemen holding Trust units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such Trust units, including the issuance of IRS Forms 1099 and certain written tax 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. 20 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 2019 tax year because the Trust had no revenues, income or deductions in 2019 attributable to properties located in Kansas. The Trust did not file a return with Kansas for the 2018 and 2017 tax years for the same reason. Wyoming does not impose a state income tax. Each unitholder should consult his or her own tax advisor regarding state income tax requirements, if any, applicable to such person’s ownership of Trust units. State Tax Withholding Several states have enacted legislation requiring state income tax withholding from payments to nonresident recipients of oil and gas proceeds. After consultation with its tax counsel, the Trustee believes that it is not required to withhold on payments made to the unitholders. However, regulations are subject to change by the various states, which could change this conclusion. Should amounts be withheld on payments made to the Trust or the unitholders, distributions to the unitholders would be reduced by the required amount, subject to the filing of a claim for refund by the Trust or unitholders for such amount. Other Regulation The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws, including, but not limited to, regulations and laws relating to environmental protection, occupational safety, resource conservation and equal employment opportunity. XTO Energy has advised the Trustee that it does not believe that compliance with these laws will have any material adverse effect upon the unitholders. Item 3. Legal Proceedings As previously disclosed, XTO Energy advised the Trustee that it reached a settlement with the plaintiffs in the Chieftain class action royalty case. On July 27, 2018 the final plan of allocation was approved by the court. Based on the final plan of allocation XTO Energy has advised the Trustee that it believes approximately $24.3 million in additional production costs should be allocated to the Trust. On May 2, 2018, the Trustee submitted a demand for arbitration seeking a declaratory judgment that the Chieftain settlement is not a production cost and that XTO Energy is prohibited from charging the settlement as a production cost under the conveyance or otherwise reducing the Trust’s payments now or in the future as a result of the Chieftain litigation. The hearing on the claims related to the Chieftain settlement has been rescheduled for April 27, 2020. Other Trustee claims related to disputed amounts on the computation of the Trust’s net proceeds for 2014 through 2016 were bifurcated from the issues regarding XTO’s right to charge the Chieftain settlement as a production cost and will be heard at a later date, which is still to be determined. 21 If the approximately $24.3 million allocated portion of the Chieftain settlement results in an adjustment to the Trust’s share of net proceeds, it would result in additional excess costs under the Oklahoma conveyance that would likely result in no distributions under the Oklahoma conveyance for several years, or more depending on the results of operations of the underlying properties, while these additional excess costs are recovered. Certain of the underlying properties are involved in various other lawsuits and governmental proceedings arising in the ordinary course of business. XTO Energy has advised the Trustee that it does not believe that the ultimate resolution of these claims will have a material effect on the financial position or liquidity of the Trust, but may have an effect on annual distributable income. Item 4. Mine Safety Disclosures Not Applicable. 22 PART II Item 5. Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units Units of Beneficial Interest The units of beneficial interest in the Trust began trading on the New York Stock Exchange on April 9, 1999 under the symbol “HGT.” On August 27, 2018, the Trust units were delisted from the NYSE and began to be quoted on the OTCQX, which is maintained by the OTC Market Group Inc., under the symbol “HGTXU.” Any quotations on the OTCQX reflect inter-dealer prices, without retail mark-up, mark-down, or commission and may not necessarily reflect actual transactions. At March 4, 2020, there were 40,000,000 units outstanding and approximately 582 unitholders of record; 39,784,711 of these units were held by depository institutions. The Trust has no equity compensation plans, nor has it purchased any units during the period covered by this report. See “Item 1. Business” for a description of the Trustee’s obligations to make monthly distributions and how the monthly distribution amount is determined under the indenture. Item 6. Selected Financial Data Not required for smaller reporting companies; the Trust has elected to omit this information. 23 Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations Calculation of Net Profits Income The following is a summary of the calculation of net profits income received by the Trust: Year Ended December 31(a) 2018 2019 Three Months Ended December 31(a) 2019 2018 Sales Volumes Gas (Mcf)(b) Underlying properties . . . . . . . . . . . . . . . . . . Average per day . . . . . . . . . . . . . . . . . . . . Net profits interests . . . . . . . . . . . . . . . . . . . 11,112,535 30,445 109,541 12,994,466 35,601 447,961 Oil (Bbls)(b) Underlying properties . . . . . . . . . . . . . . . . . . Average per day . . . . . . . . . . . . . . . . . . . . Net profits interests . . . . . . . . . . . . . . . . . . . 302,040 828 249 155,334 426 7,627 2,969,373 32,276 — 145,683 1,584 — 3,265,229 35,492 — 34,666 377 — Average Sales Prices Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil (per Bbl) $ $ 2.95 53.60 $ $ 2.69 62.69 $ $ 2.21 53.39 $ $ 2.68 67.99 Revenues Gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 32,762,489 16,189,356 $ 34,963,154 9,737,686 $ 6,555,147 7,777,550 $ 8,765,079 2,356,923 Total Revenues . . . . . . . . . . . . . . . . . . . . . . . 48,951,845 44,700,840 14,332,697 11,122,002 Costs Taxes, transportation and other . . . . . . . . . . . . Production expense . . . . . . . . . . . . . . . . . . . . . Development costs(c) . . . . . . . . . . . . . . . . . . . . Overhead . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Excess costs(d) . . . . . . . . . . . . . . . . . . . . . . . . . . 10,208,162 21,041,901 18,051,637 11,549,455 (12,361,133) 8,178,584 18,131,944 21,802,500 11,636,835 (17,037,709) 2,725,253 6,121,091 1,319,473 3,289,159 877,721 2,060,152 4,349,947 7,837,500 2,917,565 (6,043,162) Total Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . 48,490,022 42,712,154 14,332,697 11,122,002 Net Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net Profits Percentage . . . . . . . . . . . . . . . . . . . . . 461,823 80% 1,988,686 80% Net Profits Income . . . . . . . . . . . . . . . . . . . . . . . . $ 369,458 $ 1,590,949 $ — 80% — $ — 80% — (a) Because of the two-month interval between time of production and receipt of net profits income by the Trust: 1) oil and gas sales for the year ended December 31 generally relate to twelve months of production for the period November through October, and 2) oil and gas sales for the three months ended December 31 generally relate to production for the period August through October. (b) Oil and gas sales volumes are allocated to the net profits interests by dividing Trust net cash inflows by average sales prices. As oil and gas prices change, the Trust’s allocated production volumes are impacted as the quantity of production necessary to cover expenses changes inversely with price. As such, the underlying property production volume changes may not correlate with the Trust’s allocated production volumes in any given period. Therefore, comparative discussion of oil and gas sales volumes is based on the underlying properties. (c) See Note 5 to Financial Statements under Item 8, Financial Statements and Supplementary Data. (d) See Note 4 to Financial Statements under Item 8, Financial Statements and Supplementary Data. 24 Results of Operations Years Ended December 31, 2019 and 2018 Net profits income for 2019 was $369,458, as compared with $1,590,949 for 2018. The 77% decrease in net profits income from 2018 to 2019 was primarily the result of decreased gas production ($4.4 million), net excess costs activity ($3.7 million), increased production expenses ($2.3 million), increased taxes, transportation and other costs ($1.6 million), and lower oil prices ($1.1 million), partially offset by increased oil production ($6.3 million), decreased development costs ($3.0 million), and higher gas prices ($2.6 million). Approximately 97% in 2019 and 75% in 2018 of net profits income was derived from natural gas sales. Trust administration expense was $913,398 in 2019 as compared to $1,115,904 in 2018. Net cash reserve activity was $522,511 in 2019 and $128,157 in 2018. Cash reserve activity for 2019 included partial replenishment of $212,706, offset by utilization of $735,217 for the payment of trust expenses. Interest income was $21,429 in 2019 and $23,152 in 2018. Changes in interest income are attributable to fluctuations in net profits income and interest rates. Distributable income was $0 or $0.000000 per unit in 2019 and $370,040 or $0.009251 per unit in 2018. Net profits income is recorded when received by the Trust, which is the month following receipt by XTO Energy, and generally two months after oil and gas production. Net profits income is generally affected by three major factors: 1. 2. 3. oil and gas sales volumes; oil and gas sales prices; and costs deducted in the calculation of net profits income. Volumes Gas. From 2018 to 2019, underlying gas sales volumes decreased 14% primarily due to natural production decline, timing of cash receipts and a change to account for a portion of gas sales as residue that were previously accounted for at the wellhead (which did not affect the net profits income received by the Trust), partially offset by gas sales from new wells in Major County, Oklahoma. Oil. From 2018 to 2019, underlying oil sales volumes increased 94% primarily due to oil sales from new wells in Major County, Oklahoma, and timing of cash receipts partially offset by natural production decline. The estimated rate of natural production decline on the underlying oil and gas properties is approximately 6% to 8% a year. Prices Gas. The 2019 average gas price was $2.95 per Mcf, up 10% from the 2018 average gas price of $2.69 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 2019 through January 2020 was $2.41 per MMBtu. At March 20, 2020, the average NYMEX gas price for the following 12 months was $2.10 per MMBtu. Oil. The average oil price for 2019 was $53.60 per Bbl, down 14% from the average oil price for 2018 of $62.69 per Bbl. Oil prices are expected to remain volatile. The average NYMEX price for November 2019 through January 2020 was $58.30 per Bbl. At March 20, 2020, the average NYMEX oil price for the following 12 months was $28.65 per Bbl. Costs The calculation of net profits income includes deductions for production expense, development costs and overhead since the related underlying properties are working interests. 25 Taxes, transportation and other. Taxes, transportation and other generally fluctuates with changes in total revenues. Taxes, transportation and other increased 25% from 2018 to 2019 primarily because of increased gas deductions related to certain adjustments previously included in gas sales revenue that are now recorded in this line item and increased production taxes related to higher oil revenues, partially offset by decreased production taxes related to lower gas revenues. Production expense. Production expense increased 16% from 2018 to 2019 primarily because of reporting of expense well work activity previously reported in development costs and other higher operating expenses in all three conveyances. Development costs. Development costs charged to the Trust were $18.1 million in 2019 and $21.8 million in 2018. The monthly deduction is based on the current level of development expenditures, budgeted future development costs and the cumulative actual costs under (over) previous deductions. Changes in oil or natural gas prices could impact future development plans on the underlying properties. Subsequent to June 30, 2019, XTO Energy has advised the Trustee that the budgeted development cost accrual was fully depleted as of the July 2019 distribution. XTO Energy also had previously advised the Trustee that once the accrual was fully depleted, development costs were charged to the Trust as they are incurred for all conveyances. XTO Energy has advised the Trustee that drilling in Major County, Oklahoma is complete and resulted in cost overruns due to unforeseen expenditures that were charged to the Trust in the third quarter of 2019. XTO Energy has advised the Trustee that this monthly deduction will continue to be evaluated and revised as necessary. For further information on development costs, see Note 5 to Financial Statements under Item 8, Financial Statements and Supplementary Data. Overhead. Overhead is charged by XTO Energy and other operators for administrative expenses incurred to support operations of the underlying properties. Overhead fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well as an annual cost level adjustment. Excess costs. If monthly costs exceed revenues for any conveyance, these excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from another conveyance. Underlying cumulative excess costs for the Kansas, Oklahoma and Wyoming conveyances remaining as of December 31, 2019 totaled $31.2 million ($25.0 million NPI), including accrued interest of $1.0 million ($0.8 million NPI). For further information on excess costs, including the balance and accrued interest by conveyance, see Note 4 to Financial Statements under Item 8, Financial Statements and Supplementary Data. Fourth Quarter 2019 and 2018 During fourth quarter 2019 the Trust received net profits income totaling $0 compared with fourth quarter 2018 net profits income of $0 primarily due to decreased development costs ($5.2 million), increased oil production ($4.7 million), partially offset by net excess costs activity ($5.5 million), lower oil and gas prices ($1.7 million), increased production expenses ($1.4 million), increased taxes, transportation and other costs ($0.5 million), decreased gas production ($0.5 million), and increased overhead ($0.3 million). After adding interest income of $3,800, deducting administration expense of $238,379 and utilizing the cash reserve $234,579 for the payment of Trust expenses, distributable income for fourth quarter 2019 was $0 or $0.000000 per unit. Distributable income for fourth quarter 2018 was $0 or $0.000000 per unit. 26 Distributions to unitholders for the quarter ended December 31, 2019 were: Record Date Payment Date October 31, 2019 November 29, 2019 December 31, 2019 November 15, 2019 December 13, 2019 January 15, 2020 Per Unit $0.000000 0.000000 0.000000 $0.000000 Volumes Fourth quarter underlying gas sales volumes decreased 9% from 2018 to 2019 primarily due to natural production decline, timing of cash receipts and a change to account for a portion of gas sales as residue that were previously accounted for at the wellhead (which did not affect the net profits income received by the Trust), partially offset by gas sales from new wells in Major County, Oklahoma. Underlying oil sales volumes increased 320% from 2018 to 2019 primarily due to oil sales from new wells in Major County, Oklahoma, and timing of cash receipts partially offset by natural production decline. Prices The average fourth quarter 2019 gas price was $2.21 per Mcf, down 18% from the fourth quarter 2018 average price of $2.68 per Mcf. The average fourth quarter 2019 oil price was $53.39 per Bbl, down 21% from the fourth quarter 2018 average price of $67.99 per Bbl. For further information about product prices, see “Years Ended December 31, 2019 and 2018 – Prices” above. Costs Taxes, transportation and other. Taxes, transportation and other increased 32% from fourth quarter 2018 to 2019 primarily because of increased gas deductions related to certain adjustments previously included in gas sales revenue that are now recorded in this line item and increased production taxes related to higher oil revenues, partially offset by decreased production taxes related to lower gas revenues. Production expense. Fourth quarter production expense increased 41% from 2018 to 2019 primarily because of reporting of expense well work activity previously reported in development costs and other higher operating expenses in all three conveyances. Development costs. Development costs deducted are based on the current level of development expenditures, budgeted future development costs and the cumulative actual costs under (over) previous deductions. The development costs decreased 83% from fourth quarter 2018 to 2019, primarily due to the decrease in the development budget for the drilling of four horizontal wells in Major County, Oklahoma, completed in 2019. For further information on development costs, see Note 5 to Financial Statements under Item 8, Financial Statements and Supplementary Data. Overhead. Overhead is charged by XTO Energy and other operators for administrative expenses incurred to support operations of the underlying properties. Overhead fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well as an annual cost level adjustment. Excess costs. If monthly costs exceed revenues for any conveyance, these excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from another conveyance. For information on excess costs, including the excess cost balance and accrued interest by conveyance, see Note 4 to Financial Statements under Item 8, Financial Statements and Supplementary Data. 27 Liquidity and Capital Resources The Trust’s only cash requirement is any declared monthly distribution of its income to unitholders, which is funded by the monthly receipt of net profits income after payment of Trust administration expenses. The Trust is not liable for any production costs or liabilities attributable to the net profits interests. If at any time the Trust receives net profits income in excess of the amount due, the Trust is not obligated to return such overpayment, but future net profits income payable to the Trust will be reduced by the overpayment, plus interest at the prime rate. The Trust may borrow funds required to pay Trust liabilities if fully repaid prior to further distributions to unitholders. The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources. The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. Financial statements prepared on a going concern basis assume the realization of assets and the settlement of liabilities in the normal course of business. Increases in excess costs for the Kansas, Oklahoma and Wyoming conveyances have resulted in no net proceeds to the Trust for the last nine months of 2018 and a reduction in the Trust’s expense reserve. In March through May of 2019, the Trust received net profits income from the Wyoming conveyance in an amount that covered all of the Trust’s administrative expenses and allowed for a partial replenishment of the expense reserve, but there were no funds to distribute to unitholders. The net profits income in these months are not necessarily indicative of future cash inflows for the next 12 months. These conditions raise substantial doubt about the Trust’s ability to continue as a going concern as the Trust may not have, based on the current estimated administrative expenses, sufficient cash to meet its obligations during the one year period after the date the financial statements are issued. Factors attributable to the potential cash shortage are primarily the previously disclosed increase in development costs to drill four horizontal wells in Major County, Oklahoma (actual cost incurred through fourth quarter 2019 are $27.6 million net to the Trust) which have created an excess cost position on the Oklahoma conveyance. Additionally, excess cost positions on the Kansas and Wyoming conveyances have resulted in no net proceeds to the Trust from the Kansas conveyance for all of 2018 and 2019 and no net proceeds to the Trust from the Wyoming conveyance for all of 2018 and 2019, with the exception of the March 2019 through May 2019 distributions. The Trustee has prepared a preliminary budget estimating the administrative expenses for the year ending December 31, 2020 and the three months ending March 31, 2021 which assumes no cash inflow from either net profits income or from other sources. This budget estimates that the expense reserve will be depleted by approximately June 2020. If either income or expenses differ from the assumptions in the Trustee’s preliminary budget, this date may be sooner or later than the estimate. The Trustee is currently seeking financing to pay the Trust obligations during the one year period after the date the financial statements are issued once the expense reserve funds have been depleted. This outcome would ensure that the Trust could continue as a going concern; however, there is no assurance that such additional financing could be obtained. If the Trust obtains debt financing, any funds borrowed must be repaid in full, including accrued interest, before distributions to unitholders could be made. The Trust’s financial statements do not include any adjustments that might result from the outcome of this uncertainty. Greenhouse Gas Emissions and Climate Change Regulation There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change. A number of nations and U.S. states have adopted or are considering some form of climate change legislation and regulations, including carbon taxes, cap-and-trade policies and bans on drilling in certain areas or in certain ways. The climate accord reached at the Conference of the Parties (COP21) in Paris set many new goals, and while many related policies are still emerging, XTO Energy has informed the Trustee that it continues to anticipate that such policies will increase the cost of carbon dioxide emissions over time. As these regulations are under development, XTO Energy is unable to predict the total impact of the potential regulations upon the operators of the underlying properties, and it is possible that the operators of the underlying properties could face increases in operating costs or a ban or certain types of activities in order to comply with climate 28 change or GHG emissions legislation, which costs could reduce or eliminate net proceeds payable to the Trust and Trust distributions. Off-Balance Sheet Arrangements The Trust has no off-balance sheet financing arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations. Related Party Transactions XTO Energy operates approximately 95% of the underlying properties. In computing net proceeds, XTO Energy deducts an overhead charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31, 2019, the monthly overhead charge, based on the number of operated wells, was approximately $1,019,000 ($815,000 net to the Trust) and is subject to annual adjustment based on an oil and gas industry index as defined in the Trust Indenture. Certain of XTO Energy’s wholly-owned subsidiaries purchase natural gas and provide services for the properties operated by XTO Energy. In the Hugoton area, Timberland provides gathering from the wellhead to DCP’s gathering system for approximately $0.75 per Mcf. A portion of the gas production in Major County, Oklahoma is sold to Ringwood Gathering Company (“RGC”) for a price based upon third party sales. RGC retains approximately $0.31 per Mcf as a compression and gathering fee. For further information regarding natural gas sales from the underlying properties to affiliates of XTO Energy, see Significant Properties, under Item 2, Properties. Total gas sales from the underlying properties to XTO Energy’s wholly-owned subsidiaries were $1.8 million for 2019, or 5% of total gas sales, $5.8 million for 2018, or 16% of total gas sales. On June 25, 2010, XTO Energy became a wholly-owned subsidiary of Exxon Mobil Corporation. Critical Accounting Policies The financial statements of the Trust are significantly affected by its basis of accounting and estimates related to its oil and gas properties and proved reserves, as summarized below. Basis of Accounting The Trust’s financial statements are prepared on a modified cash basis, which is a comprehensive basis of accounting other than U.S. GAAP. This method of accounting is consistent with reporting of taxable income to Trust unitholders. The most significant differences between the Trust’s financial statements and those prepared in accordance with U.S. GAAP are: 1. 2. 3. Net profits income is recognized in the month received rather than accrued in the month of production. Expenses are recognized when paid rather than when incurred. Cash reserves may be established by the Trustee for certain contingencies that would not be recorded under U.S. GAAP. This comprehensive basis of accounting other than U.S. GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. For further information regarding the Trust’s basis of accounting, see Note 2 to Financial Statements under Item 8, Financial Statements and Supplementary Data. 29 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 indicate 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, including information provided by XTO Energy such as estimates of future production and development and operating expenses. Significantly, during the third quarter of 2019, long term gas prices used to develop projections of future cash flows declined further and excess costs on all three conveyances increased substantially. In light of these facts and circumstances, an impairment trigger event occurred in the third quarter of 2019. An assessment of the forecasted net cash flows for the NPI indicated that the estimated undiscounted future net cash flows from the NPI were below the carrying value of the NPI. During the third quarter of 2019, the NPI was written down to its fair value of zero, resulting in a $15.7 million impairment charged directly to Trust corpus, which did not affect distributable income. 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. Impairments recorded for book purposes will not result in a loss for tax purposes for the unitholders until the loss is recognized. Oil and Gas Reserves The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using 12-month average prices, based on the first-day-of-the-month price for each month in the period, estimated reserve quantities can be significantly impacted by changes in product prices. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from original estimates. The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 9 to Financial Statements under Item 8, Financial Statements and Supplementary Data, is prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures, including recovery of cumulative excess costs remaining at year end. Discounted including future net cash flows are calculated using a 10% rate. Changes in any of these assumptions, 30 consideration of other factors, could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent XTO Energy’s or the Trustee’s estimated current market value of proved reserves. Forward-Looking Statements Certain information included in this annual report and other materials filed, or to be filed, by the Trust with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by XTO Energy or the Trustee) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the Trust, operations of the underlying properties and the oil and gas industry. Such forward-looking statements may concern, among other things, reserve-to-production ratios, future production, development activities and associated operating expenses, future development plans by area, increased density drilling, maintenance projects, development, production and other costs, oil and gas prices, pricing differentials, proved reserves, future net cash flows, production levels, expense reserve budgets, availability of financing, arbitration, litigation, political and regulatory matters, such as tax and environmental policy, climate policy, trade barriers, sanctions, and competition. Such forward-looking statements are based on XTO Energy’s and the Trustee’s current plans, expectations, assumptions, projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “projects,” “anticipates,” “predicts,” “believes,” “goals,” “estimates,” “should,” “could,” “would,” and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual financial and operational results may differ materially from expectations, estimates or assumptions expressed in, implied in, or forecasted in such forward-looking statements. Some of the risk factors that could cause actual results to differ materially are explained in Item 1A, Risk Factors. Item 7A. Quantitative and Qualitative Disclosures about Market Risk Not required for smaller reporting companies; the Trust has elected to omit this information. 31 Item 8. Financial Statements and Supplementary Data Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Statements of Assets, Liabilities and Trust Corpus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Statements of Distributable Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Statements of Changes in Trust Corpus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page 33 34 34 34 35 All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto. 32 Report of Independent Registered Public Accounting Firm To the Unitholders of Hugoton Royalty Trust and Simmons Bank, As Trustee Opinion on the Financial Statements We have audited the accompanying statements of assets, liabilities, and trust corpus of Hugoton Royalty Trust (the “Trust”) as of December 31, 2019 and 2018, and the related statements of distributable income and of changes in trust corpus for the years then ended, including the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities, and trust corpus of the Trust as of December 31, 2019 and 2018, and its distributable income and its changes in trust corpus for the years then ended in conformity with the modified cash basis of accounting described in Note 2. Substantial Doubt About the Trust’s Ability to Continue as a Going Concern The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. As discussed in Note 2 to the financial statements, increases in excess costs have led to a reduction in net profits income available to the Trust. These factors have resulted in a decline to the expense reserve available to the Trust for the payment of its obligations which raise substantial doubt about its ability to continue as a going concern. The Trustee’s plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty. Basis for Opinion These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on the Trust’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Basis of Accounting As described in Note 2, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than generally accepted accounting principles. /s/ PricewaterhouseCoopers LLP Dallas, Texas March 30, 2020 We have served as the Trust’s auditor since 2011. 33 HUGOTON ROYALTY TRUST STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS December 31 2019 2018 Assets Cash and short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net profits interests in oil and gas properties – net $605,646 $ 1,128,157 (Notes 1 and 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 15,816,990 $605,646 $16,945,147 Liabilities and Trust Corpus Distribution payable to unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expense reserve (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Trust corpus (40,000,000 units of beneficial interest $ — $ 605,646 — 1,128,157 authorized and outstanding) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 15,816,990 $605,646 $16,945,147 (a) The expense reserve allows the Trustee to pay its obligations should it be unable to pay them out of the net profits income. STATEMENTS OF DISTRIBUTABLE INCOME Year Ended December 31 2019 2018 Net profits income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 369,458 21,429 $1,590,949 23,152 Total income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Administration expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash reserves withheld (used) for Trust expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 390,887 913,398 (522,511) 1,614,101 1,115,904 128,157 Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 370,040 Distributable income per unit (40,000,000 units) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.000000 $ 0.009251 STATEMENTS OF CHANGES IN TRUST CORPUS Trust corpus, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amortization of net profits interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Impairment of net profits interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distributions declared . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 15,816,990 (135,457) (15,681,533) — — $16,379,749 (562,759) — 370,040 (370,040) Trust corpus, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $15,816,990 Year Ended December 31 2019 2018 See accompanying notes to financial statements. 34 HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS 1. Trust Organization and Provisions Hugoton Royalty Trust (the “Trust”) was created on December 1, 1998 by XTO Energy Inc. (formerly known as “Cross Timbers Oil Company”). Effective on that date, XTO Energy conveyed 80% net profits interests in certain predominantly gas-producing working interest properties in Kansas, Oklahoma and Wyoming to the Trust under separate conveyances for each of the three states. In exchange for the conveyances of the net profits interests to the Trust, XTO Energy received 40 million units of beneficial interest in the Trust. The Trust’s initial public offering was in April 1999. The majority of the underlying working interest properties are currently owned and operated by XTO Energy (Note 7). Simmons Bank is the Trustee for the Trust. The Trust indenture provides, among other provisions, that: 1. 2. 3. 4. 5. 6. the Trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments; the Trust may dispose of all or part of the net profits interests if approved by a vote of holders of 80% or more of the outstanding Trust units, or upon Trust termination. Otherwise, the Trust is required to sell up to 1% of the value of the net profits interests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the related underlying properties. Any sale must be for cash with 80% of the proceeds distributed to the unitholders on the next declared distribution; the Trustee may establish a cash reserve for payment of any liability that is contingent or not currently payable; the Trustee may borrow funds to pay Trust liabilities if repaid in full prior to further distributions to unitholders; the Trustee will make monthly cash distributions to unitholders (Note 3); and the Trust will terminate upon the first occurrence of: a) b) c) disposition of all net profits interests pursuant to terms of the Trust indenture, gross proceeds from the underlying properties falling below $1 million per year for two successive years, or a vote of holders of 80% or more of the outstanding Trust units to terminate the Trust in accordance with provisions of the Trust indenture. 2. Basis of Accounting The financial statements of the Trust are prepared on the following basis and are not intended to present financial position and results of operations in conformity with U.S. GAAP: 1. 2. 3. 4. Net profits income is recorded in the month received by the Trustee (Note 3); Interest income, interest to be received and distribution payable to unitholders include interest to be earned on net profits income from the monthly record date (last business day of the month) through the date of the next distribution; Trust expenses are recorded based on liabilities paid and cash reserves established by the Trustee for liabilities and contingencies; and Distributions to unitholders are recorded when declared by the Trustee (Note 3). 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. 35 HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS—(Continued) 2. 3. Expenses are recognized when paid rather than when incurred. Cash reserves may be established by the Trustee for certain contingencies that would not be recorded under U.S. GAAP. This comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with U.S. GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the Trust’s financial statements are prepared on the modified cash basis, as described above, most accounting pronouncements are not applicable to the Trust’s financial statements. Impairment of Net Profits Interest The Trustee reviews the Trust’s net profits interests (“NPI”) in oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the NPI may not be recoverable. In general, the Trustee does not view temporarily low prices as an indication of impairment. The markets for crude oil and natural gas have a history of significant price volatility and though prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand. If events and circumstances indicate 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, including information provided by XTO Energy such as estimates of future production and development and operating expenses. Significantly, during the third quarter of 2019, long term gas prices used to develop projections of future cash flows declined further and excess costs on all three conveyances increased substantially. In light of these facts and circumstances, an impairment trigger event occurred in the third quarter of 2019. An assessment of the forecasted net cash flows for the NPI indicated that the estimated undiscounted future net cash flows from the NPI were below the carrying value of the NPI. During the third quarter of 2019, the NPI was written down to its fair value of zero, resulting in a $15.7 million impairment charged directly to Trust corpus, which did not affect distributable income. 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. Impairments recorded for book purposes will not result in a loss for tax purposes for the unitholders until the loss is recognized. Liquidity and Going Concern The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. Financial statements prepared on a going concern basis assume the realization of assets and the settlement of liabilities in the normal course of business. Increases in excess costs for the Kansas, Oklahoma and Wyoming conveyances have resulted in no net proceeds to the Trust for the last nine months of 2018 and a reduction in the Trust’s expense reserve. In March through May of 2019, the Trust received net profits income from the Wyoming conveyance in an amount that covered all of the Trust’s administrative expenses and allowed 36 HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS—(Continued) for a partial replenishment of the expense reserve, but there were no funds to distribute to unitholders. The net profits income in these months are not necessarily indicative of future cash inflows for the next 12 months. These conditions raise substantial doubt about the Trust’s ability to continue as a going concern as the Trust may not have, based on the current estimated administrative expenses, sufficient cash to meet its obligations during the one year period after the date the financial statements are issued. Factors attributable to the potential cash shortage are primarily the previously disclosed increase in development costs to drill four horizontal wells in Major County, Oklahoma (actual cost incurred through fourth quarter 2019 are $27.6 million net to the Trust) which have created an excess cost position on the Oklahoma conveyance. Additionally, excess cost positions on the Kansas and Wyoming conveyances have resulted in no net proceeds to the Trust from the Kansas conveyance for all of 2018 and 2019 and no net proceeds to the Trust from the Wyoming conveyance for all of 2018 and 2019, with the exception of the March through May distributions. The Trustee has prepared a preliminary budget estimating the administrative expenses for the year ending December 31, 2020 and the three months ending March 31, 2021 which assumes no cash inflow from either net profits income or from other sources. This budget estimates that the expense reserve will be depleted by approximately June 2020. If either income or expenses differ from the assumptions in the Trustee’s preliminary budget, this date may be sooner or later than the estimate. The Trustee is currently seeking financing to pay the Trust obligations during the one year period after the date the financial statements are issued once the expense reserve funds have been depleted. This outcome would ensure that the Trust could continue as a going concern; however, there is no assurance that such additional financing could be obtained. If the Trust obtains debt financing, any funds borrowed must be repaid in full, including accrued interest, before distributions to unitholders could be made. The Trust’s financial statements do not include any adjustments that might result from the outcome of this uncertainty. Net profits interests in oil and gas properties The initial carrying value of the net profits interests of $247,066,951 represents XTO Energy’s historical net book value for the interests on December 1, 1998, the date of the transfer to the Trust. During the second quarter 2016, the carrying value of the NPI was written down to its fair value of $28,801,000, resulting in an impairment of $57,306,527 charged directly to Trust corpus. During the third quarter 2019, the carrying value of the NPI was written down to its fair value of zero, resulting in an impairment of $15,681,533 charged directly to trust corpus. Amortization of the net profits interests is calculated on a unit-of-production basis and charged directly to trust corpus. Accumulated amortization was $174,078,891 as of December 31, 2019 and $173,943,434 as of December 31, 2018. 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 legal and marketing less costs. Costs generally include applicable taxes, transportation, sale of production, charges, production expense, development and drilling costs, and overhead. XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming). If costs exceed revenues for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from the other conveyances (Note 4). 37 HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS—(Continued) 4. Excess Costs If monthly costs exceed revenues for any of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds from other conveyances. The following summarizes excess costs activity, cumulative excess costs balance and accrued interest to be recovered by conveyance: KS OK WY Total Underlying Cumulative excess costs remaining at 12/31/18 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 896,578 $15,576,231 $ 1,336,456 $17,809,265 Net excess costs (recovery) for the quarter ended 3/31/19 . . . . . . . . . . . . . . . . . . . . . . . . . 13,547 5,391,871 (1,336,456) 4,068,962 Net excess costs (recovery) for the quarter ended 6/30/19 . . . . . . . . . . . . . . . . . . . . . . . . . 148,644 69,876 176,518 395,038 Net excess costs (recovery) for the quarter ended 9/30/19 . . . . . . . . . . . . . . . . . . . . . . . . . 361,811 7,022,818 1,415,623 8,800,252 Net excess costs (recovery) for the quarter ended 12/31/19 . . . . . . . . . . . . . . . . . . . . . . . . 374,907 (2,850,233) 1,597,606 (877,720) Cumulative excess costs remaining at 12/31/19 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued interest at 12/31/19 . . . . . . . . . . . . . . . 1,795,487 231,022 25,210,563 782,468 3,189,747 31,305 30,195,797 1,044,795 Total remaining to be recovered at 12/31/19 . . $2,026,509 $25,993,031 $ 3,221,052 $31,240,592 KS OK WY Total NPI Cumulative excess costs remaining at 12/31/18 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 717,263 $12,460,985 $ 1,069,165 $14,247,413 Net excess costs (recovery) for the quarter ended 3/31/19 . . . . . . . . . . . . . . . . . . . . . . . . . 10,837 4,313,496 (1,069,165) 3,255,168 Net excess costs (recovery) for the quarter ended 6/30/19 . . . . . . . . . . . . . . . . . . . . . . . . . 118,915 55,901 141,214 316,030 Net excess costs (recovery) for the quarter ended 9/30/19 . . . . . . . . . . . . . . . . . . . . . . . . . 289,448 5,618,254 1,132,499 7,040,201 Net excess costs (recovery) for the quarter ended 12/31/19 . . . . . . . . . . . . . . . . . . . . . . . . 299,926 (2,280,186) 1,278,085 (702,175) Cumulative excess costs remaining at 12/31/19 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued interest at 12/31/19 . . . . . . . . . . . . . . . 1,436,389 184,818 20,168,450 625,974 2,551,798 25,044 24,156,637 835,836 Total remaining to be recovered at 12/31/19 . . $1,621,207 $20,794,424 $ 2,576,842 $24,992,473 For the quarter ended December 31, 2019, lower revenues in relation to costs resulted in excess costs on properties underlying the Kansas and Wyoming net profits interests. Higher revenues in relation to costs due to production from the four new wells resulted in partial recovery of excess costs on properties underlying the Oklahoma net profits interest. 38 HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS—(Continued) During the year ended December 31, 2019, recoveries of interest on properties underlying the Wyoming net profits interests were $38,809 ($31,047 NPI). Underlying cumulative excess costs for the Kansas, Oklahoma and Wyoming conveyances remaining as of December 31, 2019 totaled $31.2 million ($25.0 million NPI), including accrued interest of $1.0 million ($0.8 million NPI). 5. Development Costs The following summarizes actual development costs, development costs deducted in the calculation of net profits income, and the cumulative actual costs compared to the amount deducted for the underlying properties: Cumulative actual costs under (over) the amount deducted – beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Actual costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Budgeted / actual costs deducted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 13,913,191 (31,966,848) 18,053,657 $ 537,144 (8,426,453) 21,802,500 Cumulative actual costs under (over) the amount deducted – end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $13,913,191 Year Ended December 31 2018 2019 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. XTO Energy has advised the Trustee that actual development costs for properties underlying the Kansas and Wyoming net profits interests were charged to the Trust as incurred. XTO has advised the Trustee that actual development costs for the properties underlying the Oklahoma net profits interests were charged to the Trust as incurred once the accrual was fully depleted as of the July 2019 distribution. XTO Energy has advised the Trustee that drilling in Major County, Oklahoma is complete and resulted in cost overruns due to unforeseen expenditures that were charged to the Trust in the third quarter of 2019. XTO Energy has advised the Trustee that 2020 budgeted development costs for the underlying properties are between $1 million and $3 million. The 2020 budget year generally coincides with the Trust distribution months from April 2020 through March 2021. 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 2020 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. Impairments recorded for book purposes will not result in a loss for tax purposes for the unitholders until the loss is recognized. All revenues from the Trust are from sources within Kansas, Oklahoma or Wyoming. Because it distributes all of its net income to unitholders, the Trust has not been taxed at the trust level in Kansas or Oklahoma. While the Trust has not owed tax, the Trustee is generally required to file Kansas and Oklahoma income tax returns 39 HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS—(Continued) 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 2019 tax year because the Trust had no revenues, income or deductions in 2019 attributable to properties located in Kansas. The Trust did not file a Kansas income tax return for the 2018 and 2017 tax years for the same reason. Wyoming does not impose a state income tax. The Trust could potentially be required to bear a portion of the legal settlement costs arising from the Chieftain settlement. For information on contingencies, including the Chieftain class action, see Note 8 to Financial Statements. In the event that the Trust is determined to be responsible for such costs, XTO will deduct the costs in its calculation of the net profits income payable to the Trust from the applicable net profits interests. Thus, for unitholders, the legal settlement costs will be reflected through a reduction in net profits income received from the Trust and thus in a reduction in the gross royalty income reported by and taxable to the unitholders. In the event that the Trustee objects to such claimed reductions, the Trustee may also incur legal fees in representing the Trust’s interests. For unitholders, such costs would be reflected through an increase in the Trust’s administrative expenses, which would be deductible by unitholders in determining the net royalty income from the Trust. Each unitholder should consult his or her own tax advisor regarding income tax requirements, if any, applicable to such person’s ownership of Trust units. 7. XTO Energy Inc. XTO Energy operates approximately 95% of the underlying properties. In computing net proceeds, XTO Energy deducts an overhead charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31, 2019, the monthly overhead charge, based on the number of operated wells, was approximately $1,019,000 ($815,000 net to the Trust) and is subject to annual adjustment based on an oil and gas industry index as defined in the Trust Indenture. Certain of XTO Energy’s wholly-owned subsidiaries purchase natural gas and provide services for the properties operated by XTO Energy. In the Hugoton area, Timberland provides gathering from the wellhead to DCP’s gathering system for approximately $0.75 per Mcf. 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 $1.8 million for 2019, or 5% of total gas sales, $5.8 million for 2018, or 16% of total gas sales. On June 25, 2010, XTO Energy became a wholly-owned subsidiary of Exxon Mobil Corporation. 8. Contingencies Litigation Royalty Class Action and Arbitration As previously disclosed, XTO Energy advised the Trustee that it reached a settlement with the plaintiffs in the Chieftain class action royalty case. On July 27, 2018 the final plan of allocation was approved by the court. Based on the final plan of allocation XTO Energy has advised the Trustee that it believes approximately $24.3 million in 40 HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS—(Continued) additional production costs should be allocated to the Trust. On May 2, 2018, the Trustee submitted a demand for arbitration seeking a declaratory judgment that the Chieftain settlement is not a production cost and that XTO Energy is prohibited from charging the settlement as a production cost under the conveyance or otherwise reducing the Trust’s payments now or in the future as a result of the Chieftain litigation. The hearing on the claims related to the Chieftain settlement has been rescheduled for April 27, 2020. Other Trustee claims related to disputed amounts on the computation of the Trust’s net proceeds for 2014 through 2016 were bifurcated from the issues regarding XTO’s right to charge the Chieftain settlement as a production cost and will be heard at a later date, which is still to be determined. If the approximately $24.3 million allocated portion of the Chieftain settlement results in an adjustment to the Trust’s share of net proceeds, it would result in additional excess costs under the Oklahoma conveyance that would likely result in no distributions under the Oklahoma conveyance for several years, or more depending on the results of operations of the underlying properties, while these additional excess costs are recovered. Other Lawsuits and Governmental Proceedings Certain of the underlying properties are involved in various other lawsuits and governmental proceedings arising in the ordinary course of business. XTO Energy has advised the Trustee that it does not believe that the ultimate resolution of these claims will have a material effect on the financial position or liquidity of the Trust, but may have an effect on annual distributable income. Other Several states have enacted legislation requiring state income tax withholding from payments made to nonresident recipients of oil and gas proceeds. After consultation with its tax counsel, the Trustee believes that it is not required to withhold on payments made to the unitholders. However, regulations are subject to change by the various states, which could change this conclusion. Should amounts be withheld on payments made to the Trust or the unitholders, distributions to the unitholders would be reduced by the required amount, subject to the filing of a claim for refund by the Trust or unitholders for such amount. 9. Supplemental Oil and Gas Reserve Information (Unaudited) Oil and Natural Gas Reserves Proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the 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. 41 HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS—(Continued) Standardized Measure The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month average prices for oil and gas, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures to produce the proved reserves, including recovery of cumulative excess costs remaining at year end. Future net cash flows are discounted at an annual rate of 10%. No provision is included for federal income taxes since future net cash flows are not subject to taxation at the trust level. The standardized measure does not represent management’s estimate of future cash flows or the value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, prices used to determine the standardized measure are influenced by supply and demand as affected by recent economic conditions as well as other factors and may not be the most representative in estimating future revenues or reserve data. Estimated costs to plug and abandon wells on the underlying working interest properties at the end of their productive lives have not been deducted from cash flows since this is not a legal obligation of the Trust. These costs are the legal obligation of XTO Energy as the owner of the underlying working interests and will only be deducted from net proceeds payable to the Trust if net proceeds from the related conveyance exceed such costs when paid, subject to excess cost carryforward provisions (Notes 3 and 4). The average realized gas prices used to determine the standardized measure were $1.88 per Mcf in 2019, $2.36 per Mcf in 2018, $2.40 per Mcf in 2017 and $1.94 per Mcf in 2016. Oil prices used to determine the standardized measure were based on average realized oil prices of $53.20 per Bbl in 2019, $63.30 per Bbl in 2018, $47.91 per Bbl in 2017 and $39.08 per Bbl in 2016. Reserve quantities and revenues for the net profits interests were estimated from projections of reserves and revenues attributable to the underlying properties. Since the Trust has defined net profits interests, the Trust does not own a specific percentage of the oil and gas reserves. Oil and gas reserves are allocated to the net profits interests by dividing Trust net cash inflows by 12-month average oil and gas prices. Any fluctuations in 12-month average prices or estimated costs will result in revisions to the estimated reserve quantities allocated to the net profits interests, which may not correlate with revisions of underlying proved reserves. 42 HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS—(Continued) Proved Reserves (in thousands) Underlying Properties Oil (Bbls) Gas (Mcf) Net Profits Interests Oil (Bbls) Gas (Mcf) Balance, December 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance, December 31, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance, December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92,468 5 39,851 (13,903) — 118,421 9,388 6,375 (12,994) — 121,190 90 (29,994) (11,113) — Balance, December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80,173 1,097 33 345 (156) — 1,319 674 167 (155) — 2,005 53 (176) (302) — 1,580 4,167 3 10,496 (1,628) — 13,038 2,513 (2,313) (448) — 12,790 46 (12,726) (110) — — 66 17 109 (27) — 165 180 106 (8) — 443 27 (470) — — — Revisions of prior estimates of the proved gas reserves for the underlying properties in each year are primarily because of changes in the gas and oil prices. Revisions for the net profits interests may not correlate with underlying properties in any given year since the Trust’s allocated reserves reflect recovery of the Trust’s portion of production and development costs at 12-month average prices. Any conveyance where costs exceed revenues will result in zero allocated net profits interests reserves for that conveyance. Proved Developed Reserves (in thousands) Underlying Properties Oil (Bbls) Gas (Mcf) Net Profits Interests Oil (Bbls) Gas (Mcf) December 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91,734 December 31, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117,667 December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111,234 December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79,204 1,097 1,319 1,339 1,580 4,167 12,844 7,979 — 66 165 121 — 43 HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS—(Continued) Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (in thousands) Underlying Properties Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future costs: December 31 2018 2017 2019 $234,398 $413,046 $347,055 Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Development 233,603 795 338,719 6,687 Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 67,640 — 29,776 301,930 795 44,330 13,125 Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 37,864 $ 31,205 Net Profits Interests Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future production taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 58,139 4,027 — $ 38,655 3,192 Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 54,112 — 23,821 35,463 10,499 Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 30,291 $ 24,964 Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (in thousands) 2019 2018 2017 Underlying Properties Standardized measure, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 37,864 $ 31,205 $ 9,536 Revisions: Prices and costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Quantity estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion of discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Production rates and other Net revisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (35,003) 4,456 3,869 (12,093) 195 (38,576) 1,174 (18,513) 18,051 — 11,684 14,205 2,731 (27,592) 687 1,715 6,932 (23,791) 21,803 — 25,717 4,667 784 (2,667) (586) 27,915 401 (9,447) 2,800 — Net change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (37,864) 6,659 21,669 Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 37,864 $31,205 Net Profits Interests Standardized measure, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion of discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revisions of prior estimates, changes in price and other . . . . . . . . . . . . . . . . . . . . . . . Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net profits income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 30,291 939 3,095 (33,956) — (369) $ 24,964 5,545 2,185 (812) — (1,591) $ 7,628 321 628 21,705 — (5,318) Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 30,291 $24,964 44 HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS—(Continued) 10. Quarterly Financial Data (Unaudited) The following is a summary of net profits income, distributable income and distributable income per unit by quarter for 2019 and 2018: Net Profits Income Distributable Income Distributable Income per Unit 2019 First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 130,733 238,725 — — $ — — — — $0.000000 0.000000 0.000000 0.000000 $ 369,458 $ — $0.000000 2018 First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,590,949 — — — $370,040 — — — $0.009251 0.000000 0.000000 0.000000 $1,590,949 $370,040 $0.009251 45 HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS—(Continued) 11. Subsequent Events None. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures The Trustee conducted an evaluation of the Trust’s disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, the Trustee has concluded that the Trust’s disclosure controls and procedures were effective as of the end of the period covered by this annual report. In its evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by XTO Energy. Trustee’s Report on Internal Control Over Financial Reporting The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control— Integrated Framework (2013), the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2019. 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, 2019 that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting. Item 9B. Other Information None. 46 Item 10. Directors, Executive Officers and Corporate Governance PART III (a) Directors, Officers and Committees. The Trust has no directors, executive officers, audit committee, audit committee financial expert, compensation committee or nominating committee. The Trustee is a corporate Trustee which may be removed, with or without cause, by the affirmative vote of the holders of a majority of all the units then outstanding. (b) Section 16(a) Beneficial Ownership Reporting Compliance. Section 16(a) of the Securities Exchange Act of 1934 requires that directors, officers, and beneficial owners of more than 10% of the registrant’s equity securities file initial reports of beneficial ownership and reports of changes in beneficial ownership with the Securities and Exchange Commission and the New York Stock Exchange. To the Trustee’s knowledge, based solely on the information furnished to the Trustee, the Trustee is unaware of any person that failed to file on a timely basis reports required by Section 16(a) filing requirements with respect to the Trust units of beneficial interest during and for the year ended December 31, 2019. (c) Code of Ethics. Because the Trust has no employees, it does not have a code of ethics. Employees of the Trustee, Simmons Bank, must comply with the bank’s code of ethics which may be found at ir.simmonsbank.com/govdocs. Item 11. Executive Compensation (a) Compensation Committee Interlocks and Insider Participation/Compensation Committee Report. The Trust has no officers or directors and is administered by a trustee. The Trust does not have a compensation committee or maintain any equity compensation plans and there are no units reserved for issuance under any such plans. (b) Compensation of the Trustee. The Trustee and Southwest Bank, the prior trustee, received the following annual compensation for the fiscal years ended December 31, 2019 and 2018 as specified in the Trust indenture: Simmons Bank, Trustee (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Southwest Bank, Trustee (1) $72,750 $52,261 — 17,318 2019 2018 (1) Under the Trust indenture, the trustee is entitled to an annual administrative fee, paid in equal monthly installments. Such fee can be adjusted annually based on an oil and gas industry index. Upon termination of the Trust, the trustee is entitled to a termination fee of $15,000. (c) Pay Ratio Disclosure. The Trust does not have a principal executive officer or employees and therefore, the pay ratio disclosure is not applicable. 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 2019. 47 (a) Security Ownership of Certain Beneficial Owners. Based on the Trustee’s review of information filed with the SEC as of March 4, 2020, the following table sets forth information with respect to each person known to the Trustee to beneficially own more than 5% of the outstanding units. Name and Address Amount and Nature of Beneficial Ownership Percent of Clss Christopher John Heck 2214 E. 377, Unit B Granbury, TX 76049 . . . . . . . . . . . . . . . . . . . . . . . . . . 3,924,149(1) 9.81% (1) Pursuant to a Schedule 13G filed February 14, 2020, Christopher John Heck reported as of December 31, 2019, he directly owned 3,924,149 units, of which he had sole voting and dispositive power with respect to 3,900,449 units and shared voting and dispositive power with respect to 23,700 units. (b) Security Ownership of Management. The Trust has no directors or executive officers. The Trustee does not beneficially own any units in the Trust. (c) Changes in Control. The Trustee knows of no arrangements which may subsequently result in a change in control of the Trust. Item 13. Certain Relationships and Related Transactions, and Director Independence 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, 2019 was approximately $1,019,000 per month, or $12,228,000 annually (net to the Trust of $815,000 per month or $9,780,000 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, 2018 through December 31, 2019. 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, 2019 and 2018 are: Audit fees-PwC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Audit-related fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tax fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . All other fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $163,000 — — — $157,000 — — — 2019 2018 $163,000 $157,000 As referenced in Item 10, Directors, Executive Officers and Corporate Governance, above, the Trust has no audit committee, and as a result, has no audit committee pre-approval policy with respect to fees paid to PricewaterhouseCoopers LLP. 48 PART IV Item 15. Exhibits and Financial Statement Schedules (a) The following documents are filed as a part of this report: 1. Financial Statements (included in Item 8 of this report) Report of Independent Registered Public Accounting Firm Statements of Assets, Liabilities and Trust Corpus at December 31, 2019 and 2018 Statements of Distributable Income for the years ended December 31, 2019 and 2018 Statements of Changes in Trust Corpus for the years ended December 31, 2019 and 2018 Notes to Financial Statements 2. Financial Statement Schedules Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto. 3. Exhibits (4) (a) (b) (c) (d) Hugoton Royalty Trust Indenture by and between NationsBank, N.A., as Trustee, and Cross Timbers Oil Company (predecessor of XTO Energy) heretofore filed as Exhibit 4.1 to the Trust’s Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange Commission on December 4, 1998, is incorporated herein by reference. (P) 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. (P) 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. (P) 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. (P) (23) (31) (32) Consent of Miller and Lents, Ltd. Rule 13a-14(a)/15d-14(a) Certification Section 1350 Certification (99.1) Miller and Lents, Ltd. Report (P) Paper exhibits. Copies of the above Exhibits are available to any unitholder, at the actual cost of reproduction, upon written request to the Trustee, Simmons Bank, 2911 Turtle Creek Blvd, Suite 850, Dallas, Texas 75219. 49 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized. SIGNATURES HUGOTON ROYALTY TRUST By SIMMONS BANK, TRUSTEE By /s/ NANCY WILLIS Nancy Willis Vice President EXXON MOBIL CORPORATION Date: March 30, 2020 By /s/ DAVID LEVY David Levy Vice President – Upstream Business Services (The Trust has no directors or executive officers.) 50 Mr. Max Boone Unconventional Reservoir Engineering Manager XTO Energy Inc. 22777 Springwoods Village Parkway Spring, TX 77389-1425 March 25, 2020 EXHIBIT 99.1 Re: Underlying Properties (100%) Relating to the Hugoton Royalty Trust Reserves and Future Net Revenues As of December 31, 2019 SEC Price Case Dear Mr. Boone: At your request, Miller and Lents, Ltd. (M&L) estimated the proved reserves and future net revenues as of December 31, 2019, attributable to the XTO Energy Inc. (XTO) interest in certain oil and gas properties prior to inclusion in the Hugoton Royalty Trust, i.e., Underlying Properties (100%). The Underlying Properties (100%) include working interest properties from which net profits interests were conveyed to the Hugoton Royalty Trust. The properties consist of approximately 1,435 leases and 1,557 wells located primarily in Kansas, Oklahoma, and Wyoming. The aggregate results of M&L’s evaluations are as follows: Reserves Category Kansas Net Reserves Future Net Revenues Oil and Condensate MBBL Gas MMCF Undiscounted M$ Discounted at 10% Per Year M$ Proved Developed Producing . . . . . . . . . . . . . . . . . . . . . . . . . . . Proved Developed Nonproducing . . . . . . . . . . . . . . . . . . . . . . . Total Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oklahoma Proved Developed Producing . . . . . . . . . . . . . . . . . . . . . . . . . . . Proved Undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wyoming Proved Developed Producing . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Underlying Properties (100%) Proved Developed Producing . . . . . . . . . . . . . . . . . . . . . . . . . . . Proved Developed Nonproducing . . . . . . . . . . . . . . . . . . . . . . . Proved Undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . TOTAL PROVED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 0 72 1,468 0 1,468 40 40 1,580 0 0 1,580 2,371 253 2,624 50,230 716 50,946 26,603 26,603 79,204 253 716 80,173 3,425 114 3,539 75,297 18 75,315 20,888 20,888 99,609 114 18 99,741 1,770 40 1,811 46,466 -196 46,270 13,910 13,910 62,147 40 -196 61,991 Underlying Properties (100%) Relating to the Hugoton Royalty Trust March 25, 2020 Oil and condensate volumes are expressed in thousand barrels (MBBL). Gas volumes are expressed in million cubic feet (MMCF). Future net revenues are expressed in thousand dollars (M$). The report was prepared for the use of XTO in its financial and reserves reporting and was completed on March 25, 2020. M&L performed evaluations, which are designated as the SEC Price Case, using price and expense premises specified by XTO and described in detail on Appendix 1. Proved reserves and future net revenues were estimated in accordance with the provisions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10(a). The Securities and Exchange Commission definition of proved reserves is shown on Appendix 2 (not included). Gas volumes for each property are stated at the pressure and temperature bases appropriate for the sales contract or state regulatory authority; therefore, some of the aggregated totals may be stated at a mixed pressure base. No provisions for the possible consequences, if any, of product sales imbalances were included in M&L’s projections since M&L received no relevant data. Estimates of future net revenues and discounted future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves. In M&L’s projections, future costs of abandoning facilities and wells were assumed to be offset by salvage values. Estimated costs, if any, for restoration of producing properties to satisfy environmental standards are beyond the scope of this assignment. Following Appendix 2 (not included) is a list of exhibits that include annual projections of future production and net revenues for each state and reserves category. Also included in the exhibits are one-line summaries for the total royalty trust and for each state showing the proved reserves and future net revenues for the individual properties. These exhibits should not be relied upon independently of this narrative. The proved developed producing reserves and production forecasts were estimated by production decline extrapolations, water-oil ratio trends, P/Z declines, or in a few cases, by volumetric calculations. For some properties with insufficient performance history to establish trends, M&L estimated future production by analogy with other properties with similar characteristics. The past performance trends of many properties were influenced by production curtailments, workovers, waterfloods, and/or infill drilling. Actual future production may require that M&L’s estimated trends be significantly altered. Reserves estimates from volumetric calculations and from analogies are often less certain than reserves estimates based on well performance obtained over a period during which a substantial portion of the reserves was produced. The estimated proved developed nonproducing reserves can be produced from existing well bores but require capital costs for recompletions or for pipeline connections. These proved developed nonproducing reserves estimates were based on analogies with other wells that commercially produce from the same formation in the same field. The timing of initial production was provided to M&L by XTO. When actual production history is available for these nonproducing reserves, M&L’s reserves estimates may be significantly revised. The estimated proved undeveloped reserves require significant capital expenditures, such as for planned drilling and completion costs. The proved undeveloped reserves estimates for infill wells are based on analogies to similar infill wells in the same field and/or the production histories of offset wells in the same field. As actual results of the planned drilling become available, M&L’s reserves estimates may be significantly revised. The data employed in M&L’s estimations of proved reserves and future net revenues were provided by XTO. The current expenses for each lease were obtained from operating statements provided by XTO except for certain leases where XTO deducted items considered by XTO to be nonrecurring expenditures. No overhead was included for those properties operated by XTO. For some properties, such as large waterfloods, XTO assumed a decline in operating costs due to depleting production that was derived by forecasting a decrease in the property well count. For some gas properties, XTO assumed operating costs would be split between a variable component and a fixed component. The variable component was a constant cost per thousand cubic feet of gas production Underlying Properties (100%) Relating to the Hugoton Royalty Trust March 25, 2020 and the fixed component was a constant cost per well completion. The data provided to M&L by XTO, including, but not limited to, graphical representations and tabulations of past production performance, well tests and pressures, ownership interests, prices, capital expenditures, and operating costs were accepted as represented and were considered appropriate for the purpose of this report. M&L employed all methods, data, procedures, and assumptions considered necessary and appropriate in utilizing the data provided to prepare this report. The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect M&L’s informed judgments and are subject to the inherent uncertainties associated with interpretation of geological, geophysical, and engineering information. These uncertainties include, but are not limited to, (1) the utilization of analogous or indirect data and (2) the application of professional judgments. Government policies and market conditions different from those employed in this study may cause (1) the total quantity of oil, natural gas liquids, or gas to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report. At this time, M&L is not aware of any regulations that would affect XTO’s ability to recover the estimated reserves. Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any financial ownership in XTO Energy Inc. or any related company. M&L’s compensation for the required investigations and preparation of this report is not contingent on the results obtained and reported, and it has not performed other work that would affect M&L’s objectivity. Production of this report was supervised by Katie M. Reinaker, P.E., an officer of the firm who is a licensed Professional Engineer in the State of Texas and is professionally qualified, with more than ten years of relevant experience, in the estimation, assessment, and evaluation of oil and gas reserves. M&L’s work papers and data are in its files and available for review upon request. If you have any questions regarding the above, or if M&L can be of further assistance, please call. Very truly yours, MILLER AND LENTS Texas Registered Engineering Firm No. F-1442 By /S/ KATIE M. REINAKER Katie M. Reinaker, P. E. Senior Vice President By /S/ JENNIFER A. GODBOLD Jennifer A. Godbold, P. E. Vice President Hugoton Royalty Trust (100%) SEC PRICE CASE Appendix 1 A. Oil Price B. Gas Price C. Operating Costs Average price during the 12-month period prior to 12/31/19 determined as the arithmetic average of the first-day-of-the-month price for each month during the year 2019. The average price was based on the West Texas Intermediate benchmark price. The arithmetic average of the first-day-of-the-month benchmark prices is $55.69 per barrel and is held constant through the life of the property. The average realized price, after appropriate adjustments, is $53.20 per barrel. Average price during the 12-month period prior to 12/31/19 determined as the arithmetic average of the first-day-of-the-month price for each month during the year 2019. The average price was based on the Henry Hub benchmark price. The arithmetic average of the first-day-of-the-month benchmark price is $2.58 per MMBtu and is held constant through the life of the property. The average realized price, after appropriate adjustments is $1.88 per MCF. Current expenses held constant through the life of the property. For some properties, expenses included a variable component that was a constant cost per unit of gas production and a fixed component that was a constant cost per well completion. D. Discount Rate 10% per year. Form 10-K A copy of the Hugoton Royalty Trust Form 10-K has been provided with this Annual Report. charge upon request. Copies of exhibits to the Form 10-K may be obtained upon request or Additional copies of this Annual Report and Form 10-K will be provided to unitholders without from the Trust’s web site at www.hgt-hugoton.com. Hugoton Royalty Trust Simmons Bank, Trustee 2911 Turtle Creek Blvd, Suite 850 Dallas, Texas 75219 Attention: Annual Reports 1-855-588-7839 Web site www.hgt-hugoton.com Auditors PricewaterhouseCoopers LLP Dallas, Texas Legal and Tax Counsel Thompson & Knight LLP Dallas, Texas Transfer Agent and Registrar American Stock Transfer and Trust Company LLC www.astfinancial.com Certification The Trustee’s certification, required by Section 302 of the Sarbanes-Oxley Act of 2002, has been filed as Exhibit 31 of the Trust’s Form 10-K, for the fiscal year ended December 31, 2019. Inside back cover. PMS#301U with black, 2-color. Hugoton Royalty Trust Simmons Bank 2911 Turtle Creek Blvd, Suite 850 Dallas, Texas 75219 1-855-588-7839 www.hgt-hugoton.com 

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