UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2017

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-10476

Hugoton Royalty Trust

(Exact name of registrant as specified in its charter)

Texas	58-6379215
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Southwest Bank Trustee P.O. Box 962020, Fort Worth, Texas	76162-2020
(Address of principal executive offices)	(Zip Code)

(855) 588-7839

(Registrant’s telephone number, including area code)

NONE

(Former name, former address and former fiscal year, if change since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☐    No  ☐

Indicate by check mark 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 (check one):

Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐  (Do not check if a smaller reporting company)	Smaller reporting company	☐
		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 Exchange Act Rule 12b-2).    Yes  ☐    No  ☒

Indicate the number of units of beneficial interest outstanding, as of the latest practicable date:

Outstanding as of August 1, 2017

40,000,000

HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2017

TABLE OF CONTENTS
	Page
Glossary of Terms		3
PART I.        FINANCIAL INFORMATION
Item 1.           Financial Statements (Unaudited)		4
Report of Independent Registered Public Accounting Firm		5
Condensed Statements of Assets, Liabilities and Trust Corpus at June  30, 2017 and December 31, 2016		6
Condensed Statements of Distributable Income for the Three and Six Months Ended June  30, 2017 and 2016		7
Condensed Statements of Changes in Trust Corpus for the Three and Six Months Ended June  30, 2017 and 2016		8
Notes to Condensed Financial Statements		9
Item 2.           Trustee’s Discussion and Analysis		14
Item 3.           Quantitative and Qualitative Disclosures about Market Risk		19
Item 4.           Controls and Procedures		19
PART II.     OTHER INFORMATION
Item 1.           Legal Proceedings		20
Item 1A.       Risk Factors		20
Item 6.           Exhibits		20
Signatures		21

2

HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

The following are definitions of significant terms used in this Form 10-Q:

Bbl	Barrel (of oil)
Mcf	Thousand cubic feet (of natural gas)
MMBtu	One million British Thermal Units, a common energy measurement
net proceeds	Gross proceeds received by XTO Energy from sale of production from the underlying properties, less applicable costs, as defined in the net profits interest conveyances
net profits income	Net proceeds multiplied by the net profits percentage of 80%, which is paid to the Trust by XTO Energy. “Net profits income” is referred to as “royalty income” for tax reporting purposes.
net profits interest	An interest in an oil and gas property measured by net profits from the sale of production, rather than a specific portion of production. The following defined net profits interests were conveyed to the Trust from the underlying properties: 80% net profits interests - interests that entitle the Trust to receive 80% of the net proceeds from the underlying properties.
underlying properties	XTO Energy’s interest in certain oil and gas properties from which the net profits interests were conveyed. The underlying properties include working interests in predominantly gas-producing properties located in Kansas, Oklahoma and Wyoming.
working interest	An operating interest in an oil and gas property that provides the owner a specified share of production that is subject to all production expense and development costs

3

HUGOTON ROYALTY TRUST

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

The condensed financial statements included herein are presented, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in annual financial statements have been condensed or omitted pursuant to such rules and regulations, although the Trustee believes that the disclosures are adequate to make the information presented not misleading. These condensed financial statements should be read in conjunction with the financial statements and the notes thereto included in the Trust’s latest Annual Report on Form 10-K. In the opinion of the Trustee, all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of the assets, liabilities and trust corpus of the Hugoton Royalty Trust at June 30, 2017 and the distributable income and changes in trust corpus for the three- and six-month periods ended June 30, 2017 and 2016 have been included. Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year. The condensed financial statements as of June 30, 2017, and for the three-month and six-month periods ended June 30, 2017 and 2016 have been subjected to a review by PricewaterhouseCoopers LLP, the Trust’s independent registered public accounting firm, whose report is included herein.

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Report of Independent Registered Public Accounting Firm

To the Unitholders of Hugoton Royalty Trust and

Southwest Bank, Trustee:

We have reviewed the accompanying condensed statement of assets, liabilities and trust corpus of Hugoton Royalty Trust (the “Trust”) as of June 30, 2017, and the related condensed statements of distributable income and changes in trust corpus for the three-month and six-month periods ended June 30, 2017 and 2016. These interim financial statements are the responsibility of the Trustee.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

As described in Note 1, these interim financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed interim financial statements for them to be in conformity with the basis of accounting described in Note 1.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statement of assets, liabilities and trust corpus as of December 31, 2016, and the related statements of distributable income and changes in trust corpus for the year then ended (not presented herein), and in our report dated March 10, 2017, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying condensed statement of assets, liabilities and trust corpus as of December 31, 2016 is fairly stated, in all material respects, in relation to the statement of assets, liabilities and trust corpus from which it has been derived.

/s/ PricewaterhouseCoopers LLP

Dallas, TX

August 4, 2017

5

HUGOTON ROYALTY TRUST

Condensed Statements of Assets, Liabilities and Trust Corpus (Unaudited)

	June 30, 2017		December 31, 2016
ASSETS
Cash and short-term investments	$	1,403,840	$	1,257,800
Net profits interests in oil and gas properties - net (Note 1)		20,063,091		26,885,503
	$	21,466,931	$	28,143,303
LIABILITIES AND TRUST CORPUS
Distribution payable to unitholders	$	403,840	$	257,800
Expense reserve (a)		1,000,000		1,000,000
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)		20,063,091		26,885,503
	$	21,466,931	$	28,143,303

(a) The expense reserve allows the Trustee to pay its obligations should it be unable to pay them out of the net profits income. As of June 30, 2017, the reserve currently established by the Trustee is fully funded at $1,000,000.

The accompanying notes to condensed financial statements are an integral part of these statements.

6

HUGOTON ROYALTY TRUST

Condensed Statements of Distributable Income (Unaudited)

	Three Months Ended June 30				Six Months Ended June 30
	2017		2016		2017		2016
Net profits income	$	1,324,846	$	199,545	$	3,548,472	$	263,107
Interest income		1,605		173		2,525		255
Total income		1,326,451		199,718		3,550,997		263,362
Administration expense		176,171		193,490		514,037		537,337
Cash reserves withheld (used) for Trust expenses		—		6,228		—		(273,975	)
Distributable income	$	1,150,280	$	0	$	3,036,960	$	0
Distributable income per unit (40,000,000 units)	$	0.028757	$	0.000000	$	0.075924	$	0.000000

The accompanying notes to condensed financial statements are an integral part of these statements.

7

HUGOTON ROYALTY TRUST

Condensed Statements of Changes in Trust Corpus (Unaudited)

	Three Months Ended June 30						Six Months Ended June 30
	2017			2016			2017			2016
Trust corpus, beginning of period	$	22,781,888		$	86,728,951		$	26,885,503		$	86,900,231
Amortization of net profits interests		(2,718,797	)		(621,424	)		(6,822,412	)		(792,704	)
Impairment of net profits interest (Note 1)		—			(57,306,527	)		—			(57,306,527	)
Distributable income		1,150,280			—			3,036,960			—
Distributions declared		(1,150,280	)		—			(3,036,960	)		—
Trust corpus, end of period	$	20,063,091		$	28,801,000		$	20,063,091		$	28,801,000

The accompanying notes to condensed financial statements are an integral part of these statements.

8

HUGOTON ROYALTY TRUST

Notes to Condensed Financial Statements (Unaudited)

1. Basis of Accounting

The financial statements of Hugoton Royalty Trust (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. generally accepted accounting principles (“GAAP”):

– Net profits income recorded for a month is the amount computed and paid by XTO Energy Inc., the owner of the underlying properties, to Southwest Bank, as trustee (“Trustee”) for the Trust. XTO Energy is a wholly owned subsidiary of Exxon Mobil Corporation. Net profits income consists of net proceeds received by XTO Energy from the underlying properties in the prior month, multiplied by a net profits percentage of 80%.

Costs deducted in the calculation of net proceeds for the 80% net profits interests generally include applicable taxes, transportation, marketing and legal costs, production expense, development costs, operating charges and other costs.

– Net profits income is computed separately for each of the three conveyances under which the net profits interests were conveyed to the Trust. If monthly 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 proceeds from the other conveyances.

– Interest income and distribution payable to unitholders include interest earned on the previous month’s investment.

– Trust expenses are recorded based on liabilities paid and cash reserves established by the Trustee for liabilities and contingencies.

– Distributions to unitholders are recorded when declared by the Trustee.

– 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 with the next declared distribution.

The Trust’s financial statements differ from those prepared in conformity with U.S. GAAP because revenues are recognized when received rather than accrued in the month of production, expenses are recognized when paid rather than when incurred and certain cash reserves may be established by the Trustee for contingencies which 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.

9

Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with U.S. GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the Trust’s financial statements are prepared on the modified cash basis, as described above, most accounting pronouncements are not applicable to the Trust’s financial statements.

Impairment of Net Profits Interest

The Trustee reviews the Trust’s net profits interests (“NPI”) in oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the NPI may not be recoverable. In general, the Trustee does not view temporarily low prices as an indication of impairment. The markets for crude oil and natural gas have a history of significant price volatility and though prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand. If events and circumstances indicated that the carrying value may not be recoverable, the Trustee would use the estimated undiscounted future net cash flows from the NPI to evaluate the recoverability of the Trust assets. If the undiscounted future net cash flows from the NPI are less than the NPI carrying value, the Trust would recognize an impairment loss for the difference between the NPI carrying value and the estimated fair value of the NPI. The determination as to whether the NPI is impaired requires a significant amount of judgment by the Trustee and is based on the best information available to the Trustee at the time of the evaluation.

In light of lower long term prices used to develop projections of future cash flows, continued excess costs on two conveyances and zero distributions to unitholders for the quarter ended June 30, 2016, the Trustee concluded in the second quarter of 2016 that the events or circumstances indicated the carrying value may not be recoverable and an assessment of the forecasted net cash flows was performed for the NPI. The fair value of the NPI was developed using estimates for future oil and gas production attributable to the Trust, future crude oil and natural gas commodity prices published by third-party industry experts (adjusted for basis differentials), estimated taxes, development and operating expenses, and a risk-adjusted discount rate. The result of the assessment indicated that the estimated undiscounted future net cash flows from the NPI were below the carrying value of the NPI. The NPI was written down to its fair value of $28.8 million, resulting in a $57.3 million impairment charged directly to trust corpus, which did not affect distributable income.

There was no impairment of the NPI during the quarter ended June 30, 2017.

Net profits interests in oil and gas properties

The initial carrying value of the net profits interests of $247,066,951 represents XTO Energy’s historical net book value for the interests on December 1, 1998, the date of the transfer to the Trust. During the second quarter 2016, the carrying value of the NPI was written down to its fair value of $28,801,000, resulting in an impairment of $57,306,527 charged directly to trust corpus. Amortization of the net profits interests is calculated on a unit-of-production basis and charged directly to trust corpus. Accumulated amortization was $169,697,333 as of June 30, 2017 and $162,874,921 as of December 31, 2016.

10

2. Development Costs

The following summarizes actual development costs, budgeted development costs deducted in the calculation of net profits income, and the cumulative actual costs compared to the amount deducted for the underlying properties:

	Three Months Ended June 30						Six Months Ended June 30
	2017			2016			2017			2016
Cumulative actual costs under (over) the amount deducted - beginning of period	$	(73,310	)	$	404,839		$	56,243		$	239,528
Actual costs		(609,745	)		(216,088	)		(1,339,298	)		(725,777	)
Budgeted costs deducted		600,000			250,000			1,200,000			925,000
Cumulative actual costs under (over) the amount deducted - end of period	$	(83,055	)	$	438,751		$	(83,055	)	$	438,751

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 2017 budgeted development costs for the underlying properties are between $2 million and $4 million. The 2017 budget year generally coincides with the Trust distribution months from April 2017 through March 2018. 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.

3. Income Taxes

For federal income tax purposes, the Trust constitutes a fixed investment trust that is taxed as a grantor trust. A grantor trust is not subject to tax at the trust level. Accordingly, no provision for income taxes has been made in the financial statements. The unitholders are considered to own the Trust’s income and principal as though no trust were in existence. The income of the Trust is deemed to have been received or accrued by each unitholder at the time such income is received or accrued by the Trust and not when distributed by the Trust. Impairment for book purposes will not result in a loss for tax purposes for the unitholders until the loss is recognized.

All revenues from the Trust are from sources within Kansas, Oklahoma or Wyoming. Because it distributes all of its net income to unitholders, the Trust has not been taxed at the trust level in Kansas or Oklahoma. While the Trust has not owed tax, the Trustee is required to file a return with Oklahoma 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. The Trust does not expect to file a Kansas return for the 2017 tax year because it expects to have no revenues, income or deductions in 2017 attributable to properties located in Kansas. The Trust did not file a return with Kansas for the 2016 and 2015 tax years for the same reason.

Wyoming does not have a state income tax.

Each unitholder should consult his or her own tax advisor regarding income tax requirements, if any, applicable to such person’s ownership of Trust units.

11

Unitholders should consult the Trust’s latest annual report on Form 10-K for a complete discussion of federal and state tax matters.

4. Contingencies

In December 2010, a royalty class action lawsuit was filed against XTO Energy styled Chieftain Royalty Company v. XTO Energy Inc. in Coal County District Court, Oklahoma. XTO Energy removed the case to federal court in the Eastern District of Oklahoma. The plaintiffs allege that XTO Energy wrongfully deducted fees from royalty payments on Oklahoma wells, failed to make diligent efforts to secure the best terms available for the sale of gas and its constituents, and demand an accounting to determine whether they have been fully and fairly paid gas royalty interests. The case was certified as a class action in April 2012; however, on appeal in June 2012, the 10th Circuit Court of Appeals reversed the certification of the class and remanded the case back to the trial court for further proceedings. XTO Energy has informed the Trustee that it has reached a tentative settlement for the matter. The Trustee has requested the settlement amount from XTO Energy and has been informed that at this time, the amount that XTO Energy believes should be charged to the Trust has not been determined. XTO Energy has advised the Trustee that the settlement will be allocated to all of XTO Energy’s Oklahoma wells, the majority of which are not properties in which the Trust owns an underlying net profits interest.

The Trustee has informed XTO Energy that it intends to review any claimed reductions in payment to the Trust based on the facts and circumstances of such settlement. In light of a 2014 arbitration decision in which a three panel tribunal decided that the settlement in Fankhouser v. XTO Energy, Inc., including a new royalty calculation for future royalty payments, could not be charged to the Trust, to the extent that the claims in Chieftain are similar to those in Fankhouser the Trustee would likely object to such claimed reductions. Should there be a disagreement as to whether the Trust should bear its share of a settlement or judgment the matter will be resolved by binding arbitration through the American Arbitration Association under the terms of the Indenture creating the Trust. XTO Energy has informed the Trustee that, although the amount of any reduction in net proceeds is not presently determinable, in its management’s opinion, the amount is not currently expected to be material to the Trust’s financial position or liquidity though it could be material to the Trust’s annual distributable income. Additionally, XTO Energy has advised the Trustee that any reductions would result in costs exceeding revenues on the properties underlying the net profits interests of the case, as applicable, for several monthly distributions, depending on the size of the settlement, if any, and the net proceeds being paid at that time, which would result in the net profits interest being limited until such time that the revenues exceed the costs for those net profit interests.

Certain of the underlying properties are involved in various other lawsuits and governmental proceedings arising in the ordinary course of business. XTO Energy has advised the Trustee that it does not believe that the ultimate resolution of these claims will have a material effect on the financial position or liquidity of the Trust, but may have an effect on annual distributable income.

Other

Several states have enacted legislation requiring state income tax withholding from nonresident recipients of oil and gas proceeds. After consultation with its tax counsel, the Trustee believes that it is not required to withhold on payments made to the unitholders. However, regulations are subject to change by the various states, which could change this conclusion. Should amounts be withheld on payments made to the Trust or the unitholders, distributions to the unitholders would be reduced by the required amount, subject to the filing of a claim for refund by the Trust or unitholders for such amount.

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5. 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 and cumulative balances by conveyance:

	Underlying
	KS			WY			Total
Cumulative excess costs remaining at 12/31/16	$	1,049,601		$	1,158,205		$	2,207,806
Net excess costs (recovery) for the quarter ended 3/31/17		(76,669	)		(686,923	)		(763,592	)
Net excess costs (recovery) for the quarter ended 6/30/17		10,426			44,584			55,010
Cumulative excess costs remaining at 6/30/17	$	983,358		$	515,866		$	1,499,224
	NPI
	KS			WY			Total
Cumulative excess costs remaining at 12/31/16	$	839,681		$	926,564		$	1,766,245
Net excess costs (recovery) for the quarter ended 3/31/17		(61,335	)		(549,538	)		(610,873	)
Net excess costs (recovery) for the quarter ended 6/30/17		8,341			35,667			44,008
Cumulative excess costs remaining at 6/30/17	$	786,687		$	412,693		$	1,199,380

Lower gas prices caused costs to exceed revenues on properties underlying the Kansas and Wyoming net profits interests for the quarter ended June 30, 2017.

Underlying cumulative excess costs for the Kansas and Wyoming conveyances remaining as of June 30, 2017 totaled $1,499,224 (NPI $1,199,380).

6. Operated Overhead

XTO Energy advised the Trustee that the May 2016 distribution included a one-time reimbursement to the Trust of $788,000 related to operated overhead corrections for the period of January 2014 through February 2016. The reimbursement affected the net profits income under the Kansas, Oklahoma and Wyoming conveyances by approximately $186,000, $320,000 and $282,000 respectively.

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Item 2. Trustee’s Discussion and Analysis.

The following discussion should be read in conjunction with the Trustee’s discussion and analysis contained in the Trust’s 2016 Annual Report on Form 10-K, as well as the condensed financial statements and notes thereto included in this Quarterly Report on Form 10-Q. The Trust’s Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available on the Trust’s web site at www.hgt-hugoton.com.

Distributable Income

Quarter

For the quarter ended June 30, 2017, net profits income was $1,324,846, as compared to $199,545 for second quarter 2016. This increase in net profits income is primarily the result of increased gas and oil prices ($4.2 million), partially offset by decreased gas and oil production ($1.0 million), increased taxes, transportation, and other costs ($0.7 million), increased overhead ($0.7 million), net excess costs activity ($0.3 million), increased development costs ($0.3 million) and increased production expense ($0.1 million). See “Net Profits Income” below.

After adding interest income of $1,605 and deducting administration expense of $176,171, distributable income for the quarter ended June 30, 2017 was $1,150,280, or $0.028757 per unit of beneficial interest. Administration expense for the quarter decreased $17,319 as compared to the prior year quarter, primarily related to the timing of receipt and payment of Trust expenses and terms of professional services. Changes in interest income are attributable to fluctuations in net profits income and interest rates. For second quarter 2016, distributable income was $0 or $0.000000 per unit.

Distributions to unitholders for the quarter ended June 30, 2017 were:

Record Date	Payment Date	Distribution per Unit
April 28, 2017	May 12, 2017	$0.012640
May 31, 2017	June 14, 2017	0.006021
June 30, 2017	July 17, 2017	0.010096
		$0.028757

Six Months

For the six months ended June 30, 2017, net profits income was $3,548,472 compared with $263,107 for the same 2016 period. This increase in net profits income is primarily the result of increased gas and oil prices ($8.5 million) and decreased production expense ($0.3 million), partially offset by decreased gas and oil production ($1.9 million), net excess costs activity ($1.5 million), increased taxes, transportation, and other ($1.5 million), increased overhead ($0.4 million) and increased development costs ($0.2 million). See “Net Profits Income” below.

After adding interest income of $2,525 and deducting administration expense of $514,037, distributable income for the six months ended June 30, 2017 was $3,036,960, or $0.075924 per unit of beneficial interest. Administration expense for the six months ended June 30, 2017 decreased $23,300 as compared to the same 2016 period, primarily related to the timing of receipt and payment of Trust expenses and terms of professional services. Changes in interest income are attributable to fluctuations in net profits income and interest rates. For the six months ended June 30, 2016, distributable income was $0, or $0.000000 per unit.

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Net Profits Income

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:

– oil and gas sales volumes,

– oil and gas sales prices, and

– costs deducted in the calculation of net profits income.

15

The following is a summary of the calculation of net profits income received by the Trust:

	Three Months Ended June 30 (a)						Increase (Decrease)	Six Months Ended June 30 (a)					Increase (Decrease)
	2017			2016				2017		2016
Sales Volumes
Gas (Mcf) (b)
Underlying properties		3,399,989			3,693,407		(8%)		6,940,042		7,457,374		(7%)
Average per day		38,202			41,038		(7%)		38,343		40,975		(6%)
Net profits interests		421,422			103,592		307%		1,057,499		132,147		700%
Oil (Bbls) (b)
Underlying properties		39,596			47,291		(16%)		78,301		94,635		(17%)
Average per day		445			525		(15%)		433		520		(17%)
Net profits interests		7,281			1,827		299%		17,221		2,322		642%
Average Sales Prices
Gas (per Mcf)		$2.83			$1.61		76%		$3.00		$1.76		70%
Oil (per Bbl)		$48.42			$32.28		50%		$47.50		$32.75		45%
Revenues
Gas sales	$	9,630,525		$	5,964,005		61%	$	20,820,167	$	13,121,630		59%
Oil sales		1,917,419			1,526,739		26%		3,719,455		3,099,318		20%
Total Revenues		11,547,944			7,490,744		54%		24,539,622		16,220,948		51%
Costs
Taxes, transportation and other		2,131,068			1,215,472		75%		4,189,701		2,310,709		81%
Production expense		4,365,737			4,171,539		5%		8,316,224		8,717,574		(5%)
Development costs (c)		600,000			250,000		140%		1,200,000		925,000		30%
Overhead (d)		2,850,091			2,004,119		42%		5,689,525		5,164,142		10%
Excess costs (e)		(55,010	)		(399,818	)	(86%)		708,582		(1,225,361	)	N/A
Total Costs		9,891,886			7,241,312		37%		20,104,032		15,892,064		27%
Net Proceeds		1,656,058			249,432		564%		4,435,590		328,884		N/A
Net Profits Percentage		80%			80%				80%		80%
Net Profits Income	$	1,324,846		$	199,545		564%	$	3,548,472	$	263,107		N/A

(a) Because of the two-month interval between time of production and receipt of net profits income by the Trust, (1) gas and oil sales for the quarter ended June 30 generally represent production for the period February through April and (2) gas and oil sales for the six months ended June 30 generally represent production for the period November through April.

(b) Gas and oil sales volumes are allocated to the net profits interests by dividing Trust net cash inflows by average sales prices. As gas and oil 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 gas and oil sales volumes is based on the underlying properties.

(c) See Note 2 to Condensed Financial Statements.

(d) See Note 6 to Condensed Financial Statements.

(e) See Note 5 to Condensed Financial Statements.

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The following are explanations of significant variances on the underlying properties from second quarter 2016 to second quarter 2017 and from the first six months of 2016 to the comparable period in 2017:

Sales Volumes

Gas

Gas sales volumes decreased 8% for second quarter and 7% for the six-month period as compared with the same 2016 periods primarily due to natural production decline.

Oil

Oil sales volumes decreased 16% for second quarter and 17% for the six-month period as compared with the same 2016 periods primarily due to natural production decline and the timing of cash receipts.

The estimated rate of natural production decline on the underlying oil and gas properties is approximately 6% to 8% a year.

Sales Prices

Gas

The second quarter 2017 average gas price was $2.83 per Mcf, a 76% increase from the second quarter 2016 average gas price of $1.61 per Mcf. For the six-month period, the average gas price increased 70% to $3.00 per Mcf in 2017 from $1.76 per Mcf in 2016. The second quarter 2017 gas price is primarily related to production from February through April 2017, when the average NYMEX price was $3.06 per MMBtu.

Oil

The second quarter 2017 average oil price was $48.42 per Bbl, a 50% increase from the second quarter 2016 average oil price of $32.28 per Bbl. The year-to-date average oil price increased 45% to $47.50 per Bbl in 2017 from $32.75 per Bbl in 2016. The second quarter 2017 oil price is primarily related to production from February through April 2017, when the average NYMEX price was $51.45 per Bbl.

Costs

Taxes, Transportation and Other

Taxes, transportation and other costs increased 75% for the second quarter and 81% for the six-month period primarily because of increased production taxes related to higher gas and oil revenues and increased gas deductions related to higher gathering fees.

Production Expense

Production expense increased 5% for the second quarter primarily because of increased salt water disposal costs and maintenance activity, partially offset by a decrease in other field goods and services. Production expense decreased 5% for the six-month period primarily because of decreased labor and other field goods and services, partially offset by increased salt water disposal costs.

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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. These development costs increased 140% for the second quarter and 30% for the six-month period. The monthly development cost deduction will be reevaluated by XTO Energy and revised as necessary. For further information on development costs, see Note 2 to Condensed Financial Statements.

Overhead

Overhead increased 42% for the quarter and 10% for the six-month period primarily because of a one-time reimbursement related to operated overhead corrections in 2016, partially offset by the annual rate adjustment based on an industry index. See Note 6 to Condensed Financial Statements.

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 and Wyoming conveyances remaining as of June 30, 2017 totaled $1,499,224 (NPI $1,199,380). For further information on excess costs, see Note 5 to Condensed Financial Statements.

Impairment of Net Profits Interest

In light of lower long term prices used to develop projections of future cash flows, continued excess costs on two conveyances and zero distributions to unitholders for the quarter ended June 30, 2016, the Trustee concluded in the second quarter of 2016 that the events or circumstances indicated the carrying value may not be recoverable and an assessment of the forecasted net cash flows was performed for the NPI. The fair value of the NPI was developed using estimates for future oil and gas production attributable to the Trust, future crude oil and natural gas commodity prices published by third-party industry experts (adjusted for basis differentials), estimated taxes, development and operating expenses, and a risk-adjusted discount rate. The result of the assessment indicated that the estimated undiscounted future net cash flows from the NPI were below the carrying value of the NPI. The NPI was written down to its fair value of $28.8 million, resulting in a $57.3 million impairment charged directly to trust corpus, which did not affect distributable income. There was no impairment of the NPI during the quarter ended June 30, 2017.

Marketing

XTO Energy has advised the Trustee that, effective April 1, 2017, Cross Timbers Energy Services, Inc. (“CTES”), a wholly owned marketing subsidiary of XTO Energy, has assigned all gas sales contracts for production from the underlying properties to XTO Energy. XTO Energy will directly market and sell the gas to third parties. XTO Energy has advised the Trustee that there are no changes to the terms of the contracts related to the assignment and no impact on Trust distributions.

For further information regarding natural gas sales from the underlying properties to affiliates of XTO Energy, see Significant Properties, under Item 2, Properties and Note 7 to the Financial Statements under Item 8, Financial Statements and Supplementary Data of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2016.

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Contingencies

For information on contingencies, see Note 4 to Condensed Financial Statements.

Forward-Looking Statements

Statements in this report relating to future plans, predictions, events or conditions are forward-looking statements. All statements other than statements of historical fact included in this Form 10-Q, including, without limitation, statements regarding the net profits interests, underlying properties, development activities, annual and monthly development, production and other costs and expenses, monthly development cost deductions, oil and gas prices and differentials to NYMEX prices, supply levels, future drilling, workover and restimulation plans, the outcome of litigation and impact on Trust proceeds, distributions to unitholders, and industry and market conditions, are forward-looking statements that are subject to risks and uncertainties which are detailed in Part I, Item 1A of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2016, which is incorporated by this reference as though fully set forth herein. XTO Energy and the Trustee assume no duty to update these statements as of any future date.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

There have been no material changes in the Trust’s market risks from the information disclosed in Part II, Item 7A of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2016.

Item 4. Controls and Procedures.

As of the end of the period covered by this report, the Trustee carried out an evaluation of the effectiveness of the Trust’s disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15. Based upon that evaluation, the Trustee concluded that the Trust’s disclosure controls and procedures are effective in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934 and are effective in ensuring that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the Trustee to allow timely decisions regarding required disclosure. In its evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by XTO Energy. There has not been any change in the Trust’s internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

Refer to Note 4 of this Quarterly Report on Form 10-Q for information on legal proceedings.

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed under Part I, Item 1A of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2016.

Item 6. Exhibits.

(a) Exhibits.

Exhibit Number and Description
(31)	Rule 13a-14(a)/15d-14(a) Certification
(32)	Section 1350 Certification
(99)	Items 1A, 7 and 7A to the Annual Report on Form 10-K for Hugoton Royalty Trust filed with the Securities and Exchange Commission on March 10, 2017 (incorporated herein by reference)

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

	HUGOTON ROYALTY TRUST By SOUTHWEST BANK, TRUSTEE
	By	/S/ NANCY G. WILLIS
		Nancy G. Willis
		Vice President
	EXXON MOBIL CORPORATION
Date: August 4, 2017	By	/S/ DAVID LEVY
		David Levy
		Vice President - Upstream Business Services

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