HUGOTON ROYALTY TRUST - Quarter Report: 2023 June (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2023

OR

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

For the transition period from                      to                     .

Hugoton Royalty Trust

(Exact name of registrant as specified in its charter)

 

Texas		1-10476		58-6379215
(State or other jurisdiction of                 incorporation or organization)		(Commission File Number)		(I.R.S. Employer Identification No.)

c/o The Corporate Trustee:

Argent Trust Company

3838 Oak Lawn Ave, Suite 1720

Dallas, Texas 75219-4518

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code (855) 588-7839

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

2911 Turtle Creek Blvd, Suite 850

Dallas, Texas 75219

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

 

Title of each class		Trading symbol		Name of each exchange on which registered
Units of Beneficial Interest		HGTXU		OTCQB

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 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			☐			Accelerated filer			☐
Non-accelerated filer			☑			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 Rule 12b-2 of the Exchange Act).  Yes ☐  No ☑

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

Outstanding as of August 3, 2023

40,000,000

HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2023

TABLE OF CONTENTS

 

Glossary of Terms					3
PART I - FINANCIAL INFORMATION					4
Item 1.		Financial Statements (Unaudited)			4
Condensed Statements of Assets, Liabilities and Trust Corpus at June  30, 2023 and December 31, 2022					5
Condensed Statements of Distributable Income for the Three and Six Months Ended June 30, 2023 and 2022					6
Condensed Statements of Changes in Trust Corpus for the Three and Six Months Ended June 30, 2023 and 2022					7
Notes to Condensed Financial Statements					8
Item 2.		Trustee’s Discussion and Analysis			12
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			17
Item 4.		Controls and Procedures			17
PART II - OTHER INFORMATION					18
Item 1.		Legal Proceedings			18
Item 1A.		Risk Factors			19
Item 5.		Other Information			19
Item 6.		Exhibits			19
Signatures					20

 

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 income tax 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. Unless specified otherwise, all amounts included herein are presented in U.S. dollars. 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, 2023, and the distributable income and changes in trust corpus for the three-month and six-month periods ended June 30, 2023 and 2022, have been included. Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

 

4

HUGOTON ROYALTY TRUST

 

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

 

		June 30, 2023								December 31, 2022
ASSETS
Cash and short-term investments		$	1,021,382							$	2,829,458
Interest to be received			4,738								4,902
Net profits interests in oil and gas properties - net (Note 1)			-								-
		$	1,026,120							$	2,834,360
LIABILITIES AND TRUST CORPUS
Distribution payable to unitholders		$	26,120							$	1,834,360
Expense reserve (a)			1,000,000								1,000,000
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)			-								-
		$	1,026,120							$	2,834,360

 

(a)	The expense reserve allows the Trustee to pay its obligations should it be unable to pay them out of the net profits income.

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

 

5

HUGOTON ROYALTY TRUST

 

Condensed Statements of Distributable Income (Unaudited)

 

		Three Months Ended																Six Months Ended
		June 30																June 30
		2023								2022								2023								2022
Net profits income		$	1,008,161							$	1,856,317							$	11,467,914							$	2,203,727
Interest income			27,104								-								44,648								-
Total income			1,035,265								1,856,317								11,512,562								2,203,727
Administration expense			114,505								166,018								416,042								333,419
Cash reserves withheld (used) for Trust expenses			-								652,451								-								652,451
Change in accounts payable to the Trustee (increase)/decrease			-								1,037,848								-								1,217,857
Distributable income		$	920,760							$	-							$	11,096,520							$	-
Distributable income per unit (40,000,000 units)		$	0.023019							$	0.000000							$	0.277413							$	0.000000

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

 

6

HUGOTON ROYALTY TRUST

 

Condensed Statements of Changes in Trust Corpus (Unaudited)

 

		Three Months Ended								Six Months Ended
		June 30								June 30
		2023				2022				2023				2022
Trust corpus, beginning of period		$	-			$	(1,037,848	)		$	-			$	(1,217,857	)
Distributable income			920,760				-				11,096,520				-
Distributions declared			(920,760	)			-				(11,096,520	)			-
Change in accounts payable to the Trustee (increase)/decrease			-				1,037,848				-				1,217,857
Trust corpus, end of period		$	-			$	-			$	-			$	-

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

 

7

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. (“XTO Energy”), the owner of the underlying properties, to Argent Trust Company, as trustee (the “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’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.

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.

 

8

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 net profits interests 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 net profits interests 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 using proved reserves and is charged directly to trust corpus. Accumulated amortization was $174,078,891 as of September 30, 2019, when the net profits interests was written down to its fair value of zero.

 

2.	Income Taxes

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

All revenues from the Trust are from sources within Kansas, Oklahoma or Wyoming. Because it distributes all of its net income to unitholders, the Trust has not been taxed at the trust level in Kansas or Oklahoma. While the Trust has not owed tax, the Trustee is generally required to file Kansas and Oklahoma income tax returns reflecting the income and deductions of the Trust attributable to properties located in each state, along with a schedule that includes information regarding distributions to unitholders.

Wyoming does not impose a state income tax.

The Trust may be required to bear a portion of the settlement costs arising from the Chieftain royalty class action settlement. For information on contingencies, including the Chieftain class action, see Note 3 to Condensed Financial Statements. The Panel has determined the Trust is responsible for a portion of the costs. Pending finalization of all claims included in the arbitration, XTO Energy would have the right to deduct the costs in its calculation of the net profits income payable to the Trust from the applicable net profits interests. Thus, for unitholders, the portion of legal settlement costs for which the Trust is determined to be responsible will be reflected through a reduction in net profits 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 their own tax advisor regarding income tax requirements, if any, applicable to such person’s ownership of Trust units.

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

 

9

3.	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 advised the Trustee that it believes approximately $24.3 million in additional production costs should be allocated to the Trust. On May 2, 2018, the Trustee submitted a demand for arbitration seeking a declaratory judgment that the Chieftain settlement is not a production cost and that XTO Energy is prohibited from charging the settlement as a production cost under the conveyance or otherwise reducing the Trust’s payments now or in the future as a result of the Chieftain litigation. The Trust and XTO Energy conducted the interim hearing on the claims related to the Chieftain settlement on October 12-13, 2020. In the arbitration, the Trustee contended that the approximately $24.3 million allocation related to the Chieftain settlement was not a production cost and, therefore, there should not be a related adjustment to the Trust’s share of net proceeds. However, XTO Energy contended that the approximately $24.3 million was a production cost and should reduce the Trust’s share of net proceeds.

On January 20, 2021, the arbitration panel issued its Corrected Interim Final Award (i) “reject[ing] the Trust’s contention that XTO has no right under the Conveyance to charge the Trust with amounts XTO paid under section 1.18(a)(i) as royalty obligations to settle the Chieftain litigation” and (ii) stating “[t]he next phase will determine how much of the Chieftain settlement can be so charged, if any of it can be, in the exercise of the right found by the Panel.” Following briefing by both parties, on May 18, 2021, the Panel issued its second interim final award over the amount of XTO Energy’s settlement in the Chieftain class action lawsuit that can be charged to the Trust as a production cost. The Panel in its decision has ruled that out of the $80 million settlement, the “Trust is obligated to pay its share under the Conveyance of the $48 million that was received by the plaintiffs in the Chieftain lawsuit by virtue of the settlement of that litigation. The Trust is not obligated by the Conveyance to pay any share of the $32 million received by the lawyers for the plaintiffs in the Chieftain lawsuit by virtue of the settlement.” XTO Energy and the Trustee are in the process of determining the portion of the $48 million that is allocable to Trust properties to be charged as an excess cost to the Trust, but estimate it to be approximately $14.6 million net to the Trust.

The reduction in the Trust’s share of net proceeds from the portion of the settlement amount the Panel has ruled may be charged against the Oklahoma conveyance would result in excess costs under the Oklahoma conveyance that would likely result in no distributions under the Oklahoma conveyance while these excess costs are recovered. This award completes the portion of the arbitration related to the Chieftain settlement. Excess costs on any individual conveyance would not affect net proceeds to the Trust on any of the other remaining conveyances.

Other Trustee claims related to disputed amounts on the computation of the Trust’s net proceeds for 2014 through 2019 and 2021 were bifurcated from the initial arbitration. The final hearing regarding the remaining dispute over net proceeds is scheduled to occur November 8, 2023.

Other Lawsuits and Governmental Proceedings

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

 

10

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.

 

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 as calculated by XTO Energy:

 

For the quarter ended June 30, 2023, excess costs were $177,356 ($141,885 net to the Trust) on properties underlying the Kansas net profits interests.

For the quarter ended June 30, 2023, excess costs were $1,146,689 ($917,351 net to the Trust) on properties underlying the Oklahoma net profits interests. This balance does not include the portion of the Chieftain settlement the Panel determined could be charged as a production cost. XTO Energy has estimated the amount to be approximately $14.6 million net to the Trust. For the quarter ended June 30, 2023, recoveries of accrued interest were $943 ($754 net to the Trust) on properties underlying the Oklahoma net profits interests.

Underlying cumulative excess costs for the Kansas and Oklahoma conveyances remaining as of June 30, 2023, totaled $1.3 million ($1.1 million net to the Trust), including accrued interest of $1,697 ($1,358 net to the Trust).

 

11

5.	Administration Expense

Administrative expenses are incurred so that the Trustee may meet its reporting obligations to the unitholders and regulatory entities and otherwise manage the administrative functions of the Trust. These obligations include, but are not limited to, all expenses, taxes, compensation to the Trustee for managing the Trust, fees to consultants, accountants, attorneys, transfer agents, other professional and expert persons, expenses for clerical and other administrative assistance, and fees and expenses for all other services.

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 2022 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 website at www.hgt-hugoton.com.

Distributable Income

Quarter

For the quarter ended June 30, 2023, net profits income was $1,008,161 as compared to $1,856,317 for second quarter 2022 primarily due to lower oil and gas prices ($4.4 million), decreased oil and gas production ($3.8 million), increased production expenses ($0.9 million), and increased development costs ($0.4 million), partially offset by net excess costs activity ($8.1 million), and decreased taxes, transportation and other costs ($0.6 million). See “Net Profits Income” below.

After adding interest income of $27,104, and deducting administration expense of $114,505, distributable income for the quarter ended June 30, 2023, was $920,760, or $0.023019 per unit of beneficial interest. Administration expense for the quarter decreased $51,513 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, cash reserve and interest rates. For second quarter 2022, distributable income was $0, or $0.000000 per unit.

Distributions to unitholders for the quarter ended June 30, 2023, were:

 

Record Date		Payment Date							Distribution               per Unit
April 28, 2023		May 12, 2023								$	0.012363
May 31, 2023		June 14, 2023									0.010003
June 30, 2023		July 17, 2023									0.000653
										$	0.023019

 

12

Six Months

For the six months ended June 30, 2023, net profits income was $11,467,914 compared with $2,203,727 for the same 2022 period primarily due to net excess costs activity ($16.1 million), higher gas and oil prices ($3.3 million), partially offset by decreased oil and gas production ($5.7 million), increased production expenses ($1.8 million), increased taxes, transportation and other costs ($1.5 million), and increased development costs ($1.1 million). See “Net Profits Income” below.

After adding interest income of $44,648 and deducting administration expense of $416,042, distributable income for the six months ended June 30, 2023, was $11,096,520, or $0.277413 per unit of beneficial interest. Administration expense for the six months ended June 30, 2023, increased $82,623 as compared to the same 2022 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, cash reserve and interest rates. For the six months ended June 30, 2022, distributable income was $0, or $0.000000 per unit.

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.

 

13

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

 

		Three Months												Six Months
		Ended June 30 (a)								Increase				Ended June 30 (a)								Increase
		2023				2022				(Decrease)				2023				2022				(Decrease)
Sales Volumes
Gas (Mcf) (b)
Underlying properties			2,301,331				2,362,272				(3%)				4,618,368				4,828,246				(4%)
Average per day			25,858				26,542				(3%)				25,516				26,675				(4%)
Net profits interests			168,072				318,458				(47%)				990,526				368,514				169%
Oil (Bbls) (b)
Underlying properties			36,572				98,148				(63%)				75,619				148,997				(49%)
Average per day			411				1,103				(63%)				418				823				(49%)
Net profits interests			750				3,648				(79%)				11,205				3,732				200%
Average Sales Prices
Gas (per Mcf)			$  4.10				$  6.33				(35%)				$  7.34				$  6.52				13%
Oil (per Bbl)			$73.91				$76.08				(3%)				$76.54				$75.75				1%
Revenues
Gas sales			$9,426,973				$14,944,684				(37%)				$33,892,343				$31,479,038				8%
Oil sales			2,703,195				7,466,656				(64%)				5,787,970				11,286,552				(49%)
Total Revenues			12,130,168				22,411,340				(46%)				39,680,313				42,765,590				(7%)
Costs
Taxes, transportation and other			2,526,101				3,301,879				(23%)				7,569,190				5,733,949				32%
Production expense			5,630,546				4,562,858				23%				10,249,554				7,973,249				29%
Development costs			810,531				292,723				177%				2,559,137				1,180,043				117%
Overhead			3,225,891				3,185,596				1%				6,290,402				6,351,101				(1%)
Excess costs (c)			(1,323,102)				8,747,920				(115%)				(1,322,862)				18,772,621				(107%)
Total Costs			10,869,967				20,090,976				(46%)				25,345,421				40,010,963				(37%)
Other Proceeds			-				32				(100%)				-				32				(100%)
Net Proceeds			1,260,201				2,320,396				(46%)				14,334,892				2,754,659				420%
Net Profits Percentage			80%				80%								80%				80%
Net Profits Income			$1,008,161				$ 1,856,317				(46%)				$11,467,914				$ 2,203,727				420%

 

(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 4 to Condensed Financial Statements.

 

14

The following are explanations of significant variances on the underlying properties from second quarter 2022 to second quarter 2023 and from the first six months of 2022 to the comparable period in 2023:

Sales Volumes

Gas

Gas sales volumes decreased 3 percent for second quarter and decreased 4 percent for the six-month period as compared with the same 2022 periods primarily because of natural production decline and timing of cash receipts.

Oil

Oil sales volumes decreased 63 percent for second quarter and 49 percent for the six-month period as compared with the same 2022 periods primarily because of timing of cash receipts and natural production decline.

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

Sales Prices

Gas

The second quarter 2023 average gas price was $4.10 per Mcf, a 35 percent decrease from the second quarter 2022 average gas price of $6.33 per Mcf. For the six-month period, the average gas price increased 13 percent to $7.34 per Mcf in 2023 from $6.52 per Mcf in 2022.

Oil

The second quarter 2023 average oil price was $73.91 per Bbl, a 3 percent decrease from the second quarter 2022 average oil price of $76.08 per Bbl. The year-to-date average oil price increased 1 percent to $76.54 per Bbl in 2023 from $75.75 per Bbl in 2022.

Costs

Taxes, Transportation and Other

Taxes, transportation and other costs decreased 23 percent for the second quarter primarily because of decreased production and gas deductions due to lower revenues. Taxes, transportation and other costs increased 32 percent for the six-month period primarily because of increased gas production taxes due to higher revenues and absence of Oklahoma production tax refunds.

Production Expense

Production expense increased 23 percent for the second quarter and 29 percent for the six-month period primarily because of increased repairs and maintenance costs, labor, and timing of the annual Oklahoma Senate Bill 168 fee, partially offset by decreased power and fuel costs.

 

15

Development Costs

Development costs increased 177 percent for the second quarter and 117 percent for the six-month period primarily because of increased drilling costs related to non-operated wells. Changes in oil or natural gas prices could impact future development plans on the underlying properties.

As previously disclosed, XTO Energy advised the Trustee that it elected to participate in the development of three non-operated wells in Major County, Oklahoma. Two of the wells were completed in second quarter of 2023 and one well is expected to be completed in third quarter of 2023. XTO Energy advised the Trustee that the total development costs for the three non-operated wells was anticipated to be approximately $9 million underlying ($7 million net to the Trust). No assurances can be made as to the estimated costs of the non-operated wells, timing to complete the third well, or timing of receipt of costs for drilling the wells.

Overhead

Overhead increased 1 percent for the second quarter and decreased 1 percent for the six-month period. 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 based on an industry index.

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 Oklahoma conveyances remaining as of June 30, 2023, totaled $1.3 million ($1.1 million net to Trust), including accrued interest of $1,697 ($1,358 net to Trust). For further information on excess costs, see Note 4 to Condensed Financial Statements.

Contingencies

For information on contingencies, see Note 3 to Condensed Financial Statements.

Forward-Looking Statements

Certain information included in this quarterly 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, excess costs, reserve-to-production ratios, future production, development activities and associated operating expenses, future development plans by area, increased density drilling, maintenance projects, development, production, regulatory and other costs, oil and gas prices and expectations for future demand, the impact of inflation and economic downturns on economic activity, government policy and its impact on oil and gas prices and future demand, the development and competitiveness of alternative energy sources, pricing differentials, proved reserves, future net cash flows, production levels, expense reserve budgets, availability of financing, arbitration, litigation, liquidity, financing, political and regulatory matters, such as tax and environmental policy, climate policy, trade barriers, sanctions, competition, war and other political or security disturbances. Such forward-looking statements are based on XTO Energy’s and the Trustee’s current plans, expectations, assumptions, projections and estimates and are identified by words such as “may,” “intends,” “plans,” “anticipates,” “believes,” “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, including those detailed in Part I, Item 1A of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2022, which is incorporated by this reference as though fully set forth herein. 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. XTO Energy and the Trustee assume no duty to update these statements as of any future date.

 

16

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable. Upon qualifying as a smaller reporting company, this information is no longer required.

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.

 

17

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

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 advised the Trustee that it believes approximately $24.3 million in additional production costs should be allocated to the Trust. On May 2, 2018, the Trustee submitted a demand for arbitration seeking a declaratory judgment that the Chieftain settlement is not a production cost and that XTO Energy is prohibited from charging the settlement as a production cost under the conveyance or otherwise reducing the Trust’s payments now or in the future as a result of the Chieftain litigation. The Trust and XTO Energy conducted the interim hearing on the claims related to the Chieftain settlement on October 12-13, 2020. In the arbitration, the Trustee contended that the approximately $24.3 million allocation related to the Chieftain settlement was not a production cost and, therefore, there should not be a related adjustment to the Trust’s share of net proceeds. However, XTO Energy contended that the approximately $24.3 million was a production cost and should reduce the Trust’s share of net proceeds.

On January 20, 2021, the arbitration panel issued its Corrected Interim Final Award (i) “reject[ing] the Trust’s contention that XTO has no right under the Conveyance to charge the Trust with amounts XTO paid under section 1.18(a)(i) as royalty obligations to settle the Chieftain litigation” and (ii) stating “[t]he next phase will determine how much of the Chieftain settlement can be so charged, if any of it can be, in the exercise of the right found by the Panel.” Following briefing by both parties, on May 18, 2021, the Panel issued its second interim final award over the amount of XTO Energy’s settlement in the Chieftain class action lawsuit that can be charged to the Trust as a production cost. The Panel in its decision has ruled that out of the $80 million settlement, the “Trust is obligated to pay its share under the Conveyance of the $48 million that was received by the plaintiffs in the Chieftain lawsuit by virtue of the settlement of that litigation. The Trust is not obligated by the Conveyance to pay any share of the $32 million received by the lawyers for the plaintiffs in the Chieftain lawsuit by virtue of the settlement.” XTO Energy and the Trustee are in the process of determining the portion of the $48 million that is allocable to Trust properties to be charged as an excess cost to the Trust, but estimate it to be approximately $14.6 million net to the Trust.

The reduction in the Trust’s share of net proceeds from the portion of the settlement amount the Panel has ruled may be charged against the Oklahoma conveyance would result in excess costs under the Oklahoma conveyance that would likely result in no distributions under the Oklahoma conveyance while these excess costs are recovered. This award completes the portion of the arbitration related to the Chieftain settlement. Excess costs on any individual conveyance would not affect net proceeds to the Trust on any of the other remaining conveyances.

Other Trustee claims related to disputed amounts on the computation of the Trust’s net proceeds for 2014 through 2019 and 2021 were bifurcated from the initial arbitration. The final hearing regarding the remaining dispute over net proceeds is scheduled to occur November 8, 2023.

Other Lawsuits and Governmental Proceedings

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

 

18

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, 2022.

Item 5. Other Information

The Trust does not have any directors or officers, and as a result, no such persons adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

Item 6.    Exhibits

 

 

19

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 ARGENT TRUST COMPANY, TRUSTEE
				By		/s/ NANCY WILLIS
						Nancy Willis
						Vice President
				EXXON MOBIL CORPORATION
Date: August 11, 2023				By		/s/ WENDI POWELL
						Wendi Powell
						Upstream Controller

(The Trust has no directors or executive officers.)

 

20