UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

 

SCHEDULE 14D-9

(RULE 14d-101)

SOLICITATION/RECOMMENDATION STATEMENT

UNDER SECTION 14(d)(4) OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

HUGOTON ROYALTY TRUST

(Name of Subject Company)

 

 

HUGOTON ROYALTY TRUST

(Name of Person(s) Filing Statement)

 

 

UNITS OF BENEFICIAL INTEREST

(Title of Class of Securities)

444717102

(CUSIP Number of Class of Securities)

c/o Trustee:

Simmons Bank

2911 Turtle Creek Blvd, Suite 850

Dallas, Texas 75219

(855) 588-7839

(Name, Address and Telephone Number of Person Authorized to Receive Notices and Communications on Behalf of the Person(s) Filing Statement)

With copies to:

Amy R. Curtis

Thompson & Knight LLP

One Arts Plaza

1722 Routh Street, Suite 1500

Dallas, TX 75201-2533

 

 

 

☐

Check the box if the filing relates solely to preliminary communications made before the commencement of a tender offer.

 

 

 

TABLE OF CONTENTS

 

		Page
Item 1. Subject Company Information.			1
Item 2. Identity and Background of Filing Person.			1
Item 3. Past Contacts, Transactions, Negotiations and Agreements.			1
Item 4. The Solicitation or Recommendation.			2
Item 5. Person/Assets, Retained, Employed, Compensated or Used.			12
Item 6. Interest in Securities of the Subject Company.			12
Item 7. Purposes of the Transaction and Plans or Proposals.			12
Item 8. Additional Information.			12
Item 9. Exhibits.			13

 

i

Item 1.

Subject Company Information.

The name, address and telephone number of the subject company are as follows:

Hugoton Royalty Trust

c/o Simmons Bank, Trustee

2911 Turtle Creek Blvd., Suite 850

Dallas, Texas 75219

(855) 588-7839

The title and number of the class of equity securities to which this Statement relates are 40,000,000 outstanding units of beneficial interest as of April 14, 2020.

 

Item 2.

Identity and Background of Filing Person.

The name, address and telephone number of the filing person are as follows:

Hugoton Royalty Trust

c/o Simmons Bank, Trustee

2911 Turtle Creek Blvd., Suite 850

Dallas, Texas 75219

(855) 588-7839

The Trust’s website is www.hgt-hugoton.com. The information on the Trust’s website should not be considered a part of this Statement.

The filing person is the Trust acting through its trustee, Simmons Bank (the “Trustee”). This Statement relates to the tender offer statement that was filed on behalf of XTO Energy Inc. (“Offeror”) relating to the offer by the Offeror to purchase all of the outstanding units of beneficial interest (the “Units”) in Hugoton Royalty Trust (the “Trust”), at a price of $0.20 per Unit. The offer is subject to the terms and conditions set forth in the Tender Offer Statement on Schedule TO filed with the Securities and Exchange Commission by Offeror on April 1, 2020 (the “Offer to Purchase”). The Offer to Purchase and the related Letter of Transmittal (the “Letter of Transmittal”) and Notice of Guaranteed Delivery (the “Notice of Guaranteed Delivery”) attached to the Offer to Purchase constitute the “Offer”.

According to the Offer to Purchase, the address of the principal executive office of the Offeror is 22777 Springwoods Village Pkwy., Spring, Texas, 77389.

As of April 1, 2020, the Offeror represented in the Offer to Purchase that it did not own any Units of the Trust.

 

Item 3.

Past Contacts, Transactions, Negotiations and Agreements.

The Trust was created pursuant to agreements between the Offeror and the initial trustee of the Trust. In connection with its operation of the properties underlying the Net Profits Interests (as defined below) and its obligations pursuant to the agreements between the Offeror and the Trustee, the Offeror regularly interacts and communicates with the Trust and the Trustee. However, other than the letter from the Offeror to the Trustee dated April 1, 2020 enclosing a copy of the Offer, the Offeror has not had any contacts, transactions or negotiations with the Trustee regarding the Offer or concerning a merger, consolidation or acquisition, a tender offer or other acquisition of securities, or sale or other transfer of a material amount of the Trust’s assets.

The Trust’s Annual Report on Form 10-K for the year ended December 31, 2019 (the “2019 Form 10-K”) contains information regarding agreements, arrangements, understandings and actual or potential

 

1

conflicts of interest under the heading “Item 13. Certain Relationships and Related Transactions, and Director Independence,” a copy of which is filed as Exhibit 99.1(e)(5) to this Statement and incorporated herein by reference.

The information contained in “Item 4. The Solicitation or Recommendation” is incorporated herein by reference.

 

Item 4.

The Solicitation or Recommendation.

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 (as amended and restated on March 24, 1999, the “Trust Indenture”) between Offeror (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 holders of the Units (the “Unitholders”) that it would resign as trustee of the Trust. At a special meeting of the Trust’s Unitholders, 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. SFNC is the parent of Simmons Bank. SFNC merged Southwest Bank with Simmons Bank effective February 20, 2018, and Simmons Bank is now the Trustee of the Trust.

Effective December 1, 1998, the Offeror conveyed to the Trust net profits interests in certain long-lived, principally natural gas, properties in Kansas, Oklahoma and Wyoming under three separate conveyances (collectively, the “Conveyances”). The net profits interests are the only assets of the Trust, other than cash being held for the payment of expenses and liabilities. The net profits interests entitle the Trust to receive 80% of the net proceeds (as defined in the Conveyances) from the sales of oil and gas produced from the underlying properties, and are collectively referred to herein as the “Net Profits Interests”. In connection with the Conveyances, the Offeror is party to the Trust Indenture. The Net Profits Interests are the sole non-cash asset of the Trust other than certain short-term investments. The Offeror owns the properties underlying the Net Profits Interests and operates approximately 83% of the producing wells. In connection with such ownership and operation, the Offeror regularly interacts and communicates with the Trust and the Trustee regarding the Net Profits Interests. The Offeror also provides the annual audited statements of revenues and direct operating expenses and unaudited quarterly statements of revenues and direct operating expenses for the Trust, and together with the Trustee, prepares the Trust’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other Securities and Exchange Commission (“SEC”) filings and the Offeror’s parent company, ExxonMobil, co-signs, together with the Trustee, the SEC filings of the Trust.

The 2019 Form 10-K contains a description of the Trust, a description of the Units, information regarding the Net Profits Interests and the other information required to be included in such report as filed with the Securities and Exchange Commission, a copy of which is filed as Exhibit 99.1(e)(5) to this Statement and incorporated herein by reference. A copy of the 2019 Form 10-K (excluding exhibits) was included in the 2019 Annual Report of the Trust to Unitholders, which was posted to the Trust’s website in April of 2020. The provisions governing the Trust are complex and extensive and no attempt has been made herein or was made in the 2019 Form 10-K to describe or reference all such provisions. The 2019 Form 10-K contains a general description of the basic framework of the Trust and a summary of the material terms of the Trust Indenture, and detailed provisions concerning the Trust may be found in the Trust Indenture, which is filed as Exhibit 99.1(e)(1) to this Statement and incorporated herein by reference.

Under the Trust Indenture, the Trustee has certain powers to take such action as in its judgment is necessary or advisable to achieve the purposes of the Trust, including the authority to enter into the Conveyances, to agree to modifications or settlements of the terms of the Conveyances or to settle disputes with respect thereto. If Trustee determines that it is in the best interest of the Unitholders to sell all or any part of any of the Net

 

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Profits Interests for cash as it deems in the best interest of the Unitholders, it may sell such Net Profits Interests if approved by an affirmative vote of Unitholders holding at least 80% of the Units. The Trustee is not empowered to engage in any business or commercial activity of any kind except investing cash on hand or prosecuting, defending or settling certain claims against the Trust, the Trustee, or the assets of the Trust. The Trustee also has the power to collect and distribute proceeds received by the Trust, to pay Trust liabilities and expenses, to establish a cash reserve, to engage certain third parties to perform services for the Trust, to borrow funds under certain limited circumstances, and otherwise to administer the Trust. The Trustee has only such powers as are set forth in the Trust Indenture or are required by law and is not empowered otherwise to manage or take part in the administration of the Trust. The Trust has no directors, executive officers or employees. The Net Profits Interests are passive in nature and the Trustee does not have any control over or any responsibility relating to the operation of the underlying properties.

Section 3.03 of the Trust Indenture expressly provides that the Trustee shall not, in its capacity as the Trustee under the Trust, engage in any business or commercial activity of any kind whatsoever. The stated purposes of the Trust set forth in Section 2.02 of the Trust Indenture are:

 

(a)

to receive, hold, protect and conserve, for the benefit of the Unitholders, the assets held by the Trustee under the Trust Indenture;

 

(b)

to convert the Net Profits Interest to cash either (i) by retaining them and collecting the proceeds from production payable with respect thereto until production has ceased or the Net Profits Interest has otherwise terminated or (ii) by selling or otherwise disposing of all or a part of the Net Profits Interest in accordance with and subject to the terms of the Trust Indenture;

 

(c)

to pay, or provide for the payment of, any costs and liabilities incurred in carrying out the purposes of the Trust, and thereafter to distribute the remaining amounts of cash received by the Trust to the Unitholders pro rata based on the number of Units owned; and

 

(d)

subject to the restrictions on engaging in any business or commercial activity set forth above, to engage in such other activities as are necessary or convenient for the attainment of any of the foregoing or are incident thereto and which may be engaged in or carried out by a trust under the Texas Trust Code.

Accordingly, the Trustee is not authorized, within the express terms of its duties and responsibilities under the Trust Indenture, and therefore is unable to take a position with respect to the Offer.

The Trustee does not own any Units and, accordingly, does not plan to tender Units pursuant to the Offer. The Trust does not have officers, directors or employees.

Although the Trustee is not making a recommendation with respect to the Offer, the Trustee believes that the Unitholders, in conjunction with advice from the Unitholder’s financial, tax, legal and other advisors, should carefully consider the following information and the information set forth in the 2019 Form 10-K, a copy of which is filed as Exhibit 99.1(e)(5) to this Statement and incorporated herein by reference, in making their own decisions of whether to accept or reject the Offer:

Trust Provisions

The Trust Indenture provides, among other provisions, that:

 

1.

the Trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments;

 

2.

the Trust may dispose of all or part of the net profits interests if approved by a vote of holders of 80% or more of the outstanding Trust units, or upon Trust termination. Otherwise, the Trust is required to

 

3

sell up to 1% of the value of the net profits interests in any calendar year, pursuant to notice from Offeror of its desire to sell the related underlying properties. Any sale must be for cash with 80% of the proceeds distributed to the unitholders on the next declared distribution;

 

3.

the Trustee may establish a cash reserve for payment of any liability that is contingent or not currently payable;

 

4.

the Trustee may borrow funds to pay Trust liabilities if repaid in full prior to further distributions to unitholders;

 

5.

the Trustee will make monthly cash distributions to Unitholders; and

 

6.

the Trust will terminate upon the first occurrence of:

 

a)

disposition of all net profits interests pursuant to terms of the Trust indenture,

 

b)

gross proceeds from the underlying properties falling below $1 million per year for two successive years, or

 

c)

a vote of holders of 80% or more of the outstanding Trust units to terminate the Trust in accordance with provisions of the Trust Indenture.

Distributions

The Trust has had no cash distribution for more than 24 months as of April 14, 2020. The Trustee determines the amount to be distributed to the 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. Net profits income received by the Trustee consists of net proceeds received in the prior month by the Offeror from the underlying properties, multiplied by 80%. Net proceeds are the gross proceeds received from the sale of production, less costs (generally applicable taxes, transportation, legal and marketing charges, production expense, development and drilling costs, and overhead). When 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.

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 Offeror 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

 

4

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 financial statements included in the 2019 Form 10-K were 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 statement 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 included in the 2019 Form 10-K do not include any adjustments that might result from the outcome of this uncertainty.

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.

 

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The following summarizes excess costs activity, cumulative excess costs balance and accrued interest to be recovered by Conveyance:

 

		Underlying
		KS				OK				WY				Total
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			1,795,487				25,210,563				3,189,747				30,195,797
Accrued interest at 12/31/19			231,022				782,468				31,305				1,044,795
Total remaining to be recovered at 12/31/19		$	2,026,509			$	25,993,031			$	3,221,052			$	31,240,592

 

		NPI
		KS				OK				WY				Total
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			1,436,389				20,168,450				2,551,798				24,156,637
Accrued interest at 12/31/19			184,818				625,974				25,044				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.

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).

 

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Offeror

Offeror operates approximately 95% of the underlying properties. In computing net proceeds, Offeror 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 Offeror’s wholly-owned subsidiaries purchase natural gas and provide services for the properties operated by Offeror. 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 Offeror’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, Offeror became a wholly-owned subsidiary of Exxon Mobil Corporation.

Trustee Compensation

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:

 

		2019				2018
Simmons Bank, Trustee (1)		$	72,750			$	52,261
Southwest Bank, Trustee (1)			—				17,318

 

(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.

Liability of the Trustee

In carrying out its powers and performing its duties, the Trustee may act in its discretion directly or (at the Trust’s expense) through agents and attorneys, and will be liable to the unitholders only for fraud, gross negligence or acts or omissions in bad faith as adjudicated by final, non-appealable judgment of a court of competent jurisdiction. The Trustee will not be liable for any act or omission of its agents or employees unless the Trustee acted in bad faith or with gross negligence in their selection and retention. The Trustee and its officers, agents and employees when acting in such capacity will be indemnified for any liability, expense, claim, damages or loss incurred in the administration of the Trust, except in cases of fraud, gross negligence or acts or omissions in bad faith for which it is liable as described above. The Trustee will have a lien on the assets of the Trust as security for this indemnification and its compensation earned as Trustee. The Trustee is entitled to indemnification from assets of the Trust or, to the extent that assets of the Trust are exhausted, from the Offeror. Unitholders will not be liable to the Trustee for any indemnification. The Trustee must ensure that all contractual liabilities of the Trust are limited to the assets of the Trust and will be liable for its failure to do so, subject to the Trustee’s rights to be indemnified from the assets of the Trust described in this paragraph.

Royalty Class Actions and Arbitrations

Fankhouser Arbitration.

On October 10, 2012, the court approved a $37 million settlement in the royalty class action lawsuit filed against the Offeror styled Fankhouser v. XTO Energy, Inc. in the United States District Court for the

 

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Western District of Oklahoma. The Fankhouser settlement also included a new royalty calculation for future royalty payments to members of the certified class in Fankhouser. Subsequent to such settlement, the Offeror and the Trustee arbitrated the issue of whether the Trust’s pro-rata portion of the Fankhouser settlement amount constituted a production cost (as defined in the Conveyances), and would therefore be included in the calculation of net proceeds. The three-panel tribunal issued a decision on April 21, 2014, based on which the Offeror is prohibited from charging any portion of the Fankhouser settlement (including additional royalty due under the required calculation for future royalty payments to Fankhouser class members) to the Trust, now or in the future. The Offeror was also required to reimburse the Trust $4,386,396 which represents amounts withheld from the September and October 2012 distributions of the Trust and $1,985,438 which represents the Trust’s attorney fees, arbitration expenses and related interest. On December 12, 2014, the 17th state district court of Tarrant County, Texas entered the arbitration decision as a final judgment.

Chieftain Arbitration

As previously disclosed, Offeror 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 Offeror 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 Offeror 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 had been scheduled for April 27, 2020 but has been postponed due to a continuance granted by the arbitrators at the request of the Offeror related to the coronavirus pandemic to a date still to be determined. The arbitrators denied the Trustee’s request to hold the arbitration on the April 27, 2020 setting by video conference. 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 Offeror’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.

Oil and Natural Gas Reserves

Proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.

Standardized Measure

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include

 

8

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 Offeror 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.

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.

 

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Proved Reserves

 

		Underlying Properties								Net Profits Interests
		Gas				Oil				Gas				Oil
(in thousands)		(Mcf)				(Bbls)				(Mcf)				(Bbls)
Balance, December 31, 2016			92,468				1,097				4,167				66
Extensions, additions and discoveries			5				33				3				17
Revisions of prior estimates			39,851				345				10,496				109
Production - sales volumes			(13,903	)			(156	)			(1,628	)			(27	)
Sales in place			—				—				—				—
Balance, December 31, 2017			118,421				1,319				13,038				165
Extensions, additions and discoveries			9,388				674				2,513				180
Revisions of prior estimates			6,375				167				(2,313	)			106
Production - sales volumes			(12,994	)			(155	)			(448	)			(8	)
Sales in place			—				—				—				—
Balance, December 31, 2018			121,190				2,005				12,790				443
Extensions, additions and discoveries			90				53				46				27
Revisions of prior estimates			(29,994	)			(176	)			(12,726	)			(470	)
Production - sales volumes			(11,113	)			(302	)			(110	)			—
Sales in place			—				—				—				—
Balance, December 31, 2019			80,173				1,580				—				—

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

 

		Underlying Properties								Net Profits Interests
		Gas				Oil				Gas				Oil
(in thousands)		(Mcf)				(Bbls)				(Mcf)				(Bbls)
December 31, 2016			91,734				1,097				4,167				66
December 31, 2017			117,667				1,319				12,844				165
December 31, 2018			111,234				1,339				7,979				121
December 31, 2019			79,204				1,580				—				—

 

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Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

 

		December 31
(in thousands)		2019				2018				2017
Underlying Properties
Future cash inflows		$	234,398			$	413,046			$	347,055
Future costs:
Production			233,603				338,719				301,930
Development			795				6,687				795
Future net cash flows			—				67,640				44,330
10% discount factor			—				29,776				13,125
Standardized measure		$	—			$	37,864			$	31,205
Net Profits Interests
Future cash inflows		$	—			$	58,139			$	38,655
Future production taxes			—				4,027				3,192
Future net cash flows			—				54,112				35,463
10% discount factor			—				23,821				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			(35,003	)			11,684				25,717
Quantity estimates			4,456				14,205				4,667
Accretion of discount			3,869				2,731				784
Future development costs			(12,093	)			(27,592	)			(2,667	)
Production rates and other			195				687				(586	)
Net revisions			(38,576	)			1,715				27,915
Extensions, additions and discoveries			1,174				6,932				401
Production			(18,513	)			(23,791	)			(9,447	)
Development costs			18,051				21,803				2,800
Sales in place			—				—				—
Net change			(37,864	)			6,659				21,669
Standardized measure, December 31		$	—			$	37,864			$	31,205
Net Profits Interests
Standardized measure, January 1		$	30,291			$	24,964			$	7,628
Extensions, additions and discoveries			939				5,545				321
Accretion of discount			3,095				2,185				628
Revisions of prior estimates, changes in price and other			(33,956	)			(812	)			21,705
Sales in place			—				—				—
Net profits income			(369	)			(1,591	)			(5,318	)
Standardized measure, December 31		$	—			$	30,291			$	24,964

 

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Item 5.

Person/Assets, Retained, Employed, Compensated or Used.

No persons or classes of persons have been employed, retained or are to be compensated to make recommendations in connection with this transaction.

 

Item 6.

Interest in Securities of the Subject Company.

Neither the filing person, nor any person within the scope of the instructions to Item 1008(b) of Regulation M-A, engaged in any transaction in the subject securities in the past 60 days. The Trust has no directors or executive officers.

 

Item 7.

Purposes of the Transaction and Plans or Proposals.

The Trust (here the subject company) is not undertaking or engaged in any negotiations in response to the Offer that relate to:

 

1.

A tender offer or other acquisition of the subject company’s securities by the filing person, any of its subsidiaries or any other person; or

 

2.

 

a.

Any extraordinary transaction, such as a merger, reorganization or liquidation, involving the subject company (which has no subsidiaries);

 

b.

Any purchase, sale or transfer of a material amount of assets of the subject company (which has no subsidiaries); or

 

c.

Any material change in the present dividend rate or policy, or indebtedness or capitalization of the subject company.

According to the Offer, the Offeror is extending the Offer because the Offeror wants to acquire at least 80% of the outstanding Units. The Offer is conditioned on there being validly tendered and not withdrawn on April 28, 2020, as may be extended (the “Expiration Date”) 80% or 32,000,000 of the outstanding Units (the “Minimum Condition”). If the Minimum Condition is not satisfied at the Expiration Date then the Offeror will not accept for payment or pay for Units pursuant to the Offer. According to the Offer, the Offeror reserves the right to waive or reduce the Minimum Condition and to elect to purchase, pursuant to the Offer, fewer than the minimum number of Units, subject to applicable notification requirements under applicable law.

 

Item 8.

Additional Information.

Forward-Looking Statements. Certain information included in or incorporated by reference into this Schedule 14D-9 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 the Offeror and 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 the Offeror’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

 

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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. Factors which could cause such forward looking statements not to be correct include, among others, the cautionary statements set forth in the Trust’s Annual Report on Form 10-K and Quarterly Reports on Form 10-Q filed with the Securities and Exchange Commission, including but not limited to, the volatility of oil and gas prices, future production costs, future oil and gas production quantities, operating hazards and environmental conditions.

 

Item 9.

Exhibits.

99.1(a)(1)    Hugoton Royalty Trust Press Release dated April 3, 2020.

99.1(a)(2)    Hugoton Royalty Trust Press Release dated April 14, 2020.

99.1(e)(1)    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)

99.1(e)(2)    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)

99.1(e)(3)    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)

99.1(e)(4)    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)

99.1(e)(5)     The Trust’s 2019 Annual Report on Form 10-K filed with the Securities and Exchange Commission on March  30, 2020, is incorporated herein by reference.

(P)    Paper exhibits.

 

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SIGNATURE

After due inquiry and to the best of my knowledge and belief, I certify that the information set forth in this statement is true, complete and correct.

 

				HUGOTON ROYALTY TRUST
				By: SIMMONS BANK, TRUSTEE
Date: April 14, 2020				By:		/s/ NANCY WILLIS
						Nancy Willis
						Vice President

 

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