Hugoton Royalty Trust
2013
Annual Report and Form 10-K
Glossary of Terms
Bbl
Bcf
Mcf
MMBtu
Net Proceeds
Net Profits Income
Net Profits Interest
Barrel (of oil)
Billion cubic feet (of natural gas)
Thousand cubic feet (of natural gas)
One million British Thermal Units, a common energy measurement
Gross proceeds received by XTO Energy from sale of production from the underlying properties,
less applicable costs, as defined in the net profits interest conveyances.
Net proceeds multiplied by the net profits percentage of 80%, which is paid to the
trust by XTO Energy. “Net profits income” is referred to as “royalty income” for
tax reporting purposes.
An interest in an oil and gas property measured by net profits from the sale of
production, rather than a specific portion of production. The following defined net
profits interests were conveyed to the trust from the underlying properties:
80% net profits interests – interests that entitle the trust to receive 80% of the net
proceeds from the underlying properties.
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.
Units of Beneficial Interest
The units of beneficial interest in the trust began trading on the New York Stock Exchange on April 9, 1999 under the
symbol“HGT.” The following are the high and low unit sales prices and total cash distributions per unit paid by the
trust during each quarter of 2013 and 2012:
2013
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2012
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Sales Price
High
$ 9.97
Low
$ 7.30
9.98
9.45
8.16
$19.21
14.62
7.90
8.56
8.12
7.43
6.98
$13.82
6.42
5.71
6.21
Distributions
per Unit
$0.195453
0.230142
0.251364
0.185723
$0.862682
$0.245636
0.164046
0.053733
0.118408
$0.581823
At December 31, 2013, there were 40,000,000 units outstanding and approximately 761 unitholders of record.
The Trust
Hugoton Royalty Trust was created on
December 1, 1998 when XTO Energy
Inc. conveyed 80% net profits interests in
certain predominantly gas-producing properties located in
Kansas, Oklahoma and Wyoming to the trust. The net profits
interests are the only assets of the trust, other than cash held
for trust expenses and for distribution to unitholders.
Summary
The trust was created to collect and
distribute to unitholders monthly net
profits income related to the 80% net profits
interests. Such net profits income is calculated as 80% of
the net proceeds received from certain working interests
in predominantly gas-producing properties in Kansas,
Oklahoma and Wyoming. Net proceeds from properties in
each state are calculated by deducting production expense,
development costs and overhead from revenues. If monthly
costs exceed revenues from the underlying properties in
any state, such excess costs must be recovered, with accrued
interest, from future net proceeds of that state and cannot
reduce net profits income from another state. Excess costs
generally can occur during periods of higher development
activity and/or lower gas prices.
Costs exceeded revenues on properties underlying the
Wyoming net profits interests in July 2012, on properties
underlying the Kansas net profits interests in September
Selected Financial Data
Net profits income received by the trust on the last
business day of each month is calculated and paid by XTO
Energy based on net proceeds received from the underlying
properties in the prior month. Distributions, as calculated
by the trustee, are paid to month-end unitholders of record
within ten business days.
2012 and on properties underlying the Oklahoma net
profits interests in September 2012. The excess costs claimed
underlying the Kansas and Oklahoma net profits interests are
the subject of pending arbitration described more fully under
“Item 3 – Legal Proceedings” of the accompanying Form
10-K. For further information on excess costs, see “Trustee’s
Discussion and Analysis of Financial Condition and Results of
Operations” under Item 7 of the accompanying Form 10-K.
Cost Depletion is generally available to unitholders as
a deduction from royalty income. Available depletion is
dependent upon the unitholder’s cost of units, purchase date
and prior allowable depletion. It may be more beneficial for
unitholders to deduct percentage depletion. Please see the
2013 tax booklet for specific instructions. Unitholders should
consult their tax advisors for further information.
2013
Years Ended December 31,
Net Profits Income ............................. $ 37,333,595
Distributable Income ......................... 34,507,280
0.862682
Distributable Income per Unit ..........
Distributions per Unit ........................
0.862682
Total Assets at Year End ..................... $ 102,501,095
2012
$ 25,132,038
23,272,920
0.581823
0.581823
$112,956,689
2011
$ 56,565,368
55,764,960
1.394124
1.394124
$ 118,965,716
2010
$ 62,883,206
62,028,000
1.550700
1.550700
$ 129,222,886
2009
$ 30,180,880
29,306,240
0.732656
0.732656
$ 144,162,380
To Unitholders:
We are pleased to present the
2013 Annual Report on
legal proceedings that may affect future trust
distributions. For further information, please see
Form 10-K of the Hugoton Royalty Trust as filed with
“Legal Proceedings” under Item 3 of the accompanying
the Securities and Exchange Commission. This report
Form 10-K.
contains important information about the trust’s net
Natural gas prices averaged $4.03 per Mcf for 2013,
profits interests, including information provided to the
23% higher compared to the 2012 average price of $3.28
trustee by XTO Energy.
per Mcf. The average 2013 oil price was $95.25 per Bbl,
For the year ended December 31, 2013, net profits
4% higher than the 2012 average price of $91.30 per Bbl.
income totaled $37,333,595. After adding interest income
Gas sales volumes from the underlying properties
of $700 and deducting trust administration expense of
for 2013 were 18,712,650 Mcf, or 51,268 Mcf per day,
$2,827,015, distributable income was $34,507,280 or
a decrease of 8% from 55,658 Mcf per day in 2012.
$0.862682 per unit. Net profits income and distributions
Oil sales volumes from the underlying properties were
were 49% and 48%, respectively, higher than 2012
216,634 Bbls, or 594 Bbls per day in 2013, a decrease
amounts primarily because of higher oil and gas prices,
of 5% from 625 Bbls per day in 2012. For further
the portion of the Fankhouser settlement deducted in
information on sales volumes and product prices,
September and October of 2012 and proceeds from the
see “Trustee’s Discussion and Analysis of Financial
property sale in May 2013, partially offset by decreased
Condition and Results of Operations” under Item 7 of
oil and gas production. For further information on the
the accompanying Form 10-K.
Fankhouser settlement, see “Legal Proceedings” under
As of December 31, 2013, proved reserves for the
Item 3 and for more information on the property sale,
underlying properties were estimated by independent
see “Trustee’s Discussion and Analysis of Financial
engineers to be 241.5 Bcf of natural gas and 2.5 million
Condition and Results of Operations” under Item 7 of
Bbls of oil. Natural gas reserves for the underlying
the accompanying Form 10-K.
properties declined 6.7 Bcf and oil reserves for the
The Trust and XTO Energy are parties to several
underlying properties declined approximately 28,000
To Unitholders: Continued
Bbls primarily due to current year
been determined based on a 12-month average gas
production, partially offset by higher
price of $3.92 per Mcf and a 12-month average oil price
prices used to estimate reserves. Based on an allocation
of $94.32 per Bbl, based on the first-day-of-the-month
of these reserves, proved reserves attributable to the net
price for each month in the period, and year end costs.
profits interests were estimated to be 85.5 Bcf of natural
Other guidelines used in estimating proved reserves, as
gas and 1.0 million Bbls of oil. Estimated gas and oil
prescribed by the Financial Accounting Standards Board,
reserves attributable to the net profits interests increased
are described in Note 9 to Financial Statements under
from previously reported reserves at year-end 2012 due to
Item 8, “Financial Statements and Supplementary Data”
positive revisions to reserves related primarily to higher
of the accompanying Form 10-K. The present value of
prices, partially offset by current year production. All
estimated future net cash flows is computed based on
reserve information prepared by independent engineers
SEC guidelines and is not necessarily representative of
has been provided to the trustee by XTO Energy.
the market value of trust units.
Estimated future net cash flows from proved
As disclosed in the tax instructions provided to
reserves of the net profits interests at December 31, 2013
unitholders in February 2014, trust distributions are
were $396 million. Using an annual discount factor
considered portfolio income, rather than passive income.
of 10%, the present value of estimated future net cash
Unitholders should consult their tax advisors for further
flows at December 31, 2013 was $206 million. Proved
information.
reserve estimates and related future net cash flows have
To Unitholders: Continued
On January 9, 2014, Bank of America
2013, included in this annual report. The effective date
gave notice to unitholders that it will be
of Bank of America’s resignation shall be May 30, 2014,
resigning as Trustee subject to the conditions set forth
assuming all of the conditions have been satisfied or
below. Bank of America intends to nominate Southwest
waived as of such date.
Bank, an independent state bank chartered under
the laws of the State of Texas and headquartered in
Fort Worth, Texas, as successor trustee at a meeting
of unitholders of the Trust to be called for the purpose
of approving a successor trustee of the Trust. Bank of
America’s resignation is conditioned on the satisfaction
or waiver by Bank of America of several qualifying
Hugoton Royalty Trust
By: U.S. Trust, Bank of America
Private Wealth Management, Trustee
By: Nancy G. Willis
Vice President
conditions as stated and referenced on Page 1, Part 1,
March 14, 2014
Item 1, second paragraph of the attached Form 10-K for
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
3102,13rebmeceDdedneraeylacsifehtroF
67401-1rebmunelifnoissimmoC
Hugoton Royalty Trust
(Exact name of registrant as specified in the Hugoton Royalty Trust Indenture)
saxeT
(State or other jurisdiction of
incorporation or organization)
5129736-85
(I.R.S. Employer Identification No.)
U.S. Trust, Bank of America
Private Wealth Management
Trustee
P.O. Box 830650
Dallas, Texas 75283-0650
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number including area code:
(877) 228-5083
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
tseretnIlaicifeneBfostinU
Name of each exchange on which registered
egnahcxEkcotSkroYweN
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is awell-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
‘
No Í
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes ‘
No Í
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 Í
No ‘
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was
required to submit and post such files).
Yes ‘
No ‘
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
Í
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the
definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):
Large accelerated filer ‘
Accelerated filer Í
Non-accelerated filer ‘
(Do not check if asmaller reporting company)
Smaller reporting company ‘
Indicate by check mark whether the registrant is ashell company (as defined in Exchange Act Rule 12b-2).
Yes
‘
No Í
The aggregate market value of the units of beneficial interest of the trust, based on the closing price on the New York Stock Exchange as of June 28, 2013 (the last
business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $345 million.
At February 14, 2014, there were 40,000,000 units of beneficial interest of the trust outstanding.
Listed below is the only document parts of which are incorporated herein by reference and the parts of this report into which the document is incorporated:
None
DOCUMENTS INCORPORATED BY REFERENCE
HUGOTON ROYALTY TRUST
2013 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
Page
Glossary of Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
1
Part I
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Item 1.
Item 1A.
Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Item 2.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Item 3.
Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Item 4.
Part II
Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units . . . . . . . . . . . . . . . . . . ..
Item 5.
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Item 6.
Item 7.
Trustee’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . ..
Item 7A. Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Item 8.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . . . . . ..
Item 9.
Item 9A.
Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Item 11.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters . . . . . . . . . ..
Item 12.
Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . . . . . . . . . . . ..
Item 13.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Principal Accountant Fees and Services
Item 14.
Part III
2
4
8
8
17
20
21
21
22
28
29
43
43
43
44
44
44
44
45
Item 15.
Exhibits and Financial Statement Schedules
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
46
Part IV
i
HUGOTON ROYALTY TRUST
GLOSSARY OF TERMS
The following are definitions of significant terms used in this Annual Report on Form 10-K:
Bbl
Bcf
Mcf
MMBtu
net proceeds
net profits income
net profits interest
Barrel (of oil)
Billion cubic feet (of natural gas)
Thousand cubic feet (of natural gas)
One million British Thermal Units, a common energy measurement
Gross proceeds received by XTO Energy from sale of production from the underlying
properties, less applicable costs, as defined in the net profits interest conveyances.
Net proceeds multiplied by the net profits percentage of 80%, which is paid to the trust by
XTO Energy. “Net profits income” is referred to as “royalty income” for tax reporting
purposes.
An interest in an oil and gas property measured by net profits from the sale of production,
rather than aspecific portion of production. The following defined net profits interests were
conveyed to the trust from the underlying properties:
80% net profits interests — interests that entitle the trust to receive 80% of the net proceeds
from the underlying properties.
underlying properties
XTO Energy’s interest in certain oil and gas properties from which the net profits interests
were conveyed. The underlying properties include working interests in predominantly gas-
producing properties located in Kansas, Oklahoma and Wyoming.
working interest
An operating interest in an oil and gas property that provides the owner a specified share of
production that is subject to all production expense and development costs.
1
Item 1. Business
PART I
Hugoton Royalty Trust is an express trust created under the laws of Texas pursuant to the Hugoton Royalty Trust Indenture
entered into on December 1, 1998 between XTO Energy Inc. (formerly known as Cross Timbers Oil Company), as grantor, and
NationsBank, N.A., as trustee. Bank of America, N.A., successor to NationsBank, N.A., is now the trustee of the trust. In 2007 the
Bank of America private wealth management group officially became known as “U.S. Trust, Bank of America Private Wealth
Management.” The legal entity that serves as the trustee of the trust did not change, and references in this Form 10-K to U.S. Trust,
Bank of America Private Wealth Management shall describe the legal entity Bank of America, N.A. The principal office of the trust is
located at 901 Main Street, Dallas, Texas 75202 (telephone number 877-228-5083).
On January 9, 2014, U.S. Trust, Bank of America Private Wealth Management gave notice to unitholders that it will be resigning
as trustee subject to the conditions set forth below. Bank of America, N.A. intends to nominate Southwest Bank, an independent state
bank chartered under the laws of the State of Texas and headquartered in Fort Worth, Texas (“Southwest Bank”), as successor
trustee at a meeting of unitholders of the trust to be called for the purpose of approving a successor trustee of the Trust. U.S. Trust,
Bank of America Private Wealth Management’s resignation is conditioned on the satisfaction or waiver by U.S. Trust, Bank of
America Private Wealth Management of each of the following: (i) the appointment of Southwest Bank as trustee of Sabine Royalty
Trust (another royalty trust for which U.S. Trust, Bank of America Private Wealth Management currently serves as trustee); (ii) the
appointment of Southwest Bank or another successor trustee as trustee of the trust and five other royalty trusts for which U.S. Trust,
Bank of America Private Wealth Management currently serves as trustee and as agent under a disbursing arrangement for which it
currently serves as agent; (iii) the accuracy of certain representations and warranties and performance of certain agreements made
by Southwest Bank in an agreement between U.S. Trust, Bank of America Private Wealth Management and Southwest Bank; and
(iv) no governmental injunction, order or other action that would prohibit Southwest Bank’s appointment, U.S. Trust, Bank of
America Private Wealth Management’s resignation or the other actions described above. The effective date of U.S. Trust, Bank of
America Private Wealth Management’s resignation shall be May 30, 2014, assuming all of the conditions described above have been
satisfied or waived as of such date.
The trust’s internet web site is www.hugotontrust.com. We make available free of charge, through our web site, our Annual
Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or
furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. These reports are accessible through our
internet web site as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and
Exchange Commission.
Effective December 1, 1998, XTO Energy conveyed to the trust 80% net profits interests in certain predominantly natural gas
producing working interest properties in Kansas, Oklahoma and Wyoming under three separate conveyances. In exchange for these
net profits interest conveyances to the trust, 40 million units of beneficial interest were issued to XTO Energy. In April and May 1999,
XTO Energy sold a total of 17 million units in the trust’s initial public offering. In 1999 and 2000, XTO Energy also sold 1.3 million
trust units to certain of its officers. The trust did not receive the proceeds from these sales of trust units. Units are listed and traded
on the New York Stock Exchange under the symbol “HGT.” In May 2006, XTO Energy distributed all of its remaining 21.7 million
trust units as a dividend to its common stockholders. XTO Energy currently is not a unitholder of the trust.
On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.
The net profits interests entitle the trust to receive 80% of the net proceeds from the sale of oil and gas from the underlying
properties. Each month XTO Energy determines the amount of cash received from the sale of production and deducts property and
production taxes, production expense, development costs and overhead.
Net proceeds payable to the trust depend upon production quantities, sales prices of oil and gas and costs to develop and
produce oil and gas in the prior month. If monthly costs exceed revenues for any of the three conveyances (one for each of the
states of Kansas, Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds of
that conveyance and cannot reduce net proceeds from other conveyances.
2
Costs exceeded revenues on properties underlying the Wyoming net profits interests in July 2012, on properties underlying the
Kansas net profits interests in September 2012 and on properties underlying the Oklahoma net profits interests in September 2012.
The excess costs claimed underlying the Kansas and Oklahoma net profits interests in September 2012 are the subject of pending
arbitration described more fully under “Item 3 — Legal Proceedings.” For further information on excess costs, see Trustee’s
Discussion and Analysis of Financial Condition and Results of Operations, under Item 7.
The trust is not liable for any production costs or liabilities attributable to the underlying properties. If at any time the trust
receives net profits income in excess of the amount due, the trust is not obligated to return such overpayment, but net profits
income payable to the trust for the next month will be reduced by the overpayment, plus interest at the prime rate.
As a working interest owner, XTO Energy can generally decline participation in any operation and allow consenting parties to
conduct such operations, as provided under the operating agreements. XTO Energy also can assign, sell, or otherwise transfer its
interest in the underlying properties, subject to the net profits interests, or can abandon an underlying property if it is incapable of
producing in paying quantities, as determined by XTO Energy.
To the extent allowed, XTO Energy is responsible for marketing its production from the underlying properties under existing
sales contracts, or new arrangements on the best terms reasonably obtainable in the circumstances. See “Pricing and Sales
Information” under Item 2, Properties.
Net profits income received by the trust on or before the last business day of the month is related to net proceeds received by
XTO Energy in the preceding month, and is generally attributable to oil and gas production two months prior. The amount to be
distributed to unitholders each month by the trustee is determined by:
Adding —
(1) net profits income received,
(2) interest income and any other cash receipts and
(3) cash available as a result of reduction of cash reserves, then
Subtracting —
(1) liabilities paid and
(2) the reduction in cash available related to establishment of or increase in any cash reserve.
The monthly distribution amount is distributed to unitholders of record within ten business days after the monthly record date.
The monthly record date is generally the last business day of the month. The trustee calculates the monthly distribution amount and
announces the distribution per unit at least ten days prior to the monthly record date.
The trustee may establish cash reserves for contingencies. Cash held for such reserves, as well as for pending payment of the
monthly distribution amount, may be invested in federal obligations or certificates of deposit of major banks.
The trustee’s function is to collect the net profits income from the net profits interests, to pay all trust expenses, and pay the
monthly distribution amount to unitholders. The trustee’s powers are specified by the terms of the trust indenture. The trust cannot
engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments.
The trust has no employees since all administrative functions are performed by the trustee.
Approximately 76% of the net profits income received by the trust during 2013, as well as 79% of the estimated proved
reserves of the net profits interests at December 31, 2013 (based on estimated future net cash flows using 12-month average oil and
gas prices, based on the first-day-of-the-month price for each month in the period), is attributable to natural gas. There has
historically been a greater demand for gas during the winter months than the rest of the year. Otherwise, trust income generally is
not subject to seasonal factors, nor dependent upon patents, licenses, franchises or concessions. The trust conducts no research
activities.
The oil and gas industry is highly competitive in all its phases. Operators of the properties in which the trust holds interests
encounter competition from other oil and gas companies and from individual producers and operators. Oil and natural gas are
commodities, for which market prices are determined by external supply and demand factors.
3
Item 1A. Risk Factors
The following factors could cause actual results to differ materially from those contained in forward-looking statements made
in this report and presented elsewhere by the trustee from time to time. Such factors may have a material adverse effect upon the
trust’s financial condition, distributable income and changes in trust corpus.
The following discussion of risk factors should be read in conjunction with the financial statements and related notes included
under Item 8, Financial Statements and Supplementary Data. Because of these and other factors, past financial performance should
not be considered an indication of future performance.
The market price for the trust units may not reflect the value of the net profits interests held by the trust.
The public trading price for the trust units tends to be tied to the recent and expected levels of cash distributions on the trust
units. The amounts available for distribution by the trust vary in response to numerous factors outside the control of the trust or XTO
Energy, including prevailing prices for oil and natural gas produced from the underlying properties. The market price of the trust
units is not necessarily indicative of the value that the trust would realize if the net profits interests were sold to a third party buyer.
In addition, such market price is not necessarily reflective of the fact that, since the assets of the trust are depleting assets, a portion
of each cash distribution paid on the trust units should be considered by investors as a return of capital, with the remainder being
considered as a return on investment. There is no guarantee that distributions made to a unitholder over the life of these depleting
assets will equal or exceed the purchase price paid by the unitholder.
Oil and natural gas prices fluctuate due to a number of uncontrollable factors, and any decline will
adversely affect the net proceeds payable to the trust and trust distributions.
The trust’s monthly cash distributions are highly dependent upon the prices realized from the sale of natural gas and, to a
lesser extent, oil. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that
are beyond the control of the trust and XTO Energy. Factors that contribute to price fluctuations include instability in oil-producing
regions, worldwide economic conditions, weather conditions, the supply and price of domestic and foreign oil, natural gas and
natural gas liquids, consumer demand, the price and availability of alternative fuels, the proximity to, and capacity of, transportation
facilities and the effect of worldwide energy conservation measures. Moreover, government regulations, such as regulation of natural
gas transportation and price controls, can affect product prices in the long term. Lower oil and natural gas prices may reduce the
amount of oil and natural gas that is economic to produce and will reduce net profits available to the trust. The volatility of energy
prices reduces the predictability of future cash distributions to trust unitholders.
Higher production expense and/or development costs, without concurrent increases in revenue, will directly
decrease the net proceeds payable to the trust. Certain claimed production expenses by XTO Energy may
reduce or eliminate distributions to unitholders for extended periods of time.
Production expense and development costs are deducted in the calculation of the trust’s share of net proceeds. Accordingly,
higher or lower production expense and development costs, without concurrent changes in revenue, will directly decrease or
increase the amount received by the trust. If development costs and production expense for underlying properties in a particular
state exceed the production proceeds from the properties (as was the case with respect to the properties underlying the Wyoming
net profits interests in July 2012, the Kansas net profits interests in September 2012 and the Oklahoma net profits interests in
September 2012), the trust will not receive net proceeds for those properties until future proceeds from production in that state
exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient
additional revenue to repay the costs. The excess costs claimed by XTO Energy in September 2012 underlying the Kansas and
Oklahoma net profits interests relate to settlement payments made by XTO Energy in the Fankhouser v. XTO Energy, Inc. case.
Although the issue of whether XTO Energy may deduct all or a portion of the settlement payments from trust proceeds is the subject
of a pending arbitration, if XTO Energy is ultimately successful in such arbitration, the deduction of the settlement payments would
cause costs to exceed revenues for approximately 12 months on properties underlying the Oklahoma net profits interests and by
approximately 5 years on properties underlying the Kansas net profits interests; however, changes in oil or natural gas prices or
expenses could cause the time period to increase or decrease correspondingly. See “Item 3 — Legal Proceedings” for additional
information.
4
Proved reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material
inaccuracies in reserve estimates or underlying assumptions could cause the quantities and net present value
of the reserves to be overstated.
Estimating proved oil and gas reserves is inherently uncertain. Petroleum engineers consider many factors and make
assumptions in estimating reserves and future net cash flows. Those factors and assumptions include historical production from the
area compared with production rates from similar producing areas, the effects of governmental regulation, assumptions about
future commodity prices, production expense and development costs, taxes and capital expenditures, the availability of enhanced
recovery techniques and relationships with landowners, working interest partners, pipeline companies and others. Lower oil and
gas prices generally cause lower estimates of proved reserves. Ultimately, actual production, revenues and expenditures for the
underlying properties will vary from estimates and those variances could be material. Because the trust owns net profits interests, it
does not own aspecific percentage of the oil and gas reserves. Estimated proved reserves for the net profits interests are based on
estimates of reserves for the underlying properties and an allocation method that considers estimated future net proceeds and oil
and gas prices. Because trust reserve quantities are determined using an allocation formula, increases or decreases in oil and gas
prices can significantly affect estimated reserves of the net profits interests.
Operational risks and hazards associated with the development of the underlying properties may decrease
trust distributions.
There are operational risks and hazards associated with the production and transportation of oil and natural gas, including
without limitation natural disasters, blowouts, explosions, fires, leakage of oil or natural gas, releases of other hazardous materials,
mechanical failures, cratering, and pollution. Any of these or similar occurrences could result in the interruption or cessation of
operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the
environment or natural resources, or cleanup obligations. The operation of oil and gas properties is also subject to various laws and
regulations. Non-compliance with such laws and regulations could subject the operator to additional costs, sanctions or liabilities.
The uninsured costs resulting from any of the above or similar occurrences could be deducted as a production expense or
development cost in calculating the net proceeds payable to the trust, and would therefore reduce trust distributions by the amount
of such uninsured costs.
Cash held by the trustee is not fully insured by the Federal Deposit Insurance Corporation, and future royalty
income may be subject to risks relating to the creditworthiness of third parties.
Currently, cash held by the trustee as a reserve for liabilities and for the payment of expenses and distributions to unitholders
is invested in Bank of America, N.A. certificates of deposit which are backed by the good faith and credit of Bank of America, N.A.,
but are only insured by the Federal Deposit Insurance Corporation up to $250,000. Each unitholder should independently assess
the creditworthiness of Bank of America, N.A. For more information about the credit rating of Bank of America, N.A., please refer to
its periodic filings with the SEC. The trust does not lend money and has limited ability to borrow money, which the trustee believes
limits the trust’s risk from the currently tight credit markets. The trust’s future royalty income, however, may be subject to risks
relating to the creditworthiness of the operators of the underlying properties and other purchasers of crude oil and natural gas
produced from the underlying properties, as well as risks associated with fluctuations in the price of crude oil and natural gas.
Information contained in Bank of America N.A.’s periodic filings with the SEC is not incorporated by reference into this Annual
Report on Form 10-K and should not be considered part of this report or any other filing that the trust makes with the SEC.
Trust unitholders and the trustee have no influence over the operations on, or future development of, the
underlying properties.
Neither the trustee nor the trust unitholders can influence or control the operation or future development of the underlying
properties. The failure of an operator to conduct its operations or discharge its obligations in a proper manner could have an
adverse effect on the net proceeds payable to the trust. Although XTO Energy and other operators of the underlying properties must
adhere to the standard of a prudent operator, they are under no obligation to continue operating the properties. Neither the trustee
nor trust unitholders have the right to replace an operator.
5
The assets of the trust represent interests in depleting assets and, if XTO Energy or any other operators
developing the underlying properties do not perform additional successful development projects, the assets
may deplete faster than expected. Eventually, the assets of the trust will cease to produce in commercial
quantities and the trust will cease to receive proceeds from such assets.
The net proceeds payable to the trust are derived from the sale of hydrocarbons from depleting assets. The reduction in proved
reserve quantities is a common measure of the depletion. Future maintenance and development projects on the underlying properties
will affect the quantity of proved reserves and can offset the reduction in proved reserves. The timing and size of these projects will
depend on the market prices of oil and natural gas. If the operator(s) of the properties do not implement additional maintenance and
development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the
trust. Because the net proceeds payable to the trust are derived from the sale of hydrocarbons from depleting assets, the portion of
distributions to unitholders attributable to depletion may be considered ar eturn on capital as opposed to ar eturn on investment.
Distributions that are ar eturn of capital will ultimately diminish the depletion tax benefits available to the unitholders, which could
reduce the market value of the units over time. Eventually, the properties underlying the trust’s net profits interest will cease to produce
in commercial quantities and the trust will, therefore, cease to receive any net proceeds therefrom.
Terrorism and continued geopolitical hostilities could adversely affect trust distributions or the market price
of the trust units.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in
response, cause instability in the global financial and energy markets. Terrorism and other geopolitical hostilities could adversely
affect trust distributions or the market price of the trust units in unpredictable ways, including through the disruption of fuel
supplies and markets, increased volatility in oil and natural gas prices, or the possibility that the infrastructure on which the
operators of the underlying properties rely could be a direct target or an indirect casualty of an act of terror.
XTO Energy may transfer its interest in the underlying properties without the consent of the trust or the trust
unitholders.
XTO Energy may at any time transfer all or part of its interest in the underlying properties to another party. Neither the trust nor the
trust unitholders are entitled to vote on any transfer of the properties underlying the trust’s net profits interests, and the trust will not receive
any proceeds of any such transfer. Following any transfer, the transferred property will continue to be subject to the net profits interests of
the trust, but the calculation, reporting and remitting of net proceeds to the trust will be the responsibility of the transferee.
XTO Energy or any other operator of any underlying property may abandon the property, thereby terminating
the related net profits interest payable to the trust.
XTO Energy or any other operator of the underlying properties, or any transferee thereof, may abandon any well or property
without the consent of the trust or the trust unitholders if they reasonably believe that the well or property can no longer produce in
commercially economic quantities. This could result in the termination of the net profits interest relating to the abandoned well or
property.
The net profits interests can be sold and the trust would be terminated.
The trust may sell the net profits interests if the holders of 80% or more of the outstanding trust units approve the sale or vote
to terminate the trust. The trust will terminate if it fails to generate gross proceeds from the underlying properties of at least
$1,000,000 per year over any consecutive two-year period. Sale of all of the net profits interests will terminate the trust. The net
proceeds of any sale must be for cash with the proceeds promptly distributed to the trust unitholders.
Trust unitholders have limited voting rights and have limited ability to enforce the trust’s rights against XTO
Energy or any other operator of the underlying properties.
The voting rights of a trust unitholder are more limited than those of stockholders of most public corporations. For example,
there is no requirement for annual meetings of trust unitholders or for an annual or other periodic re-election of the trustee.
Additionally, trust unitholders have no voting rights in XTO Energy or Exxon Mobil Corporation.
6
The trust indenture and related trust law permit the trustee and the trust to sue XTO Energy or any other operator of the
underlying properties to compel them to fulfill the terms of the conveyance of the net profits interests. If the trustee does not take
appropriate action to enforce provisions of the conveyance, the recourse of the trust unitholders would likely be limited to bringing
a lawsuit against the trustee to compel the trustee to take specified actions. Trust unitholders probably would not be able to sue XTO
Energy or any other operator of the underlying properties.
Financial information of the trust is not prepared in accordance with U.S. GAAP.
The financial statements of the trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of
accounting other than U.S. generally accepted accounting principles, or U.S. GAAP. Although this basis of accounting is permitted for
royalty trusts by the Securities and Exchange Commission, the financial statements of the trust differ from U.S. GAAP financial
statements because net profits income is not accrued in the month of production, expenses are not recognized when incurred and
cash reserves may be established for certain contingencies that would not be recorded in U.S. GAAP financial statements.
The limited liability of trust unitholders is uncertain.
The trust unitholders are not protected from the liabilities of the trust to the same extent that a shareholder would be
protected from a corporation’s liabilities. The structure of the trust does not include the interposition of a limited liability entity such
as a corporation or limited partnership which would provide further limited liability protection to trust unitholders. While the
trustee is liable for any excess liabilities incurred if the trustee fails to ensure that such liabilities are to be satisfied only out of trust
assets, under the laws of Texas, which are unsettled on this point, a unitholder may be jointly and severally liable for any liability of
the trust if the satisfaction of such liability was not contractually limited to the assets of the trust and the assets of the trust and the
trustee are not adequate to satisfy such liability. As a result, trust unitholders may be exposed to personal liability. The trust,
however, is not liable for production costs or other liabilities of the underlying properties.
Drilling oil and natural gas wells is a high-risk activity and subjects the trust to a variety of factors that it
cannot control.
Drilling oil and natural gas wells involves numerous risks, including the risk that commercially productive oil and natural gas
reservoirs are not encountered. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may
cause drilling activities to be unsuccessful. In addition, there is often uncertainty as to the future cost or timing of drilling, completing and
operating wells. Further, development activities may be curtailed, delayed or canceled as a result of a variety of factors, including:
• unexpected drilling conditions;
• title problems;
• restricted access to land for drilling or laying pipeline;
• pressure or irregularities in formations;
• equipment failures or accidents;
• adverse weather conditions; and
• costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment.
While these risks do not expose the trust to liabilities of the drilling contractor or operator of the well, they can reduce net
proceeds payable to the trust and trust distributions by decreasing oil and gas revenues or increasing production expense or
development costs from the underlying properties. Furthermore, these risks may cause the costs of development activities on the
underlying properties to exceed the revenues therefrom, thereby reducing net proceeds payable to the trust and trust distributions.
The underlying properties are subject to complex federal, state and local laws and regulations that could
adversely affect net proceeds payable to the trust and trust distributions.
Extensive federal, state and local regulation of the oil and natural gas industry significantly affects operations on the underlying
properties. In particular, oil and natural gas development and production are subject to stringent environmental regulations. These
regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and natural gas wells
and other related facilities, which costs could reduce net proceeds payable to the trust and trust distributions. These regulations may
become more demanding in the future.
7
Item 1B. Unresolved Staff Comments
As of December 31, 2013, the trust did not have any unresolved Securities and Exchange Commission staff comments.
Item 2. Properties
The net profits interests are the principal asset of the trust. The trustee cannot acquire any other assets, with the exception of
certain short-term investments as specified under Item 1, Business. The trustee may sell or otherwise dispose of all or any part of
the net profits interests if approved by a vote of holders of 80% or more of the outstanding trust units, or upon termination of the
trust. Otherwise, the trust is required to sell up to 1% of the value of the net profits interests in any calendar year, pursuant to notice
from XTO Energy of its desire to sell the related underlying properties. Any sale must be for cash with 80% of the proceeds
distributed to the unitholders on the next declared distribution. All the underlying properties are currently owned by XTO Energy.
XTO Energy may sell all or any portion of the underlying properties at any time, subject to and burdened by the net profits interests.
The underlying properties are predominantly gas-producing properties with established production histories in the Hugoton
area of Oklahoma and Kansas, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. The average reserve-to-
production index for the underlying properties as of December 31, 2013 is approximately 13 years. This index is calculated using
total proved reserves and estimated 2014 production for the underlying properties. The projected 2014 production is from proved
developed producing reserves as of December 31, 2013. Based on estimated future net cash flows at 12-month average oil and gas
prices, based on the first-day-of-the-month price for each month in the period, the proved reserves of the underlying properties are
approximately 80% natural gas and 20% oil. XTO Energy operates approximately 95% of the underlying properties.
Because the underlying properties are working interests, production expense, development costs and overhead are deducted
in calculating net profits income. As a result, net profits income is affected by the level of maintenance and development activity on
the underlying properties. See Trustee’s Discussion and Analysis of Financial Condition and Results of Operations, under Item 7.
Total 2013 development costs deducted for the underlying properties were $6.5 million, an increase of 8% from the prior year. XTO
Energy has informed the trustee that total 2014 budgeted development costs for the underlying properties are between $6 million
and $7 million.
Significant Properties
Hugoton Area
Natural gas was discovered in the Hugoton area in 1922. With an estimated five million productive acres covering parts of
Texas, Oklahoma and Kansas, the Hugoton area is one of the largest domestic natural gas producing areas. During 2013, daily sales
volumes from the underlying properties in the Hugoton area averaged approximately 15,100 Mcf of gas and 44 Bbls of oil.
Most of the production from the underlying properties in the Hugoton area is from the Chase formation. XTO Energy has
informed the trustee that it has begun to develop other formations that underlie the 79,500 net acres held by production by the
Chase formation wells, which include the Council Grove, Morrow, Chester and St. Louis formations. These formations are
characterized by both oil and gas production from a variety of structural and stratigraphic traps. Since 2003, XTO Energy has drilled
wells to these formations and plans to continue this development program in 2014.
Within this area, XTO Energy did not drill any wells but did perform 7 workovers in 2013. XTO Energy has informed the
trustee that it does not plan to drill any new wells but may perform up to 9 workovers during 2014.
XTO Energy’s future development plans for the underlying properties in the Hugoton area include:
• additional compression to lower line pressures,
• installing artificial lift,
• opening new producing zones in existing wells,
• restimulating producing intervals in existing wells utilizing new technology,
• deepening existing wells to new producing zones, and
• drilling additional wells.
8
XTO Energy delivers most of its Hugoton gas production to a gathering and processing system owned by a subsidiary. Most of
the gas is sold under the terms of a contract that was entered into in March 1996, predating the existence of the trust. This system
collects the majority of its throughput from underlying properties, which, in recent months, has been approximately 11,000 Mcf per
day. The gathering subsidiary purchases the gas from XTO Energy at the wellhead, gathers and transports the gas to its plant, and
treats and processes the gas at the plant. The gathering subsidiary has agreed to use its best efforts to purchase all gas produced by
XTO Energy from the wells that are subject to the contract, but the gathering subsidiary is not obligated to purchase gas in excess of
its market requirements. The gathering subsidiary has been taking all of the gas produced for over ten years. The gathering
subsidiary pays XTO Energy for wellhead volumes at a price of 80% to 85% of the net residue price received by XTO Energy’s
marketing affiliate, which amount is adjusted for the BTU content of the gas. This affiliate currently sells the residue to a pipeline at a
price based on a monthly pipeline index less actual third party fees. The term of these contracts can vary by contract, but in general
the contracts, after an initial stated period, renew on a monthly basis unless either party gives notice of termination. If either party to
the contracts fails to perform under the contract, the contract may be terminated if written notice is given of the breach and the
breaching party fails to cure the breach within a specified period. The March 1996 contract has an annual price renegotiation term
under which either party can request that the price provided under the contract be renegotiated. Neither party has requested that the
price be renegotiated. XTO Energy does not anticipate that the terms of the contracts will be renegotiated.
Other Hugoton gas production is sold under a third party contract that remains in effect for the life of the lease. Under the
contract, XTO Energy receives 74.5% of the net proceeds received by the buyer from the sale of the residue gas and liquids
produced from certain underlying properties. The residue gas net proceeds are based upon the weighted average price of the gas
sold by the buyer at its facilities, and the liquids net proceeds are based upon an average daily index sales price, less transportation,
processing and storage fees incurred by the buyer. The buyer agrees to use its best efforts to take all of the gas produced, subject to
its market requirements. The buyer has been taking all of the gas produced for over ten years.
Anadarko Basin
Oil and gas accumulations were discovered in the Anadarko Basin of western Oklahoma in 1945. XTO Energy is one of the
largest producers in the Ringwood, Northwest Okeene and Cheyenne Valley fields of Major County, the Northeast Cedardale field of
Woodward County and the Elk City field of Beckham County, the principal producing regions of the underlying properties in the
Anadarko Basin. Daily sales volumes from the underlying properties in the Anadarko Basin averaged 22,300 Mcf of gas and
520 Bbls of oil in 2013.
The fields in the Major County area are characterized by oil and gas production from a variety of structural and stratigraphic
traps. Productive zones include the Oswego, Red Fork, Inola, Chester, Manning, Mississippian, Hunton and Arbuckle formations.
Within this area, XTO Energy did not drill any wells but did perform 29 workovers in 2013. XTO Energy has informed the trustee that
does not plan to drill any new wells but may perform up to 27 workovers in Major County during 2014.
The fields within Woodward County are characterized primarily by gas production from a variety of structural and stratigraphic
traps. Productive zones include the Cottage Grove, Oswego, Chester and Mississippian formations. Within this area, XTO Energy did
not drill any wells but did perform 2 workovers in 2013. XTO Energy has informed the trustee that it does not plan to drill any new
wells but may perform up to 3 workovers in Woodward County during 2014.
The Elk City field on the eastern edge of Beckham County produces oil and gas from a structural anticline with stratigraphic
trapping features. Production zones include the Hoxbar, Atoka and Morrow formations. Within this area, XTO Energy did not drill
any wells but did perform 8 workovers in 2013. XTO Energy has informed the trustee that it does not plan to drill any new wells but
may perform up to 8 workovers within the Elk City field during 2014.
XTO Energy plans to further develop the underlying properties in the Anadarko Basin primarily through:
• mechanical stimulation of existing wells,
• installing artificial lift,
• opening new producing zones in existing wells,
• deepening existing wells to new producing zones, and
• drilling additional wells.
9
A gathering subsidiary of XTO Energy operates a 300-mile gathering system and pipeline in the Major County area. The
gathering subsidiary and a third-party processor purchase natural gas produced at the wellhead from XTO Energy and other
producers in the area under various agreements, most of which were entered into in the 1960’s and 1970’s, and which include life-
of-production terms such that the contracts will continue until there is no further production from the underlying properties, unless
the production declines so that it is no longer economical to take the gas. The gathering subsidiary and the third-party processor are
required to take certain minimum volumes of the gas produced but have been taking all of the volumes produced for over ten years.
The gathering subsidiary gathers and transports the gas to a third-party processor, which processes the gas and pays XTO Energy
and other producers for at least 50% of the liquids processed based upon a weighted average sales price less transportation
charges, which price may vary in the event of inadequate markets. After the gas is processed, the gathering subsidiary transports the
gas via aresidue pipeline to a connection with an interstate pipeline. The gathering subsidiary sells the residue gas to the marketing
subsidiary of XTO Energy based upon a weighted average price, which price will vary monthly based upon market conditions. The
gathering subsidiary pays this price to XTO Energy less a compression and gathering fee of approximately $0.31 per Mcf of residue
gas. This gathering fee was previously approved by the Federal Energy Regulatory Commission when the gathering subsidiary was
regulated and is unlikely to change. During 2013, the gathering system collected approximately 10,000 Mcf per day, approximately
50% of which XTO Energy operates. Estimated capacity of the gathering system is 24,000 Mcf per day. The gathering subsidiary also
provides contract operating services to properties in Woodward County, collecting approximately 5,000 Mcf per day, for an average
fee of approximately $0.05 per Mcf. The fee is subject to an annual price renegotiation under which either party can request that the
price provided under the contract be renegotiated. The contract continues on a yearly basis, and it is subject to termination upon
written notice prior to its annual renewal or in the event the parties fail to agree upon a pricing renegotiation. XTO Energy also sells
gas directly to its marketing subsidiary under a month-to-month contract, which then sells the gas to third parties. The price paid to
XTO Energy is based upon the weighted average price of several published indices, which price varies upon market conditions but
any marketing fees. The price paid by the marketing affiliate includes a deduction for any
does not include adeduction for
transportation fees charged by the third party. Neither party has a firm obligation to sell or purchase any specific minimum quantity
of gas.
Green River Basin
The Green River Basin is located in southwestern Wyoming. Natural gas was discovered in the Fontenelle field of the Green
River Basin in the early 1970’s. The producing reservoirs are the Frontier, Baxter and Dakota sandstones.
Daily 2013 sales volumes from the underlying properties in the Fontenelle field averaged 13,900 Mcf of natural gas and
30 Bbls of oil. XTO Energy did not drill any wells or perform any workovers in the Green River Basin in 2013. XTO Energy has
advised the trustee that it does not plan to drill any new wells but may perform up to 4 workovers in the Green River Basin during
2014. XTO Energy has advised the trustee that it is continuing its efforts to reduce pipeline pressure which has shown potential for
increasing production and extending field life in the Fontenelle Field.
Potential development activities for the underlying properties in this area include:
• installing artificial lift,
• restimulating producing intervals utilizing new technology,
• additional compression to lower line pressures, and
• opening new producing zones in existing wells.
XTO Energy markets the gas produced from the Fontenelle field and nearby properties under various marketing arrangements.
Under the agreement covering the majority of the gas sold, XTO Energy compresses the gas on the lease, transports it off the lease
and compresses the gas again prior to entry into the gas plant pipeline. The pipeline transports the gas to the gas plant, where the
gas is processed, then redelivered to XTO Energy. The owner of the gas plant and related pipeline charges XTO Energy for
operational fuel and processing and has agreed to accept certain volumes, which amounts can be adjusted by the owner. The owner
may be able to cease taking volumes if it has valid unaddressed concerns regarding the creditworthiness of XTO Energy. In 2013, the
fuel charge was 2.27% of the volumes produced and the processing fee was approximately $0.11 per MMBtu. These charges are
adjusted annually based upon a published governmental economic index, and the contract renews on a year-to-year basis. XTO
Energy transports and sells this gas directly to the markets based on a spot sales price on a month-to-month term, and the volumes
10
to be sold are generally determined upon a monthly basis. These contracts may be terminated by either party if there are credit
issues with the other party. The gas not sold under the above arrangement may be gathered and sold under a similar arrangement
on a month-to-month term where the fee is approximately $0.18 per MMBtu and is adjusted annually. The amount of gas that the
gatherer is required to gather is limited to certain maximum volumes, and the gatherer may be able to cease taking volumes if it has
valid unaddressed concerns regarding the creditworthiness of XTO Energy. Alternatively, the gas may be sold under a contract where
XTO Energy directly sells the gas to a third party on the lease at an adjusted index price, which price varies upon market conditions.
The contract continues on a month-to-month basis, and the buyer is obligated to make agood faith effort to purchase a minimum
90% of the gas nominated by buyer for purchase. Condensate is sold to an independent third party at market rates on a month-to-
month basis. The purchaser accepts all condensate delivered at the lease, but either party may suspend performance of the contract
if there are credit issues with the other party.
Producing Acreage, Drilling and Well Counts
For the following data, “gross” refers to the total wells or acres on the underlying properties in which XTO Energy owns a
working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by XTO Energy.
Although many of XTO Energy’s wells produce both oil and gas, a well is categorized as an oil well or a gas well based upon the ratio
of oil to natural gas production. Operated wells are managed by XTO Energy, while nonoperated wells are managed by others.
The underlying properties are interests in developed properties located primarily in gas producing regions of Kansas,
Oklahoma and Wyoming. The following is a summary of the approximate producing acreage of the underlying properties at
December 31, 2013. Undeveloped acreage is not significant.
Hugoton Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Anadarko Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Green River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
209,886
164,365
37,712
195,513
132,435
28,426
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
411,963
356,374
Gross
Net
The following is a summary of the producing wells on the underlying properties as of December 31, 2013:
Operated
Wells
Nonoperated
Wells
Total
Gross
Net
Gross
Net
Gross
Net
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Oil
1,215.0
41.0
1,069.8
38.1
276.0
4.0
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
1,256.0
1,107.9
280.0
61.5
0.9
62.4
1,491.0
45.0
1,131.3
39.0
1,536.0
1,170.3
The following is a summary of the number of wells drilled on the underlying properties during the years indicated. During
2013 and 2012 no exploratory wells were drilled on the underlying properties. During 2011, one exploratory dry hole (0.0 net) was
drilled on the underlying properties. All other wells drilled were developmental. There were no wells in process of drilling at
December 31, 2013.
2013
2012
2011
Gross
Net
Gross
Net
Gross
Net
Completed gas wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. — — 1
1.5
Completed oil wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. — — — — — —
Dry wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. — — — — 1 —
0.6
3
Total(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. — — 1
0.6
4
1.5
(a)
Included in totals are zero wells in 2013, zero wells in 2012 and 3 gross (0.5 net) wells in 2011, drilled on nonoperated
interests.
11
Estimated Proved Reserves and Future Net Cash Flows
The following are proved reserves of the underlying properties, as estimated by independent engineers, and proved reserves
and future net cash flows from proved reserves of the net profits interests, based on an allocation of these reserves, at December 31,
2013:
Underlying Properties
Proved Reserves(a)
Oil
Gas
(Bbls)
(Mcf)
Net Profits Interests
Proved Reserves(a)(b)
Gas
(Mcf)
Oil
(Bbls)
Future Net Cash Flows
from Proved Reserves(a)(c)
Discounted
Undiscounted
(in thousands)
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
165,890
57,084
18,499
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
241,473
2,306
71
108
2,485
65,172
13,120
7,182
85,474
910
16
43
969
$326,131
41,077
28,941
$167,973
21,965
16,493
$396,149
$206,431
(a) Based on 12-month average oil price of $94.32 per Bbl and $3.92 per Mcf for gas, based on the first-day-of-the-month price
for each month in the period. Discounted estimated future net cash flows from proved reserves increased 27% from year-end
2012 to 2013, primarily because of a 22% increase in natural gas prices.
Since the trust has defined net profits interests, the trust does not own a specific percentage of the oil and gas reserves.
Because trust reserve quantities are determined using an allocation formula, any fluctuations in actual or assumed prices or
costs will result in revisions to the estimated reserve quantities allocated to the net profits interests.
(b)
(c) Before income taxes since future net cash flows are not subject to taxation at the trust level. Future net cash flows are
discounted at an annual rate of 10%.
Proved reserves consist of the following:
Underlying Properties
Proved Reserves
Oil
Gas
(Bbls)
(Mcf)
Net Profits Interests
Proved Reserves
Oil
(Bbls)
Gas
(Mcf)
(in thousands)
Proved developed reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Proved undeveloped reserves . . . . . . . . . . . . . . . . . . . . . . . . . ..
204,611
36,862
Total proved reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
241,473
2,163
322
2,485
76,239
9,235
85,474
878
91
969
Approximately 85% of the underlying proved reserves are proved developed reserves.
The process of estimating oil and gas reserves is complex and requires significant judgment as discussed in Item 1A, Risk
Factors, and is performed by XTO Energy. As a result, XTO Energy has developed internal policies and controls for estimating and
recording reserves. XTO Energy’s policies regarding booking reserves require proved reserves to be in compliance with the SEC
definitions and guidance. XTO Energy’s policies assign responsibilities for compliance in reserves bookings to its reserve
engineering group and require that reserve estimates be made by qualified reserves estimators, as defined by the Society of
Petroleum Engineers’ standards. All qualified reserves estimators are required to receive education covering the fundamentals of
SEC proved reserves assignments.
The XTO Energy reserve engineering group reviews reserve estimates with our third-party petroleum consultants, Miller and
Lents, Ltd., independent petroleum engineers. Miller and Lents, Ltd. estimated oil and gas reserves attributable to the underlying
properties as of December 31, 2013, 2012, 2011 and 2010. Miller and Lents’ primary technical person responsible for calculating
the trust’s reserves has more than 30 years of experience as a reserve engineer. The estimated reserves for the underlying properties
are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests. Numerous
uncertainties are inherent in estimating reserve volumes and values, and such estimates are subject to change as additional
information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially
different from the original estimates.
12
Reserve quantities and revenues for the net profits interests were estimated from projections of reserves and revenues
attributable to the combined interests of the trust and XTO Energy in the subject properties. Since the trust has defined net profits
interests, the trust does not own aspecific percentage of the oil and gas reserve quantities. Accordingly, reserves allocated to the
trust pertaining to its 80% net profits interests in the properties have effectively been reduced to reflect recovery of the trust’s 80%
portion of applicable production and development costs. Because trust reserve quantities are determined using an allocation
formula, any fluctuations in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to
the net profits interests.
Oil and Natural Gas Production
Trust production is recognized in the period net profits income is received, which is the month following receipt by XTO
Energy, and generally two months after the time of production. Oil and gas production and average sales prices attributable to the
underlying properties and the net profits interests for each of the three years ended December 31 were as follows:
2013
2012
2011
Production
Underlying Properties
Gas – Sales (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . ..
Average per day (Mcf) . . . . . . . . . . . . . . . . . . . ..
Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . ..
Average per day (Bbls) . . . . . . . . . . . . . . . . . . ..
18,712,650
51,268
216,634
594
20,370,975
55,658
228,656
625
Net Profits Interests
Gas – Sales (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . ..
Average per day (Mcf) . . . . . . . . . . . . . . . . . . . ..
Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . ..
Average per day (Bbls) . . . . . . . . . . . . . . . . . . ..
7,770,148
21,288
99,363
272
5,991,964
16,371
76,049
208
21,693,139
59,433
248,739
681
10,661,323
29,209
130,109
356
Average Sales Price
Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$ 4.03
$95.25
$ 3.28
$91.30
$ 4.73
$90.07
Oil and gas production by conveyance attributable to the underlying properties for each of the three years ended December 31
were as follows:
Conveyance
Underlying Gas Production (Mcf)
2012
2013
2011
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
1,606,436
12,041,983
5,064,231
1,805,789
12,992,317
5,572,869
2,007,032
13,858,590
5,827,517
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
18,712,650
20,370,975
21,693,139
Conveyance
Underlying Oil Production (Bbls)
2012
2013
2011
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
9,427
196,345
10,862
216,634
14,090
204,022
10,544
228,656
20,682
216,287
11,770
248,739
Pricing and Sales Information
A subsidiary of XTO Energy purchases most of XTO Energy’s natural gas production based on a weighted average sales price,
then sells the gas to third parties for the best available price. Oil production is generally marketed at the wellhead to third parties at
the best available price. XTO Energy arranges for some of its natural gas to be processed by unaffiliated third parties and markets
the natural gas liquids. Most of the natural gas attributable to the underlying properties is marketed under contracts existing at trust
13
inception. Contracts covering production from the Ringwood area of the Major County area are generally for the life of the lease,
and the contract for the majority of production from the Hugoton area was extended through 2014. If new contracts are entered
with unaffiliated third parties, the proceeds from sales under those new contracts will be included in gross proceeds from the
underlying properties. If new contracts are entered with XTO Energy’s marketing subsidiary, it may charge XTO Energy a fee that
may not exceed 2% of the sales price of the oil and natural gas received from unaffiliated parties. The sales price is net of any
deductions for transportation from the wellhead to the unaffiliated parties and any gravity or quality adjustments. For further
information on these arrangements see Significant Properties above.
Regulation
Natural Gas Regulation
The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation and
storage rates charged, tariffs, and various other matters, by the Federal Energy Regulatory Commission. Federal price controls on
wellhead sales of domestic natural gas terminated on January 1, 1993. While natural gas prices are currently unregulated, Congress
historically has been active in the area of natural gas regulation. On August 8, 2005, Congress enacted the Energy Policy Act of 2005.
The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct
FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to
significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations
or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act, including enforcement rules and new
annual reporting requirements for certain sellers of natural gas. It is impossible to predict whether new legislation to regulate
natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and
what effect, if any, such proposals might have on the operations of the underlying properties.
Federal Regulation of Oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The net price
received from the sale of these products is affected by market transportation costs. Under rules adopted by FERC effective January
1995, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific
circumstances.
On December 19, 2007, the President signed into law the Energy Independence & Security Act of 2007 (PL 110-140). The
EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil,
gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may
prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder. XTO
Energy has advised the trustee that it cannot predict the impact of future government regulation on any crude oil, condensate or
natural gas liquids facilities, sales or transportation transactions.
Environmental Regulation
Companies that are engaged in the oil and gas industry are affected by federal, state and local laws regulating the discharge of
materials into the environment. Those laws may impact operations of the underlying properties. No material expenses have been
incurred on the underlying properties in complying with environmental laws and regulations. XTO Energy does not expect that
future compliance will have a material adverse effect on the trust.
There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and
climate change. Several states have adopted climate change legislation and regulations, and various other regulatory bodies have
announced their intent to regulate GHG emissions or adopt climate change regulations. As these regulations are under development,
XTO Energy is unable to predict the total impact of the potential regulations upon the operators of the underlying properties, and it
is possible that operators of the underlying properties could face increases in operating costs in order to comply with climate
change or GHG emissions legislation, which costs could reduce net proceeds payable to the trust and trust distributions.
State Regulation
The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining
drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas
14
resources. The rates of production may be regulated and the maximum daily production allowables from both oil and gas wells may
be established on a market demand or conservation basis, or both.
Federal Income Taxes
For federal income tax purposes, the trust constitutes afixed investment trust that is taxed as a grantor trust. A grantor trust is
not subject to tax at the trust level. The unitholders are considered to own the trust’s income and principal as though no trust were
in existence. The income of the trust is deemed to have been received or accrued by each unitholder at the time such income is
received or accrued by the trust and not when distributed by the trust.
Because the trust is a grantor trust for federal tax purposes, each unitholder is taxed directly on his proportionate share of
income, deductions and credits of the trust consistent with each such unitholder’s taxable year and method of accounting and
without regard to the taxable year or method of accounting employed by the trust. The income of the trust consists primarily of a
specified share of the net profits from the sale of oil and natural gas produced from the underlying properties. During 2013, the
trust incurred administration expenses and earned interest income on funds held for distribution and for the cash reserve
maintained for the payment of contingent and future obligations of the trust. In addition, the trust received proceeds attributable to
the sale of certain properties underlying the Oklahoma net profits interests. (For further information on the property sale, see
Trustee’s Discussion and Analysis of Financial Condition and Results of Operations, under Item 7.)
The net profits interests constitute “economic interests” in oil and gas properties for federal tax purposes. Each unitholder is
entitled to amortize the cost of the units through cost depletion over the life of the net profits interests or, if greater, through
percentage depletion equal
limited to a
unitholder’s depletable tax basis in the units. Rather, aunitholder is entitled to a percentage depletion deduction as long as the
applicable underlying properties generate gross income. Unitholders may compute both percentage depletion and cost depletion
from each property and claim the larger amount as a deduction on their income tax returns.
to 15 percent of gross income. Unlike cost depletion, percentage depletion is not
If a taxpayer disposes of any “Section 1254 property” (certain oil, gas, geothermal or other mineral property), and the
adjusted basis of such property includes adjustments for depletion deductions under Section 611 of the Internal Revenue Code (the
“Code”), the taxpayer generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain
realized on the disposition of the property). This depletion recapture rule applies to any disposition of property that was placed in
service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury
Regulations govern dispositions of property after March 13, 1995. The Internal Revenue Service likely will take the position that a
unitholder must recapture depletion upon the disposition of a unit.
Interest and net profits income attributable to ownership of units and any gain on the sale thereof are considered portfolio
income, and not income from a “passive activity,” to the extent a unitholder acquires and holds units as an investment and not in the
ordinary course of a trade or business. Therefore, interest and net profits income attributable to ownership of units generally may
not be offset by losses from any passive activities.
Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6%,
and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or
exchange of certain investment assets held for more than one year) and qualified dividends of individuals is 20%. Such marginal tax
rates may be effectively increased by up to 1.2% due to the phaseout of personal exemptions and the limitations on itemized
deductions. The highest marginal U.S. federal income tax rate applicable to corporations is 35%, and such rate applies to both
ordinary income and capital gains.
Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts
for taxable years beginning after December 31, 2012. For these purposes, investment income generally will include aunitholder’s
allocable share of the trust’s interest and royalty income plus the gain recognized from a sale of trust units. In the case of an
individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or (ii) the amount by
which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such individual’s federal
income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (i) undistributed net investment income,
15
or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or
trust begins.
Pending the outcome of arbitration proceedings between the trust and XTO, the trust may be required to bear a portion of the
legal settlement costs arising from the Fankhouser settlement (discussed in Item 3 — Legal Proceedings). In the event that the trust
is determined to be responsible for such costs, XTO will deduct the costs in its calculation of the net profits income payable to the
trust from the applicable net profits interests. Thus, for unitholders, the legal settlement costs will be reflected through a reduction
in net profits income received from the trust and in a reduction in the gross royalty income reported by and taxable to the
unitholders. In addition to the potential settlement costs, the trustee has also incurred legal fees in representing the trust’s interests
in the ongoing arbitration and other pending litigation matters also discussed in “Item 3 — Legal Proceedings”. For unitholders,
such costs will be reflected through an increase in the trust’s administrative expenses, which are deductible by unitholders in
determining the net royalty income from the trust.
The difference between the per-unit taxable income for any period and the per-unit cash distributions, if any, reported for
such period is attributable to (i) items that are not currently deductible, such as an increase in the cash reserve maintained by the
trust for the payment of future expenditures, (ii) the current deduction of expenses that are paid with amounts previously reserved
and (iii) items that do not constitute taxable income, such as a decrease in the cash reserve maintained by the trust and/or a return
of capital. In 2012 and 2013, the trustee has elected to reserve amounts from monthly distributions in anticipation of legal fees
related to current and anticipated litigation (see discussion in Item 3 — Legal Proceedings), so the taxable income per period has
frequently differed from the actual amount distributed to unitholders.
Individuals may also incur expenses in connection with the acquisition or maintenance of trust units. These expenses, which
are different from a unitholder’s share of the trust’s administrative expenses discussed above, may be deductible as “miscellaneous
itemized deductions” only to the extent that such expenses exceed 2 percent of the individual’s gross income.
institutions” and certain other “non-financial
Pursuant to the Foreign Account Tax Compliance Act (commonly referred to as “FATCA”), distributions from the trust to
“foreign financial
to U.S. withholding taxes.
Specifically, certain “withholdable payments” (including certain royalties, interest and other gains or income from U.S. sources)
made to a foreign financial institution or non-financial foreign entity will generally be subject to the withholding tax unless the
foreign financial institution or non-financial foreign entity complies with certain information reporting, withholding, identification,
certification and related requirements imposed by FATCA. Foreign financial institutions located in jurisdictions that have an
intergovernmental agreement with the United States governing FATCA may be subject to different rules.
foreign entities” may be subject
The Treasury Department recently issued guidance providing that the FATCA withholding rules described above generally will
only apply to qualifying payments made after June 30, 2014. Foreign unitholders are encouraged to consult their own tax advisors
regarding the possible implications of these withholding provisions on their investment in trust units.
Some trust units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes
custodians, nominees, certain joint owners, and brokers holding an interest for a customer in street name, collectively referred to
herein as “middlemen”). Therefore, the trustee considers the trust to be a non-mortgage widely held fixed investment trust
(“WHFIT”) for U.S. federal income tax purposes. U.S. Trust, Bank of America Private Wealth Management, EIN: 56-0906609, Post
Office Box 830650, Dallas, Texas, 75283-0650, telephone number 1-877-228-5083, email address trustee1@hugotontrust.com, is
the representative of the trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing
the information reporting requirements of
the trust as a WHFIT. Tax information is also posted by the trustee at
www.hugotontrust.com. Notwithstanding the foregoing, the middlemen holding trust units on behalf of unitholders, and not the
trustee of the trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury
Regulations with respect
to such trust units, including the issuance of IRS Forms 1099 and certain written tax statements.
Unitholders whose trust units are held by middlemen should consult with such middlemen regarding the information that will be
reported to them by the middlemen with respect to the trust units.
Unitholders should consult their tax advisors regarding trust tax compliance matters.
16
State Income Taxes
All revenues from the trust are from sources within Kansas, Oklahoma or Wyoming. Kansas and Oklahoma each impose astate
income tax, which is potentially applicable to income from the net profits interests located in each of those states. Because it
distributes all of its net income to unitholders, the trust 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 Kansas and Oklahoma 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. Oklahoma taxes the income of nonresidents from real property located within the state, and the trust has been advised
by counsel that Oklahoma will tax nonresidents on income from the net profits interest located within the state. Kansas also taxes the
income of nonresidents from property located within the state. However, for tax years beginning after December 31, 2012,
Kansas allows individuals to deduct certain amounts,
their
including net
Form 1040 federal individual income tax return, from their federal adjusted gross income when calculating their Kansas taxable
income. This deduction applies to amounts reported as royalty income that are received from grantor trusts, such as the trust.
Kansas and Oklahoma also impose acorporate income tax that may apply to unitholders organized as corporations (subject to
certain exceptions for S corporations and limited liability companies, depending on their treatment for federal tax purposes).
income from royalties reported on schedule E of
Wyoming does not have a state income tax.
Each unitholder should consult his or her own tax advisor regarding state income tax requirements, if any, applicable to such
person’s ownership of trust units.
State Tax Withholding
Several states have enacted legislation requiring state income tax withholding from nonresident recipients of oil and gas
proceeds. After consultation with its tax counsel, the trustee believes that it is not required to withhold on payments made to the
unitholders. However, regulations are subject to change by the various states, which could change this conclusion. Should amounts
be withheld on payments made to the trust or the unitholders, distributions to the unitholders would be reduced by the required
amount, subject to the filing of a claim for refund by the trust or unitholders for such amount.
Other Regulation
The Minerals Management Service of the United States Department of the Interior amended the crude oil valuation regulations
in July 2004 and the natural gas valuation regulations in June 2005 for oil and natural gas produced from federal oil and natural gas
leases. The principal effect of the oil regulations pertains to which published market prices are most appropriate to value crude oil
not sold in an arm’s-length transaction and what transportation deductions should be allowed. The principal effect of the natural gas
valuation regulations pertains to the calculation of transportation deductions and changes necessitated by judicial decisions since
the regulations were last amended. Seven percent of the net acres of the underlying properties, primarily located in Wyoming,
involve federal leases. Neither of these changes have had a significant effect on trust distributions.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws,
including, but not limited to, regulations and laws relating to environmental protection, occupational safety, resource conservation
and equal employment opportunity. XTO Energy has advised the trustee that it does not believe that compliance with these laws will
have any material adverse effect upon the unitholders.
Item 3. Legal Proceedings
An amended petition for aclass action lawsuit, Beer, et al. v. XTO Energy Inc., was filed in January 2006 in the District Court
of Texas County, Oklahoma by certain royalty owners of natural gas wells in Oklahoma and Kansas. The plaintiffs allege that XTO
Energy has not properly accounted to the plaintiffs for the royalties to which they are entitled and seek an accounting regarding the
natural gas and other products produced from their wells and the prices paid for the natural gas and other products produced, and
for payment of the monies allegedly owed since June 2002, with a certain limited number of plaintiffs claiming monies owed for
additional time. XTO Energy removed the case to federal district court
in Oklahoma City. In April 2010, new counsel and
representative parties, Fankhouser and Goddard, filed a motion to intervene and prosecute the Beer class, now styled Fankhouser v.
17
XTO Energy Inc. This motion was granted on July 13, 2010. The new plaintiffs and counsel filed an amended complaint asserting
new causes of action for breach of fiduciary duties and unjust enrichment. On December 16, 2010, the court certified the class.
Cross motions for summary judgment were filed by the parties and ruled on by the court. XTO Energy has informed the trustee that
after consideration of the rulings by the court in March and April of 2012, some benefiting XTO Energy and some benefiting the
plaintiffs, and with due regard to the vagaries of litigation and their uncertain outcomes, XTO Energy and the plaintiffs entered into
settlement negotiations prior to trial and reached a tentative settlement of $37 million on April 23, 2012. XTO has advised the trustee
that $1.4 million of the settlement is attributable to Kansas claims which predate the Trust and therefore XTO Energy will not charge
to the Trust. The settlement also includes a new royalty calculation for future royalty payments. A fairness hearing was conducted on
October 10, 2012 and the settlement was given final approval by the court. The court’s order sets out the amount of attorneys’ fees
and costs awarded to the plaintiffs’ counsel from the $37 million settlement. A third party administrator will make the distribution to
the royalty owners as set out in the order approving the settlement.
XTO Energy has advised the trustee it believes that the terms of the conveyances covering the trust’s net profits interests require
the trust to bear its 80% interest in the settlement, or approximately $28.5 million, of which $23.4 million will affect the net
proceeds from Oklahoma and $5.1 million will affect the net proceeds from Kansas. If so, this will adversely affect the net proceeds
of the trust from Oklahoma and Kansas and will result in costs exceeding revenues on these properties. XTO Energy began deducting
the settlement amount with the September 2012 distribution. Based on the revised settlement allocation between Oklahoma and
Kansas and recent revenue and expense levels, the deductions XTO Energy has made, and will resume making if the Tribunal (as
defined below) ultimately rules in XTO Energy’s favor, will cause costs to exceed revenues for approximately 12 months on
properties underlying the Oklahoma net profits interests and by approximately 5 years on properties underlying the Kansas net
profits interests; however, changes in oil or natural gas prices or expenses could cause the time period to increase or decrease
correspondingly. Excess costs must be recovered, with accrued interest, from the future net proceeds of that conveyance and cannot
reduce net proceeds from other conveyances. The net profits interest from Wyoming is unaffected and payments will continue to be
made from those properties to the extent revenues exceed costs on such properties. XTO Energy has advised the trustee that the
settlement would decrease the amount of net profits going forward for the Oklahoma and Kansas properties due to changes in the
way costs (such as gathering, compression and fuel) associated with operating the properties will be allocated, resulting in a net
gain to the royalty interest owners. XTO Energy has advised the trustee that this expected net upward revision for the royalty interest
owners would reduce applicable net profits to XTO Energy and, correspondingly, to the trust. As of December 31, 2013, the revision
would have reduced trust net proceeds by approximately $842,000 (this amount would have been reflected in the June 2012
through December 2013 distributions).
The trustee has advised XTO Energy that all or a portion of the settlement amount should not be deducted from trust revenues.
The trustee further advised XTO that, notwithstanding the Fankhouser settlement, XTO should make no change in the manner in
which it calculates payments to the trust on a go-forward basis. XTO Energy does not agree with the trustee’s position, and to resolve
this disagreement XTO Energy initiated binding arbitration on August 1, 2012 in accordance with the terms of the dispute resolution
provisions of the Trust Indenture. All issues in the arbitration will be decided by a panel of three arbitrators (the “Tribunal”). Each
side selected one arbitrator and the third arbitrator was selected by the other two appointed arbitrators. The arbitration is being
administered by the American Arbitration Association under its commercial rules. The arbitration hearing was held as scheduled on
November 12 through November 14, 2013 in Fort Worth, Texas. The Tribunal is expected to issue a decision on or before April 21,
2014. Because XTO Energy advised the trustee that it began deducting the settlement in September 2012, the trustee reserved a total
of $900,000 from trust distributions to help fund potential legal and other expenses relating to the arbitration. The trustee believed
that without such a reserve, the trust was likely to be left without adequate resources to fund the costs of the arbitration out of
monthly trust revenues. As of September 30, 2013, the reserve had been fully depleted in connection with such expenses. Any
additional expenses related to this arbitration will be deducted as administrative expense when incurred, however a future reserve
may be established to accommodate payment of these expenses as needed.
The trustee requested that the Tribunal enjoin XTO Energy from continuing to deduct the Fankhouser settlement amount while
the arbitration is pending. The Tribunal ordered that pending the issuance of a final award or further order of the Tribunal, XTO
Energy should not treat any costs or expenses associated with the Fankhouser settlement as chargeable against the trust’s net profit
interest under the conveyances. The Tribunal denied the trustee’s request for an interim order directing XTO Energy to pay the trust
the amounts offset against the trust’s September and October 2012 distributions on the basis of the Fankhouser litigation. Based on
this decision, deductions associated with the Fankhouser settlement were suspended starting in November 2012. XTO Energy has
18
also informed the trustee that during the pendency of this action, no adjustment will be made to the net profits to the trust on a go-
forward basis based on the changes in the way costs will be allocated to royalty owners in accordance with the Fankhouser
settlement.
In September 2008, a class action lawsuit was filed against XTO Energy styled Wallace B. Roderick Revocable Living Trust,
et al. v. XTO Energy Inc. in the District Court of Kearny County, Kansas. XTO Energy removed the case to federal court in Wichita,
Kansas. The plaintiffs allege that XTO Energy has improperly taken post-production costs from royalties paid to the plaintiffs from
wells located in Kansas, Oklahoma and Colorado. The plaintiffs filed a motion to certify the class, including only Kansas and
Oklahoma wells not part of the Fankhouser matter. After filing the motion to certify, but prior to the class certification hearing, the
plaintiff filed a motion to sever the Oklahoma portion of the case so it could be transferred and consolidated with a newly filed class
action in Oklahoma styled Chieftain Royalty Company v. XTO Energy Inc. This motion was granted. The Roderick case now
comprises only Kansas wells not previously included in the Fankhouser matter. The case was certified as a class action in March
2012. XTO Energy filed an appeal of the class certification to the 10th Circuit Court of Appeals on April 11, 2012 which was granted
on June 26, 2012. The court reversed the certification of the class and remanded the case back to the trial court for further
proceedings.
In December 2010, a 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 expressly excludes those claims and wells prosecuted in the Fankhouser
case. The severed Roderick case claims related to the Oklahoma portion of the case were consolidated into Chieftain. The case was
certified as a class action in April 2012. XTO Energy filed an appeal of the class certification to the 10th Circuit Court of Appeals on
April 26, 2012 which was granted on June 26, 2012. The court reversed the certification of the class and remanded the case back to
the trial court for further proceedings.
XTO Energy has informed the trustee that it believes that XTO Energy has strong defenses to these lawsuits and intends to
vigorously defend its position. However, XTO Energy has informed the trustee that it is cognizant of other, similar litigation, such as
Fankhouser, and other, unrelated entities. As these cases develop, XTO Energy will assess its legal position accordingly. If XTO
Energy ultimately makes any settlement payments or receives a judgment against it in Chieftain or Roderick, XTO Energy has
advised the trustee that it believes that the terms of the conveyances covering the trust’s net profits interests require the trust to bear
its 80% share of such settlement or judgment related to production from the underlying properties. Additionally, if the judgment or
settlement increases the amount of future payments to royalty owners, XTO Energy has informed the trustee that the trust would bear
its proportionate share of the increased payments through reduced net proceeds. In the event of any such settlement or judgment,
the trustee intends to review any claimed reductions in payment to the trust based on the facts and circumstances of such settlement
or judgment. 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 profit interests of the cases named
above, as applicable, for several monthly distributions, depending on the size of the judgment or 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. If there is a settlement or judgment and should XTO Energy and the trustee disagree
concerning the amount of the settlement or judgment to be charged, if any, against the trust’s net profits interests, the matter will be
resolved by binding arbitration under the terms of the Indenture creating the trust through the American Arbitration Association.
On September 12, 2012, a lawsuit was filed against Bank of America as trustee and XTO Energy styled Harold Lamb v. Bank of
America and XTO Energy Inc., in the U.S. District Court — Western District of Oklahoma. The plaintiff, Harold Lamb, is a
unitholder in the trust and alleges that XTO Energy failed to properly pay and account to the trust under the terms of the net
overriding royalty conveyance on certain Kansas and Oklahoma properties and that Bank of America, N.A., as trustee, failed to
properly oversee such payment and accounting by XTO Energy. Additionally, the plaintiff alleged that Bank of America, N.A. and XTO
Energy breached a fiduciary duty to the trust based on the allegations found in the Fankhouser class action discussed above. The
plaintiffs sought unspecified amounts for actual/compensatory damages, punitive damages, disgorgement and injunctive relief.
19
Subsequently, the plaintiff dismissed Bank of America, N.A. from the lawsuit. The court granted XTO Energy’s motion to transfer
venue and transferred the case to the U.S. District Court for the Northern District of Texas. The Court granted XTO’s motion to
dismiss and dismissed the case citing the plaintiff’s failure to make asufficient pre-suit demand on the trustee. Subsequent to the
dismissal, attorneys for Mr. Lamb sent a letter to the trustee demanding that the trustee initiate proceedings against XTO Energy. The
trustee declined to do so, and on December 31, 2013, the plaintiff filed anew lawsuit against Bank of America, N.A. as trustee (as
nominal defendant) and XTO Energy styled Harold Lamb v. XTO Energy Inc. and Bank of America in the U.S. District Court for the
Northern District of Texas. XTO Energy and Bank of America, N.A. have appeared in the lawsuit and are currently seeking dismissal
of all claims. XTO Energy has informed the trustee that it believes that XTO Energy has strong defenses to this lawsuit and intends to
vigorously defend its position. The trustee will vigorously defend any claims that may be asserted against the trustee. The terms of the
trust indenture provide that Bank of America, N.A. and/or the trustee shall be indemnified by the trust and shall have no liability,
other than for fraud, gross negligence or acts or omissions in bad faith as adjudicated by final non-appealable judgment of a court
of competent jurisdiction.
On August 12, 2013, a demand for arbitration styled Sandra G. Goebel vs. XTO Energy, Inc., Timberland Gathering & Processing
Company, Inc. and Bank of America, N.A. was filed with the American Arbitration Association. The claimant, Sandra Goebel, is a
unitholder in the trust and alleged that XTO Energy breached the conveyances by misappropriating funds from the trust by failing to
modify its existing sales contracts with its affiliate Timberland Gathering & Processing Company, Inc. (“Timberland”). Goebel
alleged that these contracts do not currently reflect “market rate” terms, and that XTO had a duty to renegotiate the contracts to
obtain more favorable terms. The claimant further alleged that Bank of America, N.A. breached its fiduciary duty by acquiescing to
and facilitating XTO Energy’s alleged self-dealing and concealing information from unitholders that would have revealed XTO
Energy’s breaches. The claim also alleged aiding and abetting breach of fiduciary duty by XTO Energy, and disgorgement and unjust
enrichment by Timberland. The claimant sought from the respondents damages of an estimated $59.6 million for alleged royalty
underpayments, exemplary damages, an accounting by XTO Energy, a declaration, costs, reasonable attorneys’ fees, and pre-
judgment and post-judgment interest. Goebel purported to sue on behalf of and for the benefit of the Hugoton Royalty Trust. The
trustee filed a response to the arbitration demand denying any liability arising out of the claimant’s allegations and objecting to the
arbitrability of Goebel’s claims against the trustee. The arbitration panel ruled that Goebel’s claims are not arbitrable and dismissed
the claims in their entirety without prejudice. Goebel has refiled the matter as a lawsuit styled Sandra G. Goebel vs. XTO Energy,
Inc., Timberland Gathering & Processing Company, Inc. and Bank of America, N.A. in the Dallas County District Court. The
allegations are the same as those contained in the previous arbitration demand. XTO Energy has informed the trustee that it believes
that XTO Energy has strong defenses to this lawsuit and intends to vigorously defend its position. The trustee also believes it has
strong defenses to the lawsuit and will vigorously defend its position. The terms of the trust indenture provide that Bank of America,
N.A. and/or the trustee shall be indemnified by the trust and shall have no liability, other than 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 anticipates that the trust will incur additional legal and other expenses in connection with the Goebel litigation. As
a result, the trustee reserved an additional $1.6 million from trust distributions, beginning with the September 2013 distribution.
The September 2013 through December 2013 distributions each reflected adeduction of $400,000 in connection with such reserve.
Additionally, the trustee intends to reserve an additional $1.6 million from trust distributions for the Lamb litigation, which it
currently anticipates taking over a period of four months, beginning with the January 2014 distribution. As the above lawsuits
progress the trustee may need to revise these reserves.
Certain of the underlying properties are involved in various other lawsuits and certain governmental proceedings arising in the
ordinary course of business. XTO Energy has advised the trustee that it does not believe that the ultimate resolution of these claims
will have a material effect on the financial position or liquidity of the trust, but may have an effect on annual distributable income.
Item 4. Mine Safety Disclosures
Not Applicable.
20
PART II
Item 5. Market for Units of the Trust, Related Untiholder Matters and Trust Purchases of Units
Units of Beneficial Interest
The units of beneficial interest in the trust began trading on the New York Stock Exchange on April 9, 1999 under the symbol
“HGT.” The following are the high and low unit sales prices and total cash distributions per unit paid by the trust during each
quarter of 2013 and 2012:
Quarter
Sales Price
High
Low
Distributions
per Unit
2013
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
First
Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$ 9.97
9.98
9.45
8.16
$ 7.30
8.12
7.43
6.98
2012
First
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$19.21
14.62
7.90
8.56
$13.82
6.42
5.71
6.21
$0.195453
0.230142
0.251364
0.185723
$0.862682
$ 0.245636
0.164046
0.053733
0.118408
$ 0.581823
At December 31, 2013, there were 40,000,000 units outstanding and approximately 761 unitholders of record; 37,851,122 of
these units were held by depository institutions.
The trust has no equity compensation plans, nor has it purchased any units during the period covered by this report.
Item 6. Selected Financial Data
2013
Year Ended December 31
2011
2012
2010
2009
Net Profits Income . . . . . . . . . . . . . . . . . . . . . .. $ 37,333,595 $ 25,132,038 $ 56,565,368 $ 62,883,206 $ 30,180,880
29,306,240
Distributable Income . . . . . . . . . . . . . . . . . . . ..
0.732656
Distributable Income per Unit
. . . . . . . . . . . . . ..
0.732656
Distributions per Unit
. . . . . . . . . . . . . . . . . . . ..
144,162,380
Total Assets at Year-End . . . . . . . . . . . . . . . . . ..
34,507,280
0.862682
0.862682
102,501,095
62,028,000
1.550700
1.550700
129,222,886
55,764,960
1.394124
1.394124
118,965,716
23,272,920
0.581823
0.581823
112,956,689
21
Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations
Calculation of Net Profits Income
The following is a summary of the calculation of net profits income received by the trust:
Year Ended December 31(a)
2012
2013
2011
Three Months Ended
December 31(a)
2013
2012
Sales Volumes
Gas (Mcf)(b)
Underlying properties . . . . . . . . . . . . ..
. . . . . . . . . . . . . . ..
Net profits interests . . . . . . . . . . . . . . ..
Average per day
18,712,650
51,268
7,770,148
20,370,975
55,658
5,991,964
21,693,139
59,433
10,661,323
4,695,128
51,034
1,870,572
5,244,376
57,004
1,325,777
Oil (Bbls)(b)
Underlying properties . . . . . . . . . . . . ..
. . . . . . . . . . . . . . ..
Net profits interests . . . . . . . . . . . . . . ..
Average per day
Average Sales Prices
Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . ..
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . ..
Revenues
216,634
594
99,363
$4.03
$95.25
228,656
625
76,049
$3.28
$91.30
248,739
681
130,109
$4.73
$90.07
55,833
607
25,161
$3.97
$102.44
55,772
606
15,120
$3.28
$86.92
Gas sales . . . . . . . . . . . . . . . . . . . . . . . . ..
Oil sales . . . . . . . . . . . . . . . . . . . . . . . . ..
Total Revenues . . . . . . . . . . . . . . . . . ..
$75,469,935
20,635,040
96,104,975
$ 66,738,058
20,875,782
87,613,840
$102,621,117
22,405,023
125,026,140
$18,657,261
5,719,538
24,376,799
$17,206,796
4,847,434
22,054,230
Costs
Taxes, transportation and other . . . . . . . ..
Production expense . . . . . . . . . . . . . . . . ..
Development costs(c) . . . . . . . . . . . . . . . ..
Overhead . . . . . . . . . . . . . . . . . . . . . . . ..
Legal Expense(d)
. . . . . . . . . . . . . . . . . . ..
Excess costs(d) . . . . . . . . . . . . . . . . . . . . ..
Property Sales(e)
Total Costs . . . . . . . . . . . . . . . . . . . . ..
Other Proceeds . . . . . . . . . . . . . . . . . . . . ..
. . . . . . . . . . . . . . . . . . ..
Net Proceeds . . . . . . . . . . . . . . . . . . . . . . ..
Net Profits Percentage . . . . . . . . . . . . . . ..
Net Profits Income . . . . . . . . . . . . . . . . . ..
10,779,085
21,593,324
6,500,000
11,754,002
10,983,543
22,596,750
6,000,000
11,135,189
— 35,601,400
— (30,118,090)
56,198,792
50,626,411
13,613,297
21,103,426
8,800,000
10,802,707
—
—
54,319,430
2,886,081
2,609,372
5,253,599
5,402,343
1,500,000
1,800,000
2,858,695
3,029,280
—
—
— 3,342,186
15,840,561
12,840,995
$ 1,188,430
46,666,994
—
31,415,048
—
70,706,710
—
11,535,804
—
6,213,669
80%
80%
80%
80%
80%
$37,333,595
$ 25,132,038
$ 56,565,368
$ 9,228,643
$ 4,970,935
(a) Because of the two-month interval between time of production and receipt of net profits income by the trust: 1) oil and gas
sales for the year ended December 31 generally relate to twelve months of production for the period November through
October, and 2) oil and gas sales for the three months ended December 31 generally relate to production for the period
August through October.
(b) Oil and gas sales volumes are allocated to the net profits interests based upon a formula that considers oil and gas prices and
the total amount of production expense and development costs. As product prices change, the trust’s share of the production
volumes is impacted as the quantity of production to cover expenses in reaching the net profits break-even level changes
inversely with price. As such, the underlying property production volume changes may not correlate with the trust’s net profit
share of those volumes in any given period. Therefore, comparative discussion of oil and gas sales volumes is based on the
underlying properties.
See Note 5 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
See Note 4 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
See Note 11 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
(c)
(d)
(e)
22
Results of Operations
Years Ended December 31, 2013, 2012 and 2011
Net profits income for 2013 was $37,333,595, as compared with $25,132,038 for 2012 and $56,565,368 for 2011. The 49%
increase in net profits income from 2012 to 2013 is primarily the result of higher oil and gas prices ($13.1 million), the portion of
the Fankhouser settlement deducted in September and October 2012 ($4.4 million) and proceeds from the property sale in May
2013 ($1.0 million), partially offset by decreased oil and gas production ($6.3 million). The 56% decrease in net profits income
from 2011 to 2012 is primarily the result of lower gas prices ($25.2 million), decreased oil and gas production ($5.0 million) and
the portion of the Fankhouser settlement deducted in September and October of 2012 ($4.4 million), partially offset by lower
development costs ($2.2 million). Approximately 76% in 2013, 74% in 2012 and 81% in 2011 of net profits income was derived
from natural gas sales.
Trust administration expense was $2,827,015 in 2013 as compared to $1,859,626 in 2012 and $801,563 in 2011. Included in
2013 administration expense is $1,600,000 which the trustee has reserved for legal expenses regarding the Goebel litigation and
included in 2012 was $900,000 which the trustee reserved for legal expenses regarding the Fankhouser class action settlement.
Interest income was $700 in 2013, $508 in 2012 and $1,155 in 2011. Changes in interest income are attributable to fluctuations in
net profits income and interest rates. Distributable income was $34,507,280 or $0.862682 per unit in 2013, $23,272,920 or
$0.581823 per unit in 2012 and $55,764,960 or $1.394124 per unit in 2011.
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.
Volumes
From 2012 to 2013, underlying gas sales volumes decreased 8% primarily due to natural production decline. Underlying oil
sales volumes decreased 5% primarily due to natural production decline, partially offset by the timing of cash receipts. From 2011
to 2012, underlying gas sales volumes decreased 6% and underlying oil sales volumes decreased 8% primarily due to natural
production decline.
The estimated rate of natural production decline on the underlying oil and gas properties is approximately 6% to 8% a year.
Prices
Gas.
The 2013 average gas price was $4.03 per Mcf, a 23% increase from the 2012 average gas price of $3.28 per Mcf,
which was a 31% decrease from the 2011 average gas price of $4.73 per Mcf. Natural gas prices are affected by the level of North
American production, weather, crude oil and natural gas liquids prices, the U.S. economy, storage levels and import levels of
liquefied natural gas. Natural gas prices are expected to remain volatile. The average NYMEX price for November 2013 through
January 2014 was $3.91 per MMBtu. At February 18, 2014, the average NYMEX gas price for the following 12 months was $4.81 per
MMBtu.
Oil.
The average oil price for 2013 was $95.25 per Bbl, 4% higher than the average oil price for 2012 of $91.30 per Bbl,
which was 1% higher than the average oil price for 2011 of $90.07 per Bbl. Oil prices are expected to remain volatile. The average
NYMEX price for November 2013 through January 2014 was $95.58 per Bbl. At February 18, 2014, the average NYMEX oil price for
the following 12 months was $97.99 per Bbl.
Costs
The calculation of net profits income includes deductions for production expense, development costs and overhead since the
related underlying properties are working interests. If monthly costs exceed revenues for any state, these excess costs must be
recovered, with accrued interest, from future net proceeds of that state and cannot reduce net profits income from another state.
See “Excess costs” below.
23
Taxes, transportation and other.
Taxes, transportation and other generally fluctuates with changes in total revenues.
Taxes, transportation and other decreased 2% from 2012 to 2013 primarily because of decreased property taxes related to
decreased valuations, partially offset by increased gas production taxes related to higher gas revenues. Taxes, transportation and
other decreased 19% from 2011 to 2012 primarily because of decreased gas production taxes and other deductions related to
lower gas revenues, partially offset by increased property taxes related to increased valuations.
Production expense.
Production expense decreased 4% from 2012 to 2013 primarily because of decreased repairs and
maintenance, compressor and outside operated costs, partially offset by increased labor and field costs. Production expense
increased 7% from 2011 to 2012 primarily because of increased labor, repairs and maintenance costs and mechanical and
marketing rebates included in 2011, partially offset by decreased fuel costs.
Development costs. Development costs deducted were $6.5 million in 2013, $6.0 million in 2012 and $8.8 million in 2011. In
2013, actual development costs were $5.6 million. At December 31, 2013, cumulative budgeted costs exceeded cumulative actual costs
by approximately $0.6 million. The monthly development cost deduction was $850,000 from the January 2011 distribution through the
August 2011 distribution. Due to lower than anticipated actual costs as a result of reduced activity, the development cost deduction was
decreased to $500,000 beginning with the September 2011 distribution and was maintained at that level through the July 2013
distribution. As a result of increased development activity, the monthly development cost deduction was increased from $500,000 to
$600,000 beginning with the August 2013 distribution and was maintained at that level through the end of 2013. For further information
on 2014 budgeted development costs, see Properties, under Item 2. 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 this monthly deduction will continue to be evaluated and revised as necessary.
Overhead. Overhead is charged by XTO Energy for administrative expenses incurred to support operations of the underlying
properties. Overhead fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well
as an annual cost level adjustment.
Excess costs.
Costs exceeded revenues by $114,245 ($91,396 net to the trust) on properties underlying the Wyoming net
profits interests in July 2012. Lower gas prices and increased production expenses related to the timing of cash disbursements
caused costs to exceed revenues on properties underlying the Wyoming net profits interests. However, these excess costs did not
reduce net proceeds from the remaining conveyances. XTO advised the trustee that increased gas prices and decreased production
expenses led to the full recovery of excess costs, plus accrued interest of $314 ($251 net to the trust) in August 2012.
XTO advised the trustee in September 2012 that it deducted $35,601,400 ($28,481,120 net to the trust) related to the Fankhouser
settlement. The settlement deduction caused costs to exceed revenues by $27,235,464 ($21,788,371 net to the trust) on properties
underlying the Oklahoma net profits interests and by $6,225,126 ($4,980,101 net to the trust) on properties underlying the Kansas net
profits interests. However, these excess costs did not reduce net proceeds from the remaining conveyance. XTO advised the trustee in
October 2012 that it partially recovered $3,342,186 ($2,673,749 net to the trust) of excess costs. Remaining excess costs at December 31,
2012 were $24,027,648 ($19,222,118 net to the trust) on properties underlying the Oklahoma net profits interests and $6,090,756
($4,872,605 net to the trust) on properties underlying the Kansas net profits interests. The excess costs claimed underlying the Kansas and
Oklahoma net profits interests are the subject of pending arbitration described more fully under “Item 3 — Legal Proceedings.” See Note 8
to Financial Statements under Item 8, Financial Statements and Supplementary Data.
Fourth Quarter 2013 and 2012
During fourth quarter 2013 the trust received net profits income totaling $9,228,643 compared with fourth quarter 2012 net
profits income of $4,970,935. This 86% increase in net profits income was primarily due to higher oil and gas prices ($3.6 million)
and the portion of the Fankhouser settlement deducted in October of 2012 ($2.7 million), partially offset by decreased gas
production ($1.7 million).
Administration expense was $1,799,868 and interest income was $145, resulting in fourth quarter 2013 distributable income
of $7,428,920 or $0.185723 per unit. Included in fourth quarter 2013 administration expense is $1,200,000 which the trustee has
reserved for legal expenses regarding the Goebel litigation. Distributable income for fourth quarter 2012 was $4,736,320 or
$0.118408 per unit.
24
Distributions to unitholders for the quarter ended December 31, 2013 were:
Record Date
Payment Date
3102,13rebotcO
3102,92rebmevoN
3102,13rebmeceD
3102,51rebmevoN
3102,31rebmeceD
4102,51yraunaJ
Per Unit
395860.0$
159160.0
971550.0
$0.185723
Volumes
Fourth quarter underlying gas sales volumes decreased 10% and underlying oil sales volumes remained relatively flat from
2012 to 2013. Gas sales volumes decreased primarily due to natural production decline and the timing of cash receipts. Oil sales
volumes remained relatively flat as the timing of cash receipts was offset by natural production decline.
Prices
The average fourth quarter 2013 gas price was $3.97 per Mcf, or 21% higher than the fourth quarter 2012 average price of
$3.28 per Mcf. The average fourth quarter 2013 oil price was $102.44 per Bbl, or 18% higher than the fourth quarter 2012 average
price of $86.92 per Bbl. For further information about product prices, see “Years Ended December 31, 2013, 2012 and 2011 —
Prices” above.
Costs
Taxes, transportation and other.
Taxes, transportation and other decreased 10% from fourth quarter 2012 to 2013
primarily because of decreased property taxes related to decreased valuations.
Production expense.
Fourth quarter production expense increased 3% from 2012 to 2013 primarily because of increased
location costs, mechanical and marketing rebates included in fourth quarter 2012 and increased compressor costs, partially offset
by decreased repairs and maintenance costs.
Development costs. Development costs, which were deducted based on budgeted development costs, increased 20% from
fourth quarter 2012 to 2013. For further information about development costs, see “Years Ended December 31, 2013, 2012 and
2011 — Development Costs” above.
Overhead. Overhead is charged by XTO Energy for administrative expenses incurred to support operations of the underlying
properties. Overhead fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well
as an annual cost level adjustment.
Excess costs.
XTO advised the trustee in September 2012 that it deducted $35,601,400 ($28,481,120 net to the trust)
related to the Fankhouser settlement. The settlement deduction caused costs to exceed revenues by $27,235,464 ($21,788,371 net
to the trust) on properties underlying the Oklahoma net profits interests and by $6,225,126 ($4,980,101 net to the trust) on
properties underlying the Kansas net profits interests. However, these excess costs did not reduce net proceeds from the remaining
conveyance. XTO advised the trustee in October 2012 that it partially recovered $3,342,186 ($2,673,749 net to the trust) of excess
costs. Remaining excess costs at December 31, 2012 were $24,027,648 ($19,222,118 net to the trust) on properties underlying the
Oklahoma net profits interests and $6,090,756 ($4,872,605 net to the trust) on properties underlying the Kansas net profits
interests. The excess costs claimed underlying the Kansas and Oklahoma net profits interests are the subject of pending arbitration
described more fully under “Item 3 — Legal Proceedings.” See Note 8 to Financial Statements under Item 8, Financial Statements
and Supplementary Data.
Other
In accordance with the terms of the Hugoton Royalty Trust Indenture, XTO Energy advised the trustee that on April 24, 2013 it
sold properties underlying the Oklahoma net profits interests for $1,188,430 ($950,744 net to the trust). This amount was included
in the May 2013 distribution.
25
The trust is required to join in a sale of 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.
Liquidity and Capital Resources
The trust’s only cash requirement is the monthly distribution of its income to unitholders, which is funded by the monthly
receipt of net profits income after payment of trust administration expenses. The trust is not liable for any production costs or
liabilities attributable to the net profits interests. If at any time the trust receives net profits income in excess of the amount due, the
trust is not obligated to return such overpayment, but future net profits income payable to the trust will be reduced by the
overpayment, plus interest at the prime rate. The trust may borrow funds required to pay trust liabilities if fully repaid prior to
further distributions to unitholders.
The trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that
could materially affect the trust’s liquidity or the availability of capital resources.
Greenhouse Gas Emissions and Climate Change Regulation
There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and
climate change. Several states have adopted climate change legislation and regulations, and various other regulatory bodies have
announced their intent to regulate GHG emissions or adopt climate change regulations. As these regulations are under development,
XTO Energy is unable to predict the total impact of the potential regulations upon the operators of the underlying properties, and it
is possible that the operators of the underlying properties could face increases in operating costs in order to comply with climate
change or GHG emissions legislation, which costs could reduce net proceeds payable to the trust and trust distributions.
Off-Balance Sheet Arrangements
The trust has no off-balance sheet financing arrangements. The trust has not guaranteed the debt of any other party, nor does
the trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses
or contingent obligations.
Contractual Obligations
As shown below, the trust had no obligations and commitments to make future contractual payments as of December 31,
2013, other than the December distribution payable to unitholders in January 2014, as reflected in the statement of assets, liabilities
and trust corpus.
Payments due by Period
Total
Less than
1 Year
1 - 3 Years
3 - 5 Years
More than
5 Years
Distribution payable to unitholders . . . . . . . . . . . . . . . . . . . . ..
$2,207,160
$2,207,160
$—
$—
$—
Related Party Transactions
The underlying properties from which the net profits interests were carved are currently owned by XTO Energy, which
operates approximately 95% of the underlying properties. In computing net proceeds, XTO Energy deducts a monthly overhead
charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31, 2013, the
monthly overhead charge, based on the number of operated wells, was approximately $1,001,000 ($800,800 net to the trust) and is
subject to annual adjustment based on an oil and gas industry index.
XTO Energy sells as ignificant portion of natural gas production from the underlying properties to certain of XTO Energy’s wholly
owned subsidiaries under contracts in existence when the trust was created, generally at amounts approximating monthly published market
prices. 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 7to F inancial Statements under Item 8, Financial Statements and Supplementary Data. Total
gas sales from the underlying properties to XTO Energy’s wholly owned subsidiaries were $29.0 million for 2013, or 38% of total gas sales,
$22.3 million for 2012, or 34% of total gas sales and $35.6 million for 2011, or 35% of total gas sales.
On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.
26
Critical Accounting Policies
The financial statements of the trust are significantly affected by its basis of accounting and estimates related to its oil and gas
properties and proved reserves, as summarized below.
Basis of Accounting
The trust’s financial statements are prepared on a modified cash basis, which is a comprehensive basis of accounting other
than U.S. generally accepted accounting principles. This method of accounting is consistent with reporting of taxable income to trust
unitholders. The most significant differences between the trust’s financial statements and those prepared in accordance with U.S.
generally accepted accounting principles are:
• Net profits income is recognized in the month received rather than accrued in the month of production.
• Expenses are recognized when paid rather than when incurred.
• Cash reserves may be established by the trustee for certain contingencies that would not be recorded under U.S. generally
accepted accounting principles.
This comprehensive basis of accounting other than U.S. generally accepted accounting principles corresponds to the
accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin
Topic 12:E, Financial Statements of Royalty Trusts. For further information regarding the trust’s basis of accounting, see Note 2 to
Financial Statements under Item 8, Financial Statements and Supplementary Data.
All amounts included in the trust’s financial statements are based on cash amounts received or disbursed, or on the carrying
value of the net profits interests, which was derived from the historical cost of the interests at the date of their transfer from XTO
Energy, less accumulated amortization to date. Accordingly, there are no fair value estimates included in the financial statements
based on either exchange or nonexchange trade values.
Oil and Gas Reserves
The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. The
estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves
attributable to the net profits interests. Reserve engineering is a subjective process that is dependent upon the quality of available
data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors
such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as
changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using
12-month average prices, based on the first-day-of-the-month price for each month in the period, estimated reserve quantities can
be significantly impacted by changes in product prices. Accordingly, oil and gas quantities ultimately recovered and the timing of
production may be substantially different from original estimates.
The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 9 to
Financial Statements under Item 8, Financial Statements and Supplementary Data, is prepared using assumptions required by the
Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using 12-month
average oil and gas prices, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated
future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any
of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure.
Accordingly, the standardized measure does not represent XTO Energy’s or the trustee’s estimated current market value of proved
reserves.
Forward-Looking Statements
Certain information included in this annual report and other materials filed, or to be filed, by the trust with the Securities and
Exchange Commission (as well as information included in oral statements or other written statements made or to be made by XTO
Energy or the trustee) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934,
27
as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the trust, operations of the underlying properties
and the oil and gas industry. Such forward-looking statements may concern, among other things, reserve-to-production ratios,
future production, development activities, future development plans by area, increased density drilling, maintenance projects,
development, production and other costs, oil and gas prices, pricing differentials, proved reserves, future net cash flows, production
levels, litigation, regulatory matters, competition, and the satisfaction or waiver of conditions to the trustee’s resignation. Such
forward-looking statements are based on XTO Energy’s current plans, expectations, assumptions, projections and estimates and are
identified by words such as “expects,” “intends,” “plans,” “projects,” “anticipates,” “predicts,” “believes,” “goals,” “estimates,”
“should,” “could”, and similar words that convey the uncertainty of future events. These statements are not guarantees of future
performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual results may
differ materially from expectations, estimates or assumptions expressed in, implied in, or forecasted in such forward-looking
statements. Some of the risk factors that could cause actual results to differ materially are explained in Item 1A, Risk Factors.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
The only assets of and sources of income to the trust are the net profits interests, which generally entitle the trust to receive a
share of the net profits from oil and gas production from the underlying properties. Consequently, the trust is exposed to market
risk from fluctuations in oil and gas prices. The trust is a passive entity and, other than the trust’s ability to periodically borrow
money as necessary to pay expenses, liabilities and obligations of the trust that cannot be paid out of cash held by the trust, the trust
is prohibited from engaging in borrowing transactions. The amount of any such borrowings is unlikely to be material to the trust. In
addition, the trustee is prohibited by the trust indenture from engaging in any business activity or causing the trust to enter into any
investments other than investing cash on hand in specific short-term cash investments. Therefore, the trust cannot hold any
derivative financial instruments. As a result of the limited nature of its borrowing and investing activities, the trust is not subject to
any material interest rate market risk. Additionally, any gains or losses from any hedging activities conducted by XTO Energy are
specifically excluded from the calculation of net proceeds due the trust under the forms of the conveyances. The trust does not
engage in transactions in foreign currencies which could expose the trust to any foreign currency related market risk.
28
Item 8. Financial Statements and Supplementary Data
Statements of Assets, Liabilities and Trust Corpus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Statements of Distributable Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Statements of Changes in Trust Corpus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Page
30
30
30
31
42
All financial statement schedules are omitted as they are inapplicable or the required information has been included in the
consolidated financial statements or notes thereto.
29
HUGOTON ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
December 31
2013
2012
Assets
Cash and short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Net profits interests in oil and gas properties – net
$
3,646,537
$
3,063,712
(Notes 1 and 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
98,854,558
109,892,977
$102,501,095
$112,956,689
Liabilities and Trust Corpus
Distribution payable to unitholders
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Legal reserve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding) . . . . ..
$
2,207,160
1,439,377
98,854,558
$
2,379,120
684,592
109,892,977
$102,501,095
$112,956,689
STATEMENTS OF DISTRIBUTABLE INCOME
Year Ended December 31
2012
2013
2011
Net profits income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$37,333,595
700
$25,132,038
508
$56,565,368
1,155
Total income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Administration expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
37,334,295
2,827,015
25,132,546
1,859,626
56,566,523
801,563
Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$34,507,280
$23,272,920
$55,764,960
Distributable income per unit (40,000,000 units) . . . . . . . . . . . . . . . . . . ..
$ 0.862682
$ 0.581823
$ 1.394124
STATEMENTS OF CHANGES IN TRUST CORPUS
Year Ended December 31
2012
2013
2011
Trust corpus, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Amortization of net profits interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Distributions declared . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$109,892,977
(11,038,419)
34,507,280
(34,507,280)
$115,367,996
(5,475,019)
23,272,920
(23,272,920)
$124,993,766
(9,625,770)
55,764,960
(55,764,960)
Trust corpus, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$ 98,854,558
$109,892,977
$115,367,996
See accompanying notes to financial statements.
30
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
1. Trust Organization and Provisions
Hugoton Royalty Trust was created on December 1, 1998 by XTO Energy Inc. (formerly known as “Cross Timbers Oil
Company”). Effective on that date, XTO Energy conveyed 80% net profits interests in certain predominantly gas-producing working
interest properties in Kansas, Oklahoma and Wyoming to the trust under separate conveyances for each of the three states. In
exchange for the conveyances of the net profits interests to the trust, XTO Energy received 40 million units of beneficial interest in
the trust. The trust’s initial public offering was in April 1999. The majority of the underlying working interest properties are
currently owned and operated by XTO Energy (Note 7).
Bank of America, N.A. is the trustee for the trust. In 2007 the Bank of America private wealth management group officially
became known as “U.S. Trust, Bank of America Private Wealth Management.” The legal entity that serves as the trustee of the trust
did not change, and references in this Annual Report to U.S. Trust, Bank of America Private Wealth Management shall describe the
legal entity Bank of America, N.A. The trust indenture provides, among other provisions, that:
• the trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-
term cash investments;
• the trust may dispose of all or part of the net profits interests if approved by a vote of holders of 80% or more of the
outstanding trust units, or upon trust termination. Otherwise, the trust is required to sell up to 1% of the value of the net
profits interests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the related underlying
properties. Any sale must be for cash with 80% of the proceeds distributed to the unitholders on the next declared
distribution;
• the trustee may establish a cash reserve for payment of any liability that is contingent or not currently payable;
• the trustee may borrow funds to pay trust liabilities if repaid in full prior to further distributions to unitholders;
• the trustee will make monthly cash distributions to unitholders (Note 3); and
• the trust will terminate upon the first occurrence of:
•
•
•
disposition of all net profits interests pursuant to terms of the trust indenture,
gross proceeds from the underlying properties falling below $1 million per year for two successive years, or
a vote of holders of 80% or more of the outstanding trust units to terminate the trust in accordance with provisions
of the trust indenture.
On January 9, 2014, U.S. Trust, Bank of America Private Wealth Management gave notice to unitholders that it will be resigning
as trustee subject to the conditions set forth below. Bank of America, N.A. intends to nominate Southwest Bank, an independent state
bank chartered under the laws of the State of Texas and headquartered in Fort Worth, Texas (“Southwest Bank”), as successor
trustee at a meeting of unitholders of the trust to be called for the purpose of approving a successor trustee of the Trust. U.S. Trust,
Bank of America Private Wealth Management’s resignation is conditioned on the satisfaction or waiver by U.S. Trust, Bank of
America Private Wealth Management of each of the following: (i) the appointment of Southwest Bank as trustee of Sabine Royalty
Trust (another royalty trust for which U.S. Trust, Bank of America Private Wealth Management currently serves as trustee); (ii) the
appointment of Southwest Bank or another successor trustee as trustee of the trust and five other royalty trusts for which U.S. Trust,
Bank of America Private Wealth Management currently serves as trustee and as agent under a disbursing arrangement for which it
currently serves as agent; (iii) the accuracy of certain representations and warranties and performance of certain agreements made
by Southwest Bank in an agreement between U.S. Trust, Bank of America Private Wealth Management and Southwest Bank; and
(iv) no governmental injunction, order or other action that would prohibit Southwest Bank’s appointment, U.S. Trust, Bank of
America Private Wealth Management’s resignation or the other actions described above. The effective date of U.S. Trust, Bank of
America Private Wealth Management’s resignation shall be May 30, 2014, assuming all of the conditions described above have been
satisfied or waived as of such date.
31
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
2. Basis of Accounting
The financial statements of the trust are prepared on the following basis and are not intended to present financial position and
results of operations in conformity with U.S. generally accepted accounting principles:
• Net profits income is recorded in the month received by the trustee (Note 3).
• 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 (Note 3).
• The trustee routinely reviews the trust’s net profits interests in oil and gas properties for impairment whenever events or
circumstances indicate that the carrying amount of an asset may not be recoverable. If an impairment event occurs and it is
determined that the carrying value of the trust’s net profits interests may not be recoverable, an impairment will be
recognized as measured by the amount by which the carrying amount of the net profits interests exceeds the fair value of
these assets, which would likely be measured by discounting projected cash flows. There is no impairment of the assets as
of December 31, 2013.
The most significant differences between the trust’s financial statements and those prepared in accordance with U.S. generally
accepted accounting principles are:
• Net profits income is recognized in the month received rather than accrued in the month of production.
• Expenses are recognized when paid rather than when incurred.
• Cash reserves may be established by the trustee for contingencies that would not be recorded under U.S. generally accepted
accounting principles.
This comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the U.S. Securities and
Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.
Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with U.S. generally
accepted accounting principles, 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.
The initial carrying value of the net profits interests of $247,066,951 was XTO Energy’s historical net book value of the
interests on December 1, 1998, the date of the transfer to the trust. Amortization of the net profits interests is calculated on a
unit-of-production basis and charged directly to trust corpus. Accumulated amortization was $148,212,393 as of December 31,
2013 and $137,173,974 as of December 31, 2012.
3. Distributions to Unitholders
The trustee determines the amount to be distributed to unitholders each month by totaling net profits income, interest income
and other cash receipts, and subtracting liabilities paid and adjustments in cash reserves established by the trustee. The resulting
amount is distributed to unitholders of record within ten business days after the monthly record date, which is the last business day
of the month.
Net profits income received by the trustee consists of net proceeds received in the prior month by XTO Energy from the
underlying properties, multiplied by 80%. Net proceeds are the gross proceeds received from the sale of production, less costs.
Costs generally include applicable taxes, transportation, legal and marketing charges, production expense, development and drilling
costs, and overhead (Note 7).
32
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the three conveyances
(one for each of the states of Kansas, Oklahoma and Wyoming). If costs exceed revenues for any conveyance, such excess costs
must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from
the other conveyances (Note 4).
4. Excess Costs
Costs exceeded revenues by $114,245 ($91,396 net to the trust) on properties underlying the Wyoming net profits interests in
July 2012. Lower gas prices and increased production expenses related to the timing of cash disbursements caused costs to exceed
revenues on properties underlying the Wyoming net profits interests. However, these excess costs did not reduce net proceeds from
the remaining conveyances. XTO advised the trustee that increased gas prices and decreased production expenses led to the full
recovery of excess costs, plus accrued interest of $314 ($251 net to the trust) in August 2012.
XTO advised the trustee in September 2012 that it deducted $35,601,400 ($28,481,120 net to the trust) related to the
Fankhouser settlement. The settlement deduction caused costs to exceed revenues by $27,235,464 ($21,788,371 net to the trust)
on properties underlying the Oklahoma net profits interests and by $6,225,126 ($4,980,101 net to the trust) on properties
underlying the Kansas net profits interests. However,
these excess costs did not reduce net proceeds from the remaining
conveyance. XTO advised the trustee in October 2012 that it partially recovered $3,342,186 ($2,673,749 net to the trust) of excess
costs. Remaining excess costs at December 31, 2012 were $24,027,648 ($19,222,118 net to the trust) on properties underlying the
Oklahoma net profits interests and $6,090,756 ($4,872,605 net to the trust) on properties underlying the Kansas net profits
interests (Note 8). The excess costs claimed underlying the Kansas and Oklahoma net profits interests are the subject of pending
arbitration described more fully under (Note 8).
5. Development Costs
The following summarizes actual development costs, budgeted development costs deducted in the calculation of net profits
income, and the cumulative actual costs compared to the amount deducted:
Year Ended December 31
2012
2013
2011
Cumulative actual costs (over) under the amount deducted –
beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Actual costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Budgeted costs deducted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$ (301,922)
(5,609,336)
6,500,000
$ 2,396,920
(8,698,842)
6,000,000
$ (809,696)
(5,593,384)
8,800,000
Cumulative actual costs under (over) the amount deducted – end of
period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$
588,742
$ (301,922)
$ 2,396,920
The monthly development cost deduction was $850,000 from the January 2011 distribution through the August 2011
distribution. Due to lower than anticipated actual costs as a result of reduced activity, the development cost deduction was
decreased to $500,000 beginning with the September 2011 distribution and was maintained at that level through the July 2013
distribution. As a result of increased development activity, the monthly development cost deduction was increased from $500,000 to
$600,000 beginning with the August 2013 distribution and was maintained at that level through the end of 2013. For further
information on 2014 budgeted development costs, see Properties, under Item 2. 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 this monthly deduction will continue to be evaluated and revised as necessary.
33
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
6. Income Taxes
For federal income tax purposes, the trust constitutes afixed 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.
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 Kansas and Oklahoma 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 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.
7. XTO Energy Inc.
XTO Energy operates approximately 95% of the underlying properties. In computing net proceeds, XTO Energy deducts an
overhead charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31, 2013,
the overhead charge was approximately $1,001,000 ($800,800 net to the trust) per month and is subject to annual adjustment
based on an oil and gas industry index as defined in the trust agreement.
XTO Energy sells a significant portion of natural gas production from the underlying properties to certain of XTO Energy’s
wholly owned subsidiaries under contracts in existence when the trust was created, generally at amounts approximating monthly
published market prices. Most of the production from the Hugoton area is sold under a contract to Timberland Gathering &
Processing Company, Inc. (“TGPC”) based on the index price. Much of the gas production in Major County, Oklahoma is sold to
Ringwood Gathering Company (“RGC”), which retains approximately $0.31 per Mcf as a compression and gathering fee. TGPC and
RGC sell gas to Cross Timbers Energy Services, Inc. (“CTES”), which markets gas to third parties. XTO Energy sells directly to CTES
most gas production not sold directly to TGPC or RGC.
Total gas sales from the underlying properties to XTO Energy’s wholly owned subsidiaries were $29.0 million for 2013, or
38% of total gas sales, $22.3 million for 2012, or 34% of total gas sales and, $35.6 million for 2011, or 35% of total gas sales.
On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.
8. Contingencies
Litigation
An amended petition for a class action lawsuit, Beer, et al. v. XTO Energy Inc., was filed in January 2006 in the District Court
of Texas County, Oklahoma by certain royalty owners of natural gas wells in Oklahoma and Kansas. The plaintiffs allege that XTO
Energy has not properly accounted to the plaintiffs for the royalties to which they are entitled and seek an accounting regarding the
natural gas and other products produced from their wells and the prices paid for the natural gas and other products produced, and
for payment of the monies allegedly owed since June 2002, with a certain limited number of plaintiffs claiming monies owed for
additional time. XTO Energy removed the case to federal district court
in Oklahoma City. In April 2010, new counsel and
representative parties, Fankhouser and Goddard, filed a motion to intervene and prosecute the Beer class, now styled Fankhouser v.
34
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
XTO Energy Inc. This motion was granted on July 13, 2010. The new plaintiffs and counsel filed an amended complaint asserting
new causes of action for breach of fiduciary duties and unjust enrichment. On December 16, 2010, the court certified the class.
Cross motions for summary judgment were filed by the parties and ruled on by the court. XTO Energy has informed the trustee that
after consideration of the rulings by the court in March and April of 2012, some benefiting XTO Energy and some benefiting the
plaintiffs, and with due regard to the vagaries of litigation and their uncertain outcomes, XTO Energy and the plaintiffs entered into
settlement negotiations prior to trial and reached a tentative settlement of $37 million on April 23, 2012. XTO has advised the trustee
that $1.4 million of the settlement is attributable to Kansas claims which predate the Trust and therefore XTO Energy will not charge
to the Trust. The settlement also includes a new royalty calculation for future royalty payments. A fairness hearing was conducted on
October 10, 2012 and the settlement was given final approval by the court. The court’s order sets out the amount of attorneys’ fees
and costs awarded to the plaintiffs’ counsel from the $37 million settlement. A third party administrator will make the distribution to
the royalty owners as set out in the order approving the settlement.
XTO Energy has advised the trustee it believes that the terms of the conveyances covering the trust’s net profits interests require
the trust to bear its 80% interest in the settlement, or approximately $28.5 million, of which $23.4 million will affect the net
proceeds from Oklahoma and $5.1 million will affect the net proceeds from Kansas. If so, this will adversely affect the net proceeds
of the trust from Oklahoma and Kansas and will result in costs exceeding revenues on these properties. XTO Energy began deducting
the settlement amount with the September 2012 distribution. Based on the revised settlement allocation between Oklahoma and
Kansas and recent revenue and expense levels, the deductions XTO Energy has made, and will resume making if the Tribunal (as
defined below) ultimately rules in XTO Energy’s favor, will cause costs to exceed revenues for approximately 12 months on
properties underlying the Oklahoma net profits interests and by approximately 5 years on properties underlying the Kansas net
profits interests; however, changes in oil or natural gas prices or expenses could cause the time period to increase or decrease
correspondingly. Excess costs must be recovered, with accrued interest, from the future net proceeds of that conveyance and cannot
reduce net proceeds from other conveyances. The net profits interest from Wyoming is unaffected and payments will continue to be
made from those properties to the extent revenues exceed costs on such properties. XTO Energy has advised the trustee that the
settlement would decrease the amount of net profits going forward for the Oklahoma and Kansas properties due to changes in the
way costs (such as gathering, compression and fuel) associated with operating the properties will be allocated, resulting in a net
gain to the royalty interest owners. XTO Energy has advised the trustee that this expected net upward revision for the royalty interest
owners would reduce applicable net profits to XTO Energy and, correspondingly, to the trust. As of December 31, 2013, the revision
would have reduced trust net proceeds by approximately $842,000 (this amount would have been reflected in the June 2012
through December 2013 distributions).
The trustee has advised XTO Energy that all or a portion of the settlement amount should not be deducted from trust revenues.
The trustee further advised XTO that, notwithstanding the Fankhouser settlement, XTO should make no change in the manner in
which it calculates payments to the trust on a go-forward basis. XTO Energy does not agree with the trustee’s position, and to resolve
this disagreement XTO Energy initiated binding arbitration on August 1, 2012 in accordance with the terms of the dispute resolution
provisions of the Trust Indenture. All issues in the arbitration will be decided by a panel of three arbitrators (the “Tribunal”). Each
side selected one arbitrator and the third arbitrator was selected by the other two appointed arbitrators. The arbitration is being
administered by the American Arbitration Association under its commercial rules. The arbitration hearing was held as scheduled on
November 12 through November 14, 2013 in Fort Worth, Texas. The Tribunal is expected to issue a decision on or before April 21,
2014. Because XTO Energy advised the trustee that it began deducting the settlement in September 2012, the trustee reserved a total
of $900,000 from trust distributions to help fund potential legal and other expenses relating to the arbitration. The trustee believed
that without such a reserve, the trust was likely to be left without adequate resources to fund the costs of the arbitration out of
monthly trust revenues. As of September 30, 2013, the reserve had been fully depleted in connection with such expenses. Any
additional expenses related to this arbitration will be deducted as administrative expense when incurred, however a future reserve
may be established to accommodate payment of these expenses as needed.
The trustee requested that the Tribunal enjoin XTO Energy from continuing to deduct the Fankhouser settlement amount while
the arbitration is pending. The Tribunal ordered that pending the issuance of a final award or further order of the Tribunal, XTO
35
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Energy should not treat any costs or expenses associated with the Fankhouser settlement as chargeable against the trust’s net profit
interest under the conveyances. The Tribunal denied the trustee’s request for an interim order directing XTO Energy to pay the trust
the amounts offset against the trust’s September and October 2012 distributions on the basis of the Fankhouser litigation. Based on
this decision, deductions associated with the Fankhouser settlement were suspended starting in November 2012. XTO Energy has
also informed the trustee that during the pendency of this action, no adjustment will be made to the net profits to the trust on a go-
forward basis based on the changes in the way costs will be allocated to royalty owners in accordance with the Fankhouser
settlement.
In September 2008, a class action lawsuit was filed against XTO Energy styled Wallace B. Roderick Revocable Living Trust,
et al. v. XTO Energy Inc. in the District Court of Kearny County, Kansas. XTO Energy removed the case to federal court in Wichita,
Kansas. The plaintiffs allege that XTO Energy has improperly taken post-production costs from royalties paid to the plaintiffs from
wells located in Kansas, Oklahoma and Colorado. The plaintiffs filed a motion to certify the class, including only Kansas and
Oklahoma wells not part of the Fankhouser matter. After filing the motion to certify, but prior to the class certification hearing, the
plaintiff filed a motion to sever the Oklahoma portion of the case so it could be transferred and consolidated with a newly filed class
action in Oklahoma styled Chieftain Royalty Company v. XTO Energy Inc. This motion was granted. The Roderick case now
comprises only Kansas wells not previously included in the Fankhouser matter. The case was certified as a class action in March
2012. XTO Energy filed an appeal of the class certification to the 10th Circuit Court of Appeals on April 11, 2012 which was granted
on June 26, 2012. The court reversed the certification of the class and remanded the case back to the trial court for further
proceedings.
In December 2010, a 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 expressly excludes those claims and wells prosecuted in the Fankhouser
case. The severed Roderick case claims related to the Oklahoma portion of the case were consolidated into Chieftain. The case was
certified as a class action in April 2012. XTO Energy filed an appeal of the class certification to the 10th Circuit Court of Appeals on
April 26, 2012 which was granted on June 26, 2012. The court reversed the certification of the class and remanded the case back to
the trial court for further proceedings.
XTO Energy has informed the trustee that it believes that XTO Energy has strong defenses to these lawsuits and intends to
vigorously defend its position. However, XTO Energy has informed the Trustee that it is cognizant of other, similar litigation, such as
Fankhouser, and other, unrelated entities. As these cases develop, XTO Energy will assess its legal position accordingly. If XTO
Energy ultimately makes any settlement payments or receives a judgment against it in Chieftain or Roderick, XTO Energy has
advised the trustee that it believes that the terms of the conveyances covering the trust’s net profits interests require the trust to bear
its 80% share of such settlement or judgment related to production from the underlying properties. Additionally, if the judgment or
settlement increases the amount of future payments to royalty owners, XTO Energy has informed the trustee that the trust would bear
its proportionate share of the increased payments through reduced net proceeds. In the event of any such settlement or judgment,
the trustee intends to review any claimed reductions in payment to the trust based on the facts and circumstances of such settlement
or judgment. 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 profit interests of the cases named
above, as applicable, for several monthly distributions, depending on the size of the judgment or 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. If there is a settlement or judgment and should XTO Energy and the trustee disagree
concerning the amount of the settlement or judgment to be charged, if any, against the trust’s net profits interests, the matter will be
resolved by binding arbitration under the terms of the Indenture creating the trust through the American Arbitration Association.
36
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
On September 12, 2012, a lawsuit was filed against Bank of America, N.A. as trustee and XTO Energy styled Harold Lamb v. Bank of
America and XTO Energy Inc., in the U.S. District Court — Western District of Oklahoma. The plaintiff, Harold Lamb, is a unitholder in the
trust and alleges that XTO Energy failed to properly pay and account to the trust under the terms of the net overriding royalty conveyance on
certain Kansas and Oklahoma properties and that Bank of America, N.A., as trustee, failed to properly oversee such payment and accounting
by XTO Energy. Additionally, the plaintiff alleged that Bank of America, N.A. and XTO Energy breached afiduciary duty to the trust based on
the allegations found in the Fankhouser class action discussed above. The plaintiffs sought unspecified amounts for actual/compensatory
damages, punitive damages, disgorgement and injunctive relief. Subsequently, the plaintiff dismissed Bank of America, N.A. from the lawsuit.
The court granted XTO Energy’s motion to transfer venue and transferred the case to the U.S. District Court for the Northern District of
Texas. The Court granted XTO’s motion to dismiss and dismissed the case citing the plaintiff’s failure to make as ufficient pre-suit demand on
the trustee. Subsequent to the dismissal, attorneys for Mr. Lamb sent a letter to the trustee demanding that the trustee initiate proceedings
against XTO Energy. The trustee declined to do so, and on December 31, 2013, the plaintiff filed anew lawsuit against Bank of America as
trustee (as nominal defendant) and XTO Energy styled Harold Lamb v. XTO Energy Inc. and Bank of America in the U.S. District Court for
the Northern District of Texas. XTO Energy and Bank of America, N.A. have appeared in the lawsuit and are currently seeking dismissal of all
claims. XTO Energy has informed the trustee that it believes that XTO Energy has strong defenses to this lawsuit and intends to vigorously
defend its position. The trustee will vigorously defend any claims that may be asserted against the trustee. The terms of the trust indenture
provide that Bank of America, N.A. and/or the trustee shall be indemnified by the trust and shall have no liability, other than for fraud, gross
negligence or acts or omissions in bad faith as adjudicated by final non-appealable judgment of a court of competent jurisdiction.
On August 12, 2013, a demand for arbitration styled Sandra G. Goebel vs. XTO Energy, Inc., Timberland Gathering &
Processing Company, Inc. and Bank of America, N.A. was filed with the American Arbitration Association. The claimant, Sandra
Goebel, is a unitholder in the trust and alleged that XTO Energy breached the conveyances by misappropriating funds from the trust
by failing to modify its existing sales contracts with its affiliate Timberland Gathering & Processing Company, Inc. (“Timberland”).
Goebel alleged that these contracts do not currently reflect “market rate” terms, and that XTO had a duty to renegotiate the contracts
to obtain more favorable terms. The claimant further alleged that Bank of America, N.A. breached its fiduciary duty by acquiescing to
and facilitating XTO Energy’s alleged self-dealing and concealing information from unitholders that would have revealed XTO
Energy’s breaches. The claim also alleged aiding and abetting breach of fiduciary duty by XTO Energy, and disgorgement and unjust
enrichment by Timberland. The claimant sought from the respondents damages of an estimated $59.6 million for alleged royalty
underpayments, exemplary damages, an accounting by XTO Energy, a declaration, costs, reasonable attorneys’ fees, and pre-
judgment and post-judgment interest. Goebel purported to sue on behalf of and for the benefit of the Hugoton Royalty Trust. The
trustee filed a response to the arbitration demand denying any liability arising out of the claimant’s allegations and objecting to the
arbitrability of Goebel’s claims against the trustee. The arbitration panel ruled that Goebel’s claims are not arbitrable and dismissed
the claims in their entirety without prejudice. Goebel has refiled the matter as a lawsuit styled Sandra G. Goebel vs. XTO Energy,
Inc., Timberland Gathering & Processing Company, Inc. and Bank of America, N.A. in the Dallas County District Court. The
allegations are the same as those contained in the previous arbitration demand. XTO Energy has informed the trustee that it believes
that XTO Energy has strong defenses to this lawsuit and intends to vigorously defend its position. The trustee also believes it has
strong defenses to the lawsuit and will vigorously defend its position. The terms of the trust indenture provide that Bank of America,
N.A. and/or the trustee shall be indemnified by the trust and shall have no liability, other than 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 anticipates that the trust will incur additional legal and other expenses in connection with the Goebel litigation. As
a result, the trustee reserved an additional $1.6 million from trust distributions, beginning with the September 2013 distribution.
The September 2013 through December 2013 distributions each reflected adeduction of $400,000 in connection with such reserve.
Additionally, the trustee intends to reserve an additional $1.6 million from trust distributions for the Lamb litigation, which it
currently anticipates taking over a period of four months, beginning with the January 2014 distribution. As the above lawsuits
progress the trustee may need to revise these reserves.
Certain of the underlying properties are involved in various other lawsuits and certain 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.
37
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Other
Several states have enacted legislation requiring state income tax withholding from nonresident recipients of oil and gas
proceeds. After consultation with its tax counsel, the trustee believes that it is not required to withhold on payments made to the
unitholders. However, regulations are subject to change by the various states, which could change this conclusion. Should amounts
be withheld on payments made to the trust or the unitholders, distributions to the unitholders would be reduced by the required
amount, subject to the filing of a claim for refund by the trust or unitholders for such amount.
9. Supplemental Oil and Gas Reserve Information (Unaudited)
Oil and Natural Gas Reserves
Proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are those quantities of
oil and natural gas, which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be
economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating
methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence
indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing
wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with
the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to
change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves
may be substantially different
from the original estimate. Revisions result primarily from new information obtained from
development drilling and production history and from changes in economic factors.
Standardized Measure
The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions
required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month average prices for oil and
gas, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development
and production expenditures to produce the proved reserves. 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 our future cash flows or the value of proved oil and
gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations.
Furthermore, prices used to determine the standardized measure are influenced by supply and demand as affected by recent
economic conditions as well as other factors and may not be the most representative in estimating future revenues or reserve data.
Estimated costs to plug and abandon wells on the underlying working interest properties at the end of their productive lives
have not been deducted from cash flows since this is not a legal obligation of the trust. These costs are the legal obligation of XTO
Energy as the owner of the underlying working interests and will only be deducted from net proceeds payable to the trust if net
proceeds from the related conveyance exceed such costs when paid, subject to excess cost carryforward provisions (Notes 3 and 4).
The average realized gas prices used to determine the standardized measure were $3.92 per Mcf in 2013, $3.21 per Mcf in
2012, $4.67 per Mcf in 2011 and $4.45 per Mcf in 2010. Oil prices used to determine the standardized measure were based on
average realized oil prices of $94.32 per Bbl in 2013, $91.90 per Bbl in 2012, $92.92 per Bbl in 2011 and $75.91 per Bbl in 2010.
38
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Proved Reserves
(in thousands)
Underlying Properties
Oil (Bbls)
Gas (Mcf)
Net Profits Interests
Gas (Mcf)
Oil (Bbls)
Balance, December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Extensions, additions and discoveries
. . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Balance, December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Extensions, additions and discoveries
. . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Balance, December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Extensions, additions and discoveries
. . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
314,994
175
(3,567)
(21,693)
—
289,909
217
(21,574)
(20,371)
—
248,181
5
12,050
(18,713)
(50)
2,861
12
115
(249)
—
2,739
32
(29)
(229)
—
2,513
2
214
(217)
(27)
138,436
70
(1,583)
(10,661)
—
126,262
96
(43,010)
(5,992)
—
77,356
3
15,900
(7,770)
(15)
Balance, December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
241,473
2,485
85,474
1,336
5
76
(130)
—
1,287
14
(350)
(76)
—
875
1
200
(99)
(8)
969
Extensions, additions and discoveries in 2011, 2012 and 2013 are primarily related to delineation of additional proved
undeveloped reserves in the Anadarko Basin. 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. Negative revisions of 2012 gas reserves related primarily to
lower gas prices used to estimate reserves and negative revisions of 2011 gas reserves related primarily to increased future costs.
Higher upward and downward revisions for the net profits interests as compared with the underlying properties in each year were
caused by changes in oil and gas prices and estimated future production and development costs which resulted in an increase or
decrease in gas reserves allocated to the trust.
Proved Developed Reserves
(in thousands)
Underlying Properties
Gas (Mcf)
Oil (Bbls)
Net Profits Interests
Gas (Mcf)
Oil (Bbls)
December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
276,089
December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
250,833
December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
211,638
December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
204,611
2,513
2,391
2,192
2,163
126,349
113,312
71,327
76,239
1,218
1,159
806
878
39
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
Underlying Properties
Future cash inflows
Future costs:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
2013
December 31
2012
2011
$1,181,208
$1,028,147
$1,607,753
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
621,958
64,064
495,186
237,147
579,185
64,064
384,898
181,595
717,786
67,668
822,299
403,608
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$ 258,039
$ 203,303
$ 418,691
Net Profits Interests
Future cash inflows
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Future production taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$ 431,190
35,041
$ 334,857
26,939
$ 716,607
58,767
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
396,149
189,718
307,918
145,275
657,840
322,887
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$ 206,431
$ 162,643
$ 334,953
Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
2013
2012
2011
Underlying Properties
Standardized measure, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$203,303
$ 418,691
$424,589
Revisions:
Prices and costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Quantity estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Accretion of discount
Future development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Production rates and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Net revisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
76,488
(784)
18,387
6,172
1,868
102,131
103
(53,167)
6,500
(831)
(215,934)
(2,787)
36,486
(1,734)
(1,106)
(185,075)
1,102
(37,415)
6,000
—
40,475
(9,059)
37,013
(3,504)
(723)
64,202
606
(79,506)
8,800
—
Net change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
54,736
(215,388)
(5,898)
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$258,039
$ 203,303
$418,691
Net Profits Interests
Standardized measure, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Accretion of discount
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Revisions of prior estimates, changes in price and other . . . . . . . . . . . . . . . . . . . . . . . . . ..
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Net profits income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$162,643
82
14,710
66,861
(531)
(37,334)
$ 334,953
882
29,189
(177,249)
—
(25,132)
$339,671
485
29,611
21,751
—
(56,565)
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$206,431
$ 162,643
$334,953
40
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
10. Quarterly Financial Data (Unaudited)
The following is a summary of net profits income, distributable income and distributable income per unit by quarter for 2013
and 2012:
2013
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . ..
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . ..
2012
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . ..
. . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Third Quarter
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Net Profits
Income
Distributable
Income
Distributable
Income
per Unit
$ 8,065,774
9,457,572
10,581,606
9,228,643
$ 7,818,120
9,205,680
10,054,560
7,428,920
$0.195453
0.230142
0.251364
0.185723
$37,333,595
$34,507,280
$0.862682
$ 10,073,319
6,956,529
3,131,255
4,970,935
$
9,825,440
6,561,840
2,149,320
4,736,320
$ 0.245636
0.164046
0.053733
0.118408
$ 25,132,038
$ 23,272,920
$ 0.581823
11. Other
In accordance with the terms of the Hugoton Royalty Trust Indenture, XTO Energy advised the trustee that on April 24, 2013 it
sold properties underlying the Oklahoma net profits interests for $1,188,430 ($950,744 net to the trust). This amount was included
in the May 2013 distribution.
The trust is required to join in a sale of 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.
41
Report of Independent Registered Public Accounting Firm
To the Unitholders of Hugoton Royalty Trust and
Bank of America, N.A., Trustee
We have audited the accompanying statements of assets, liabilities and trust corpus of Hugoton Royalty Trust (the “Trust”) as
of December 31, 2013 and 2012, and the related statements of distributable income and changes in trust corpus for each of the
three years in the period ended December 31, 2013. We also have audited the Trust’s internal control over financial reporting as of
December 31, 2013, based on criteria established in Internal Control — Integrated Framework (1992) issued by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO). The Trustee is responsible for these financial statements, for
maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over
financial reporting, included in the Trustee’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our
responsibility is to express opinions on these financial statements and on the Trust’s internal control over financial reporting based
on our integrated audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements
are free of material misstatement and whether effective internal control over financial reporting was maintained in all material
respects. Our audits of
the financial statements included examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles used and significant estimates made by the trustee, and
evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing
such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for
our opinions.
As described in Note 2, these financial statements were prepared on the modified cash basis of accounting, which is a
comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
A trust’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A trust’s internal control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of
the assets of the trust; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the trust are
being made only in accordance with authorizations of the trustee; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the trust’s assets that could have a material effect on the financial
statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust
corpus of the Trust at December 31, 2013 and 2012, and the distributable income and changes in trust corpus for each of the three
years in the period ended December 31, 2013, on the basis of accounting described in Note 2. Also in our opinion, the Trust
maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria
established in Internal Control — Integrated Framework (1992) issued by COSO.
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
March 14, 2014
42
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The trustee conducted an evaluation of the trust’s disclosure controls and procedures, as such term is defined under
Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, the trustee has
concluded that the trust’s disclosure controls and procedures were effective as of the end of the period covered by this annual
report. In its evaluation of disclosure controls and procedures, the trustee has relied, to the extent considered reasonable, on
information provided by XTO Energy.
Trustee’s Report on Internal Control Over Financial Reporting
The trustee, Bank of America, N.A., also known as U.S. Trust, Bank of America Private Wealth Management, is responsible for
establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f)
promulgated under the Securities Exchange Act of 1934, as amended. The trustee conducted an evaluation of the effectiveness of the
trust’s internal control over financial reporting based on the criteria established in Internal Control — Integrated Framework
(1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the trustee’s evaluation under
the framework in Internal Control — Integrated Framework (1992), the trustee concluded that the trust’s internal control over
financial reporting was effective as of December 31, 2013. The effectiveness of the trust’s internal control over financial reporting as
of December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
stated in their report under Item 8, Financial Statements and Supplementary Data.
Changes in Internal Control Over Financial Reporting
There were no changes in the trust’s internal control over financial reporting during the quarter ended December 31, 2013
that have materially affected, or are reasonably likely to materially affect, the trust’s internal control over financial reporting.
Item 9B. Other Information
None.
43
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The trust has no directors, executive officers or audit committee. The trustee is a corporate trustee which may be removed,
with or without cause, by the affirmative vote of the holders of a majority of all the units then outstanding.
Section 16(a) of the Securities Exchange Act of 1934 requires that directors, officers, and beneficial owners of more than 10%
of the registrant’s equity securities file initial reports of beneficial ownership and reports of changes in beneficial ownership with the
Securities and Exchange Commission and the New York Stock Exchange. To the trustee’s knowledge, based solely on the
information furnished to the trustee, the trustee is unaware of any person that failed to file on a timely basis reports required by
Section 16(a) filing requirements with respect to the trust units of beneficial interest during and for the year ended December 31,
2013.
Because the trust has no employees, it does not have a code of ethics. Employees of the trustee, U.S. Trust, Bank of America
Private Wealth Management, must comply with the bank’s code of ethics, a copy of which will be provided to unitholders, without
charge, upon request by appointment at Bank of America Plaza, 17th Floor, 901 Main Street, Dallas, Texas 75202.
Item 11. Executive Compensation
The trustee received the following annual compensation from 2011 through 2013 as specified in the trust indenture:
Name and Principal Position
U.S. Trust, Bank of America . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Private Wealth Management, Trustee . . . . . . . . . . . . . . . . . . . ..
Year
2013
2012
2011
Other Annual
Compensation(1)
$63,343
58,873
51,936
(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.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The trust has no equity compensation plans.
(a) Security Ownership of Certain Beneficial Owners.
The trustee is not aware of any person who beneficially owns more
than 5% of the outstanding units.
(b) Security Ownership of Management.
The trust has no directors or executive officers. As of February 4, 2014, Bank of
America Corporation and its subsidiaries owned, in various fiduciary capacities, 584,381 units, with a shared right to vote 565,363
of these units and shared dispositive power with respect to 19,018 of these units. Bank of America, N.A. disclaims any beneficial
interests in these units.
(c) Changes in Control.
The trustee knows of no arrangements which may subsequently result in a change in control of the
trust.
Item 13. Certain Relationships and Related Transactions, and Director Independence
In computing net profits income paid to the trust for the net profits interests, XTO Energy deducts an overhead charge for
reimbursement of administrative expenses of operating the underlying properties. This charge at December 31, 2013 was
approximately $1,001,000 per month, or $12,012,000 annually (net to the trust of $800,800 per month or $9,609,600 annually),
and is subject to annual adjustment based on an oil and gas industry index as defined in the trust agreement.
44
XTO Energy sells asignificant portion of natural gas production from the underlying properties to certain of its wholly owned
subsidiaries under contracts in existence when the trust was created, generally at amounts approximating monthly published prices.
For further information, see Item 2, Properties.
See Item 11, Executive Compensation, for the remuneration received by the trustee from 2011 through 2013 and Item 12(b),
Security Ownership of Management, for information concerning units owned by the trustee in various fiduciary capacities.
As noted in Item 10, Directors, Executive Officers and Corporate Governance, the trust has no directors, executive officers or
audit committee. The trustee is a corporate trustee which may be removed, with or without cause, by the affirmative vote of the
holders of a majority of all the units then outstanding.
Item 14. Principal Accountant Fees and Services
Fees for services performed by PricewaterhouseCoopers LLP and KPMG LLP for the years ended December 31, 2013 and 2012
are:
Audit fees-KPMG(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Audit fees-PwC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Audit-related fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
Tax fees
All other fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..
$
7,034
$116,850
—
—
—
$10,017
$89,900
—
—
—
2013
2012
$123,884
$99,917
(a) KPMG LLP served as the trust’s independent registered public accounting firm through July 7, 2011, and was replaced by
PricewaterhouseCoopers LLP effective on that date.
As referenced in Item 10, Directors, Executive Officers and Corporate Governance, above, the trust has no audit committee,
and as a result, has no audit committee pre-approval policy with respect to fees paid to PricewaterhouseCoopers LLP or KPMG LLP.
45
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as a part of this report:
1.
Financial Statements (included in Item 8 of this report)
Reports of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus at December 31, 2013 and 2012
Statements of Distributable Income for the years ended December 31, 2013, 2012 and 2011
Statements of Changes in Trust Corpus for the years ended December 31, 2013, 2012 and 2011
Notes to Financial Statements
2.
Financial Statement Schedules
Financial statement schedules are omitted because of the absence of conditions under which they are required or because the
required information is given in the financial statements or notes thereto.
3.
Exhibits
(4) (a)
(b)
(c)
(d)
Hugoton Royalty Trust Indenture by and between NationsBank, N.A. (now Bank of America, 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.
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. (now Bank of America, 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.
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. (now Bank of America,
N.A.), as trustee, dated December 1, 1998, heretofore filed as Exhibit 10.1.2 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.
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. (now Bank of America,
N.A.), as trustee, dated December 1, 1998, heretofore filed as Exhibit 10.1.3 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.
(31)
(32)
Rule 13a-14(a)/15d-14(a) Certification
Section 1350 Certification
(99.1)
Miller and Lents, Ltd. Report
Copies of the above Exhibits are available to any unitholder, at the actual cost of reproduction, upon written request to the
trustee, U.S. Trust, Bank of America Private Wealth Management, P.O. Box 830650, Dallas, Texas 75283-0650.
46
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused
this Report to be signed on its behalf by the undersigned thereunto duly authorized.
SIGNATURES
HUGOTON ROYALTY TRUST
By BANK OF AMERICA, N.A., TRUSTEE
By /S/ NANCY G. WILLIS
Nancy G. Willis
Vice President
EXXON MOBIL CORPORATION
/S/ BETH E. CASTEEL
yB
Beth E. Casteel
Vice President — Upstream Business Services
(The trust has no directors or executive officers.)
4102,41hcraM:etaD
47
Form 10-K
A copy of the Hugoton Royalty Trust Form 10-K has been provided with this Annual Report. Additional copies
of this Annual Report and Form 10-K will be provided to unitholders without charge upon request. Copies of
exhibits to the Form 10-K may be obtained upon request or from the trust’s web site at www.hugotontrust.com.
Hugoton Royalty Trust
U.S. Trust, Bank of America
Private Wealth Management, Trustee
P.O. Box 830650
Dallas, Texas 75283-0650
Attention: Annual Reports
(877) 228-5083
Web site
www.hugotontrust.com
Auditors
PricewaterhouseCoopers LLP
Dallas, Texas
Legal and Tax Counsel
Thompson & Knight LLP
Dallas, Texas
Transfer Agent and Registrar
American Stock Transfer and Trust Company LLC
www.amstock.com
Certification
The Trustee’s certification, required by Section 302 of the Sarbanes-Oxley Act of 2002, has been filed as
Exhibit 31 of the Trust’s Form 10-K, for the fiscal year ended December 31, 2013.
Hugoton Royalty Trust
U.S. Trust, Bank of America
Private Wealth Management, Trustee
P.O. Box 830650
Dallas, Texas 75283-0650
1-877-228-5083
www.hugotontrust.com