Hugoton Royalty Trust
2014
Annual Report and Form 10-K
Glossary of Terms
Bbl
Bcf
Mcf
Barrel (of oil)
Billion cubic feet (of natural gas)
Thousand cubic feet (of natural gas)
MMBtu
One million British Thermal Units, a common energy measurement
Net Proceeds
Gross proceeds received by XTO Energy from sale of production from the underlying
Net Profits Income
Net Profits Interest
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 2014 and 2013:
2014
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2013
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Sales Price
High
$ 9.11
Low
$ 7.48
12.04
11.11
10.25
7.62
8.93
7.51
$ 9.97
9.98
9.45
8.16
$ 7.30
8.12
7.43
6.98
Distributions
per Unit
$0.191258
0.446171
0.253546
0.204267
$1.095242
$0.195453
0.230142
0.251364
0.185723
$0.862682
At December 31, 2014, there were 40,000,000 units outstanding and approximately 706 unitholders of record; 37,908,768
of these units were held by depository institutions.
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 Kansas net profits interests in November 2014 and
September 2012, on properties underlying the Wyoming
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.
net profits interests in July 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 were subject to 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 2014 tax booklet for specific
instructions. Unitholders should consult their tax
advisors for further information.
2014
Years Ended December 31,
Net Profits Income ........................... $ 44,446,473
Distributable Income ....................... 43,809,680
Distributable Income per Unit .........
1.095242
Distributions per Unit ......................
1.095242
Total Assets at Year End .................. $ 93,920,959
2013
$ 37,333,595
34,507,280
0.862682
0.862682
$102,501,095
2012
$ 25,132,038
23,272,920
0.581823
0.581823
$112,956,689
2011
2010
$ 56,565,368 $ 62,883,206
62,028,000
55,764,960
1.550700
1.394124
1.550700
1.394124
$ 118,965,716 $ 129,222,886
To Unitholders:
We are pleased to present
the 2014 Annual Report
The Trust and XTO Energy are parties
to several legal proceedings that may
on Form 10-K of the Hugoton Royalty Trust
affect future trust distributions. For further
as filed with the Securities and Exchange
information, please see “Legal Proceedings”
Commission. This report contains important
under Item 3 of the accompanying Form 10-K.
information about the trust’s net profits
Natural gas prices averaged $4.60 per Mcf
interests, including information provided to the
for 2014, 14% higher compared to the 2013
trustee by XTO Energy.
average price of $4.03 per Mcf. The average
For the year ended December 31, 2014,
2014 oil price was $95.35 per Bbl, relatively flat
net profits income totaled $44,446,473.
from the 2013 average price of $95.25 per Bbl.
After adding interest income of $517,131
Gas sales volumes from the underlying
and deducting trust administration expense
properties for 2014 were 17,426,780 Mcf, or
of $1,153,924, distributable income was
47,745 Mcf per day, a decrease of 7% from
$43,809,680 or $1.095242 per unit. Net profits
51,268 Mcf per day in 2013. Oil sales volumes
income and distributions were 19% and
from the underlying properties were 203,667
27%, respectively, higher than 2013 amounts
Bbls, or 558 Bbls per day in 2014, a decrease
primarily because of higher gas prices and the
of 6% from 594 Bbls per day in 2013. For
May 2014 arbitration reimbursement, partially
further information on sales volumes and
offset by decreased oil and gas production.
product prices, see “Trustee’s Discussion and
For further information on the arbitration
Analysis of Financial Condition and Results of
reimbursement, see “Legal Proceedings” under
Operations” under Item 7 of the accompanying
Item 3 of the accompanying Form 10-K.
Form 10-K.
To Unitholders: Continued
As of December 31, 2014,
revisions of prior reserve estimates, partially
proved reserves for the underlying
offset by higher gas prices. All reserve
properties were estimated by independent
information prepared by independent engineers
engineers to be 210.2 Bcf of natural gas and
has been provided to the trustee by XTO Energy.
2.2 million Bbls of oil. Natural gas reserves
Estimated future net cash flows from
for the underlying properties declined 31.3 Bcf
proved reserves of the net profits interests at
and oil reserves for the underlying properties
December 31, 2014 were $379 million. Using
declined approximately 266,000 Bbls primarily
an annual discount factor of 10%, the present
due to current year production and downward
value of estimated future net cash flows at
revisions of prior reserve estimates, partially
December 31, 2014 was $197 million. Proved
offset by higher gas prices used to estimate
reserve estimates and related future net
reserves. Based on an allocation of these
cash flows have been determined based on a
reserves, proved reserves attributable to the
12-month average gas price of $4.35 per Mcf
net profits interests were estimated to be 76.2
and a 12-month average oil price of $92.70
Bcf of natural gas and 0.9 million Bbls of oil.
per Bbl, based on the first-day-of-the-month
Estimated gas and oil reserves attributable
price for each month in the period, and year
to the net profits interests decreased from
end costs. Other guidelines used in estimating
previously reported reserves at year-end 2013
proved reserves, as prescribed by the Financial
due to current year production and downward
Accounting Standards Board, are described
To Unitholders: Continued
in Note 9 to Financial Statements
N.A., as trustee of the Hugoton Royalty Trust
under Item 8, “Financial Statements
announced that at the special meeting of
and Supplementary Data” of the accompanying
trust’s unitholders held on May 23, 2014,
Form 10-K. The present value of estimated
the unitholders of the trust voted to approve
future net cash flows is computed based on SEC
the proposal to appoint Southwest Bank as
guidelines and is not necessarily representative
successor trustee of the trust effective
of the market value of trust units.
May 30, 2014.
As disclosed in the tax instructions
provided to unitholders in February 2015, trust
distributions are considered portfolio income,
rather than passive income. Unitholders
should consult their tax advisors for further
information.
U.S. Trust, Bank of America Private Wealth
Management, a division of Bank of America,
Hugoton Royalty Trust
By: Southwest Bank, Trustee
By: Nancy G. Willis
Vice President
March 6, 2015
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
For the fiscal year ended December 31, 2014
Commission file number 1-10476
Hugoton Royalty Trust
(Exact name of registrant as specified in the Hugoton Royalty Trust Indenture)
Texas
(State or other jurisdiction of
incorporation or organization)
Southwest Bank
Trustee
P.O. Box 962020
Fort Worth, Texas
(Address of principal executive offices)
58-6379215
(I.R.S. Employer Identification No.)
76162-2020
(Zip Code)
Registrant’s telephone number including area code:
(855) 588-7839
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Units of Beneficial Interest
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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
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 a smaller reporting company)
Smaller reporting company ‘
Indicate by check mark whether the registrant is a shell 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 30, 2014 (the last
business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $439 million.
At February 13, 2015, 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
2014 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.
Trustee’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . .
Item 7.
Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 7A.
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.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Part III
Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters . . . . . . . . . .
Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . . . . . . . . . . . .
Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part IV
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2
3
7
7
18
20
21
21
22
28
29
43
43
43
44
44
44
44
45
46
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 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.
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. Southwest Bank is now the trustee of the trust. The principal office of the trust is located at
2911 Turtle Creek Blvd, Suite 850, Dallas, Texas 75219 (telephone number 855-588-7839).
On January 9, 2014, U.S. Trust, Bank of America Private Wealth Management, a division of Bank of America, N.A., gave
notice to unitholders that it would resign as trustee. At a special meeting of the trust’s unitholders held on May 23, 2014, the
unitholders of the trust voted to approve the proposal to appoint Southwest Bank as successor trustee of the trust effective
May 30, 2014.
The trust’s internet web site is www.hgt-hugoton.com. We make available free of charge, through our web site, our Annual
Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or
furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. These reports are accessible through our
internet web site as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities
and Exchange Commission.
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.
Costs exceeded revenues on properties underlying the Kansas net profits interests in November 2014 and September 2012,
on properties underlying the Wyoming net profits interests in July 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 were subject to 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.
2
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 78% of the net profits income received by the trust during 2014, as well as 81% of the estimated proved
reserves of the net profits interests at December 31, 2014 (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.
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
3
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 Kansas
net profits interests in November 2014 and September 2012, the Wyoming net profits interests in July 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 were subject to arbitration described more fully under “Item 3 — Legal
Proceedings.”
Proved reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in
reserve estimates or underlying assumptions could cause the quantities and net present value of the reserves to be
overstated.
Estimating proved oil and gas reserves is inherently uncertain. Petroleum engineers consider many factors and make
assumptions in estimating reserves and future net cash flows. Those factors and assumptions include historical production from
the area compared with production rates from similar producing areas, the effects of governmental regulation, assumptions
about future commodity prices, production expense and development costs, taxes and capital expenditures, the availability of
enhanced recovery techniques and relationships with landowners, working interest partners, pipeline companies and others.
Lower oil and gas prices generally cause lower estimates of proved reserves. Ultimately, actual production, revenues and
expenditures for the underlying properties will vary from estimates and those variances could be material. Because the trust owns
net profits interests, it does not own a specific percentage of the oil and gas reserves. Estimated proved reserves for the net
profits interests are based on estimates of reserves for the underlying properties and an allocation method that considers
estimated future net proceeds and oil and gas prices. Because trust reserve quantities are determined using an allocation
formula, increases or decreases in oil and gas prices can significantly affect estimated reserves of the net profits interests.
4
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.
Future royalty income may be subject to risks relating to the creditworthiness of third parties.
The trust does not lend money and has limited ability to borrow money, which the trustee believes limits the trust’s risk from
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.
Trust unitholders and the trustee have no influence over the operations on, or future development of, the underlying
properties.
Neither the trustee nor the trust unitholders can influence or control the operation or future development of the underlying
properties. The failure of an operator to conduct its operations or discharge its obligations in a proper manner could have an
adverse effect on the net proceeds payable to the trust. Although XTO Energy and other operators of the underlying properties
must adhere to the standard of a prudent operator, they are under no obligation to continue operating the properties. Neither the
trustee nor trust unitholders have the right to replace an operator.
The assets of the trust represent interests in depleting assets and, if XTO Energy or any other operators developing the
underlying properties do not perform additional successful development projects, the assets may 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 a return on capital as
opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits
available to the unitholders, which could reduce the market value of the units over time. Eventually, the properties underlying the
trust’s net profits interest will cease to produce in commercial quantities and the trust will, therefore, cease to receive any net
proceeds therefrom.
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.
5
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.
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
6
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.
Item 1B. Unresolved Staff Comments
As of December 31, 2014, 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, 2014 is approximately 13 years. This index is calculated using
7
total proved reserves and estimated 2015 production for the underlying properties. The projected 2015 production is from proved
developed producing reserves as of December 31, 2014. 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 82% natural gas and 18% 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 2014 development costs deducted for the underlying properties were $5.3 million, a decrease of 18% from the prior
year. XTO Energy has informed the trustee that total 2015 budgeted development costs for the underlying properties are between
$4 million and $6 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 2014, daily
sales volumes from the underlying properties in the Hugoton area averaged approximately 13,400 Mcf of gas and 28 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.
Within this area, XTO Energy did not drill any wells but did perform 21 workovers in 2014. XTO Energy has informed the
trustee that it does not plan to drill any new wells but may perform up to 15 workovers during 2015.
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.
Prior to May 1, 2014, XTO Energy delivered most of its Hugoton gas production to a gathering and processing system owned
by a subsidiary, Timberland Gathering & Processing Company, Inc. (“Timberland”). Most of the gas was sold under the terms of a
contract that was entered into in March 1996, predating the existence of the trust. Timberland purchased the gas from XTO
Energy at the wellhead, gathered and transported the gas to its plant, and treated and processed the gas at the plant. Timberland
had been taking all of the gas produced for over ten years. Timberland paid 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 was adjusted for the BTU content of the
gas. This marketing affiliate sold the residue to a pipeline at a price based on a monthly pipeline index less actual third party
fees.
XTO Energy has advised the trustee that Timberland has notified XTO Energy that it has permanently shut down the
processing portion of its facilities as of May 1, 2014 due to reliability issues. XTO Energy has advised the trustee that Timberland
believes that investments and repairs are not economically feasible; however, Timberland will continue to gather and compress
gas from the Hugoton area. Effective May 1, 2014, XTO Energy has a gas purchase contract in place with DCP Midstream, L.P. to
process all gas production from its wells attached to the Timberland Gathering System in Seward County, Kansas and in Texas
and Beaver Counties, Oklahoma. The system collects the majority of its throughput from underlying properties, which XTO Energy
8
has advised the trustee, in recent months, has been approximately 10,000 Mcf per day. XTO Energy receives 100% of the net
value for residue gas based upon a price per MMBtu of Panhandle Eastern Pipe Line Company index. XTO Energy receives 100% of
the net value for any recovered NGLs based upon the monthly average of the daily average prices per gallon under Mont Belvieu
Spot Gas Liquids Prices by Oil Price Information Service. XTO Energy also receives 100% of the net value of its allocated recovered
helium based upon the price published by the U. S. Bureau of Land Management for Crude Helium. Under this contract DCP is
entitled to charge a processing fee of $0.25 and a helium processing fee of $0.10 per Delivery Point MMBtu in addition to other
deductions such as for fuel and transportation. The fees are subject to annual adjustment based on changes in the Consumer
Price Index. The sales contract with DCP Midstream, L.P. is in force from May 1, 2014 until March 31, 2019, and from year to year
thereafter until canceled by either party upon 180 days written notice. XTO Energy has the contractual right to take in kind and
sell any of its allocated products by giving DCP appropriate notice as per the contract. Timberland, an affiliate of XTO Energy,
provides gathering from the wellhead to DCP’s gathering system for a fee of $0.75 per Mcf of gas delivered by XTO Energy.
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 21,700 Mcf of gas and
509 Bbls of oil in 2014.
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 2014. XTO Energy has informed the trustee
that it does not plan to drill any new wells but may perform up to 27 workovers in Major County during 2015.
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 5 workovers in 2014. XTO Energy has informed the trustee that it does not plan
to drill any new wells but may perform up to 5 workovers in Woodward County during 2015.
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 7 workovers in 2014. XTO Energy has informed the trustee that it does not plan to drill any new wells but
may perform up to 7 workovers within the Elk City field during 2015.
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.
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
9
producers in the area under various agreements, most of which were entered into in the 1960’s and 1970’s, and which include
life-of-production terms such that the contracts will continue until there is no further production from the underlying properties,
unless the production declines so that it is no longer economical to take the gas. The gathering subsidiary and the third-party
processor are required to take certain minimum volumes of the gas produced but have been taking all of the volumes produced for
over ten years. The gathering subsidiary gathers and transports the gas to a third-party processor, which processes the gas and
pays XTO Energy and other producers for at least 50% of the liquids processed based upon a weighted average sales price less
transportation charges, which price may vary in the event of inadequate markets. After the gas is processed, the gathering
subsidiary transports the gas via a residue pipeline to a connection with an interstate pipeline. The gathering subsidiary 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 2014, 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 $0.11 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 does not include a deduction for any marketing fees.
The price paid by the marketing affiliate includes a deduction for any transportation fees charged by the third party. Neither party
has a firm obligation to sell or purchase any specific minimum quantity of gas.
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 2014 sales volumes from the underlying properties in the Fontenelle field averaged 12,700 Mcf of natural gas and
21 Bbls of oil. XTO Energy did not drill any wells or perform any workovers in the Green River Basin in 2014. 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
2015. 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 2014, the fuel charge was 2.77% 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 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
10
$0.19 per MMBtu and is adjusted annually. The amount of gas that the gatherer is required to gather is limited to certain
maximum volumes, and the gatherer may be able to cease taking volumes if it has valid unaddressed concerns regarding the
creditworthiness of XTO Energy. Alternatively, the gas may be sold under a contract where XTO Energy directly sells the gas to a
third party on the lease at an adjusted index price, which price varies upon market conditions. The contract continues on a month-
to-month basis, and the buyer is obligated to make a good faith effort to purchase a minimum 90% of the gas nominated by
buyer for purchase. Condensate is sold to an independent third party at market rates on a month-to-month basis. The purchaser
accepts all condensate delivered at the lease, but either party may suspend performance of the contract if there are credit issues
with the other party.
Producing Acreage, Drilling and Well Counts
For the following data, “gross” refers to the total wells or acres on the underlying properties in which XTO Energy owns a
working interest and “net” refers to gross wells or acres multiplied by the percentage working 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, 2014. Undeveloped acreage is not significant.
Hugoton Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Anadarko Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Green River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
209,302
170,092
37,711
194,785
132,753
28,426
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
417,105
355,964
Gross
Net
The following is a summary of the producing wells on the underlying properties as of December 31, 2014:
Operated
Wells
Nonoperated
Wells
Total
Gross
Net
Gross
Net
Gross
Net
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,163.0
42.0
1,053.1
38.9
263.0
4.0
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,205.0
1,092.0
267.0
59.9
0.9
60.8
1,426.0
46.0
1,113.0
39.8
1,472.0
1,152.8
The following is a summary of the number of wells drilled on the underlying properties during the years indicated. During
2014, 2013 and 2012 no exploratory wells were drilled on the underlying properties. There were no wells in process of drilling at
December 31, 2014.
0.6
Completed gas wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — 1
Completed oil wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — —
Dry wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — —
Total(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — 1
0.6
2014
2013
2012
Gross
Net
Gross
Net
Gross
Net
(a)
Included in totals are zero wells in 2014, 2013 and 2012, 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, 2014:
Underlying Properties
Proved Reserves(a)
Oil
Gas
(Bbls)
(Mcf)
Net Profits Interests
Proved Reserves(a)(b)
Oil
Gas
(Bbls)
(Mcf)
Future Net Cash Flows
from Proved Reserves(a)(c)
Discounted
Undiscounted
(in thousands)
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
142,470
51,294
16,424
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
210,188
2,102
60
57
2,219
56,031
13,796
6,336
76,163
818
16
22
856
$303,558
49,402
26,430
$156,054
26,093
15,131
$379,390
$197,278
(a)
(b)
(c)
Based on 12-month average oil price of $92.70 per Bbl and $4.35 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 decreased 4% from year-end
2013 to 2014, primarily because of 2014 production and downward revisions of prior reserve estimates, partially offset by a
11% increase in 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.
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
Gas
(Bbls)
(Mcf)
(in thousands)
Proved developed reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved undeveloped reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
177,389
32,799
Total proved reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
210,188
1,847
372
2,219
68,335
7,828
76,163
767
89
856
Approximately 84% 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, 2014, 2013, 2012 and 2011. 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
12
properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests.
Numerous uncertainties are inherent in estimating reserve volumes and values, and such estimates are subject to change as
additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be
substantially different from the original estimates.
Reserve quantities and revenues for the net profits interests were estimated from projections of reserves and revenues
attributable to the 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 a specific 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:
Production
Underlying Properties
Gas – Sales (Mcf)
Average per day (Mcf)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average per day (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Profits Interests
Gas – Sales (Mcf)
Average per day (Mcf)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average per day (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014
2013
2012
17,426,780
47,745
203,667
558
18,712,650
51,268
216,634
594
20,370,975
55,658
228,656
625
8,004,435
21,930
110,515
303
7,770,148
21,288
99,363
272
5,991,964
16,371
76,049
208
Average Sales Price
Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 4.60
$95.35
$ 4.03
$95.25
$ 3.28
$91.30
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)
2013
2012
2014
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,531,314
11,255,819
4,639,647
1,606,436
12,041,983
5,064,231
1,805,789
12,992,317
5,572,869
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17,426,780
18,712,650
20,370,975
Conveyance
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Underlying Oil Production (Bbls)
2013
2012
2014
7,023
188,911
7,733
203,667
9,427
196,345
10,862
216,634
14,090
204,022
10,544
228,656
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Pricing and Sales Information
XTO Energy sells a portion of its natural gas production directly to third parties, and the rest is sold to a subsidiary of XTO
Energy based on a weighted average sales price. The weighted average sales price received from the subsidiary is based upon
sales to third parties for the best available price. Oil production is generally marketed at the wellhead to third parties at the best
available price. XTO Energy arranges for some of its natural gas to be processed by unaffiliated third parties and markets the
natural gas liquids. Most of the natural gas attributable to the underlying properties is marketed under contracts existing at trust
inception. Contracts covering production from the Ringwood area of the Major County area are generally for the life of the lease.
The contract with an unaffiliated third party for the majority of production from the Hugoton area was extended through 2019. 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.
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There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and
climate change. Several states have adopted climate change legislation and regulations, and various other regulatory bodies
have announced their intent to regulate GHG emissions or adopt climate change regulations. As these regulations are under
development, XTO Energy is unable to predict the total impact of the potential regulations upon the operators of the underlying
properties, and it is possible that operators of the underlying properties could face increases in operating costs in order to comply
with climate change or GHG emissions legislation, which costs could reduce net proceeds payable to the trust and trust
distributions.
State Regulation
The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining
drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and
gas resources. The rates of production may be regulated and the maximum daily production allowables from both oil and gas
wells may be established on a market demand or conservation basis, or both.
Federal Income Taxes
For federal income tax purposes, the trust constitutes a fixed investment trust that is taxed as a grantor trust. A grantor
trust is not subject to tax at the trust level. The unitholders are considered to own the trust’s income and principal as though no
trust were in existence. The income of the trust is deemed to have been received or accrued by each unitholder at the time such
income is received or accrued by the trust and not when distributed by the trust.
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 2014, the
trust incurred administration expenses and earned interest income on funds held for distribution and for the cash reserve
maintained for the payment of contingent and future obligations of the trust.
The net profits interests constitute “economic interests” in oil and gas properties for federal tax purposes. Each unitholder
is entitled to amortize the cost of the units through cost depletion over the life of the net profits interests or, if greater, through
percentage depletion equal to 15 percent of gross income. Unlike cost depletion, percentage depletion is not limited to a
unitholder’s depletable tax basis in the units. Rather, a unitholder is entitled to a percentage depletion deduction as long as the
applicable underlying properties generate gross income. Unitholders may compute both percentage depletion and cost depletion
from each property and claim the larger amount as a deduction on their income tax returns.
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
15
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 a
unitholder’s allocable share of the trust’s interest and royalty income plus the gain recognized from a sale of trust units. In the
case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or
(ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such
individual’s federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (i) undistributed
net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket
applicable to an estate or trust begins.
The unitholders have income in 2014 as a result of the trust receiving the amounts required to be paid under the arbitration
award relating to XTO Energy’s treatment of the Fankhouser settlement (discussed in Item 3 – Legal Proceedings). A portion of the
arbitration award represents the reimbursement of amounts withheld from the September and October 2012 trust distributions,
which is treated as additional gross royalty income reported by and taxable to the unitholders, when received or accrued by the
trust, depending on the unitholder’s method of accounting. In addition, a portion of the arbitration award represents the
reimbursement of attorney’s fees and other administrative fees and expenses, which is reflected through a decrease in the trust’s
administrative expenses and thus the unitholder’s deductions in determining the net royalty income from the trust. The interest
portion of the arbitration award is taxable interest income to unitholders, when received or accrued by the trust, depending on the
unitholder’s method of accounting. “See Item 3 – Legal Proceedings for additional information.”
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 2014, 2013 and 2012, 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.
Pursuant to the Foreign Account Tax Compliance Act (commonly referred to as “FATCA”), distributions from the trust to
“foreign financial institutions” and certain other “non-financial foreign entities” may be subject to U.S. withholding taxes.
Specifically, certain “withholdable payments” (including certain royalties, interest and other gains or income from U.S. sources)
made to a foreign financial institution or non-financial foreign entity will generally be subject to the withholding tax unless the
foreign financial institution or non-financial foreign entity complies with certain information reporting, withholding, identification,
certification and related requirements imposed by FATCA. Foreign financial institutions located in jurisdictions that have an
intergovernmental agreement with the United States governing FATCA may be subject to different rules.
The Treasury Department recently issued guidance providing that the FATCA withholding rules described above generally will
apply to qualifying payments made after June 30, 2014. Foreign unitholders are encouraged to consult their own tax advisors
regarding the possible implications of these withholding provisions on their investment in trust units.
Some trust units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes
custodians, nominees, certain joint owners, and brokers holding an interest for a customer in street name, collectively referred to
herein as “middlemen”). Therefore, the trustee considers the trust to be a non-mortgage widely held fixed investment trust
(“WHFIT”) for U.S. federal income tax purposes. Southwest Bank, EIN: 75-1105980, Post Office Box 962020, Fort Worth, Texas,
76162-2020, telephone number 1-855-588-7839, email address trustee@hgt-hugoton.com, is the representative of the trust that
16
will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting
requirements of the trust as a WHFIT. Tax information is also posted by the trustee at www.hgt-hugoton.com. Notwithstanding the
foregoing, the middlemen holding trust units on behalf of unitholders, and not the trustee of the trust, are solely responsible for
complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such trust units,
including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose trust units are held by
middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with
respect to the trust units.
Unitholders should consult their tax advisors regarding trust tax compliance matters.
State Income Taxes
All revenues from the trust are from sources within Kansas, Oklahoma or Wyoming. Kansas and Oklahoma each impose a
state income tax, which is potentially applicable to income from the net profits interests located in each of those states. Because
it distributes all of its net income to unitholders, the trust 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, Kansas allows individuals to deduct
certain amounts, including net income from royalties reported on Schedule E of their 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 a
corporate income tax that may apply to unitholders organized as corporations (subject to certain exceptions for S corporations and
limited liability companies, depending on their treatment for federal tax purposes).
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.
17
Item 3. Legal Proceedings
XTO Energy settled the Fankhouser v. XTO Energy, Inc. royalty class action lawsuit for $37 million. The settlement was given
final approval by the court on October 10, 2012. XTO Energy advised the trustee that $1.4 million of the settlement was
attributable to Kansas claims which predated the trust. The settlement also included a new royalty calculation for future royalty
payments.
XTO Energy and the trustee arbitrated the issue of whether the Fankhouser settlement could be charged to the trust net
proceeds ($28.5 million; $23.4 million and $5.1 million affecting the net proceeds from Oklahoma and Kansas, respectively, in
addition to a reduction in the net profits going forward). The three panel tribunal issued a decision on April 21, 2014. Based on
that ruling, XTO Energy is prohibited from charging any portion of the Fankhouser settlement (including the new royalty
calculation for future royalty payments) to the trust, now or in the future. Additionally, XTO Energy had to reimburse $4,386,396
which represents amounts withheld from the September and October 2012 distributions and $1,985,438 which represents
attorney fees, arbitration expenses and interest.
The trust filed Southwest Bank, as Successor Trustee to Bank of America, N.A., as Trustee for the Hugoton Royalty Trust
v. XTO Energy, Inc., no. 017-274777-14 in the 17th state district court of Tarrant County, Texas, seeking judicial confirmation of
the April 21, 2014 arbitration award. The arbitration award was entered into as a final judgment on December 12, 2014.
In September 2008, a royalty 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. The case was removed 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; later reduced to Kansas. 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 its pleadings, the plaintiff has alleged damages in excess of $42.5 million.
In December 2010, a royalty class action lawsuit was filed against XTO Energy styled Chieftain Royalty Company v. XTO
Energy Inc. in Coal County District Court, Oklahoma. XTO Energy removed the case to federal court in the Eastern District of
Oklahoma. The plaintiffs allege that XTO Energy wrongfully deducted fees from royalty payments on Oklahoma wells, failed to
make diligent efforts to secure the best terms available for the sale of gas and its constituents, and demand an accounting to
determine whether they have been fully and fairly paid gas royalty interests. The case was certified as a class action in April
2012. 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. In light of the arbitration tribunal’s decision on the treatment of the Fankhouser
settlement, to the extent that the claims in Chieftain or Roderick are similar to those in Fankhouser, the trustee would likely object
to such claimed reductions. 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
18
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 through the American Arbitration Association under the
terms of the Indenture creating the trust.
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 alleged that XTO Energy failed to properly pay and account to the trust under the terms of the net
overriding royalty conveyances on certain Kansas and Oklahoma properties and that Bank of America, N.A., as the previous
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 plaintiff sought unspecified amounts for actual/compensatory damages, punitive damages, disgorgement
and injunctive relief. Sandra Goebel, another unitholder of the trust, filed a Motion to Intervene in Lamb’s lawsuit and to stay the
action in favor of her lawsuit pending in the Dallas County District Court (see discussion below) or, in the alternative, for the court
to appoint her attorneys lead counsel in Lamb’s lawsuit. On September 5, 2014, Goebel withdrew her Motion to Intervene. That
same day, Lamb filed a Motion to Voluntarily Dismiss his claims. On September 29, 2014, the Lamb case was dismissed without
prejudice to refile in state court. Lamb’s counsel has been added as counsel of record for Goebel.
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 (“AAA”). 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 did 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. (the previous
trustee) 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. Bank of America, N.A. 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 Bank of
America, N.A. 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 and
Processing Company, Inc. and Bank of America, N.A. in Dallas County District Court. The allegations are the same as those
contained in the previous arbitration demand. Defendants answered with general denials and additionally filed pleas to the
jurisdiction, special exceptions, and a plea in abatement challenging, among other things, Goebel’s putative authority to bring
claims on behalf of the trust over the trustee’s objection. The Defendants also filed a joint motion to stay the Goebel case in favor
of the first filed Lamb case discussed above. The court denied Defendants’ pleas to the jurisdiction and special exceptions,
although it did not rule on the plea in abatement. Simultaneously, the judge conditionally stayed the case pending a ruling on
Goebel’s Motion to Intervene in the Lamb case. On September 5, 2014, however, Goebel withdrew her Motion to Intervene. That
same day, Lamb filed a Motion to Voluntarily Dismiss his federal district court lawsuit (see discussion above). Goebel filed a
motion to lift the stay in the state district court; while XTO Energy, Timberland and Bank of America (individually and now as
former trustee) filed a motion to stay the case pending a mandamus appeal of the district court’s denial of their pleas to the
jurisdiction and special exceptions. On October 30, 2014, the district court granted Plaintiff’s motion to lift stay. On October 31,
2014, the district court denied Defendants’ motion to stay pending mandamus. On November 7, 2014, the Defendants filed their
petition for writ of mandamus with the Dallas Court of Appeals. Defendants also filed a motion seeking a stay from the court of
appeals, along with the petition for writ of mandamus. On November 13, 2014, the court of appeals granted Defendants’ motion
and stayed the lawsuit, including all associated discovery, until the court opines on the petition for writ of mandamus. Goebel
filed a response to the petition for the writ of mandamus on December 16, 2014 and the Defendants replied on January 13, 2015.
Accordingly, the petition has been fully briefed and is awaiting a decision from the court of appeals. Southwest Bank, the current
trustee, has not yet been named a party in the case. The trustee will vigorously defend any claims that may be asserted against it.
19
XTO Energy has informed the trustee that it believes that XTO Energy and Timberland have strong defenses to this lawsuit and
intend to vigorously defend their positions. Bank of America has informed the trustee that it 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 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 lawsuit.
As a result, the trustee reserved an additional $1.6 million from trust distributions for the Goebel litigation, beginning with the
September 2013 distribution. The September 2013 through December 2013 distributions each reflected a deduction of $400,000
in connection with such reserve. Additionally, the trustee previously reserved an additional $1.6 million from trust distributions for
the Lamb litigation but that is now a part of the reserve for the Goebel lawsuit. The January 2014 through April 2014 distributions
each reflected a deduction of $400,000 in connection with such reserve. As the Goebel lawsuit progresses, the trustee may need to
revise the reserve.
Certain of the underlying properties are involved in various other lawsuits and governmental proceedings arising in the
ordinary course of business. XTO Energy has advised the trustee that it does not believe that the ultimate resolution of these
claims will have a material effect on the financial position or liquidity of the trust, but may have an effect on annual distributable
income.
Item 4. Mine Safety Disclosures
Not Applicable.
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 2014 and 2013:
Quarter
Sales Price
High
Low
Distributions
per Unit
2014
First
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 9.11
12.04
11.11
10.25
$7.48
7.62
8.93
7.51
2013
First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 9.97
9.98
9.45
8.16
$7.30
8.12
7.43
6.98
$0.191258
0.446171
0.253546
0.204267
$1.095242
$0.195453
0.230142
0.251364
0.185723
$0.862682
At December 31, 2014, there were 40,000,000 units outstanding and approximately 706 unitholders of record; 37,908,768 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
2014
2013
Year Ended December 31
2012
2011
2010
Net Profits Income . . . . . . . . . . . . . . . . . . . . . . . . . $44,446,473 $ 37,333,595 $ 25,132,038 $ 56,565,368 $ 62,883,206
62,028,000
Distributable Income . . . . . . . . . . . . . . . . . . . . . . . .
1.550700
. . . . . . . . . . . . . . . . .
Distributable Income per Unit
Distributions per Unit . . . . . . . . . . . . . . . . . . . . . . .
1.550700
129,222,886
Total Assets at Year-End . . . . . . . . . . . . . . . . . . . . .
23,272,920
0.581823
0.581823
112,956,689
34,507,280
0.862682
0.862682
102,501,095
55,764,960
1.394124
1.394124
118,965,716
43,809,680
1.095242
1.095242
93,920,959
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)
2013
2012
2014
Three Months Ended December 31(a)
2014
2013
Sales Volumes
Gas (Mcf)(b)
Underlying properties . . . . . . . . . . . . . . . .
Average per day . . . . . . . . . . . . . . . . . .
Net profits interests . . . . . . . . . . . . . . . . .
17,426,780
47,745
8,004,435
18,712,650
51,268
7,770,148
20,370,975
55,658
5,991,964
4,395,822
47,781
1,703,649
Oil (Bbls)(b)
Underlying properties . . . . . . . . . . . . . . . .
Average per day . . . . . . . . . . . . . . . . . .
Net profits interests . . . . . . . . . . . . . . . . .
203,667
558
110,515
216,634
594
99,363
228,656
625
76,049
48,226
524
21,722
4,695,128
51,034
1,870,572
55,833
607
25,161
Average Sales Prices
Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . .
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
4.60
95.35
$
$
4.03
95.25
$
$
3.28
91.30
$
$
4.13
89.45
$
$
3.97
102.44
Revenues
Gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . .
$80,236,274
19,419,502
$75,469,935
20,635,040
$ 66,738,058
20,875,782
$18,159,388
4,313,582
$18,657,261
5,719,538
Total Revenues . . . . . . . . . . . . . . . . . . . .
99,655,776
96,104,975
87,613,840
22,472,970
24,376,799
Costs
Taxes, transportation and other
. . . . . . . . . .
Production expense . . . . . . . . . . . . . . . . . . .
Development costs(c)
. . . . . . . . . . . . . . . . . .
Overhead . . . . . . . . . . . . . . . . . . . . . . . . . . .
Legal Expense(d) . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . .
Excess costs(d)
10,523,008
21,683,844
5,300,000
12,156,711
(5,482,995)
(82,883)
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)
2,458,968
5,598,020
1,000,000
3,064,373
—
(82,883)
2,609,372
5,402,343
1,800,000
3,029,280
—
—
Total Costs . . . . . . . . . . . . . . . . . . . . . . .
44,097,685
50,626,411
56,198,792
12,038,478
12,840,995
Other Proceeds
Property Sales(e) . . . . . . . . . . . . . . . . . . . . . .
Net Proceeds . . . . . . . . . . . . . . . . . . . . . . . . .
Net Profits Percentage . . . . . . . . . . . . . . . . . .
$
— $ 1,188,430
46,666,994
55,558,091
—
31,415,048
—
10,434,492
—
11,535,804
80%
80%
80%
80%
80%
Net Profits Income . . . . . . . . . . . . . . . . . . . . .
$44,446,473
$37,333,595
$ 25,132,038
$ 8,347,594
$ 9,228,643
(a)
(b)
(c)
(d)
(e)
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.
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.
22
Results of Operations
Years Ended December 31, 2014, 2013 and 2012
Net profits income for 2014 was $44,446,473, as compared with $37,333,595 for 2013 and $25,132,038 for 2012. The 19%
increase in net profits income from 2013 to 2014 is primarily the result of higher gas prices ($8.5 million) and the May 2014
arbitration reimbursement ($4.4 million), partially offset by decreased oil and gas production ($5.7 million). 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). Approximately 78% in 2014, 76% in 2013 and
74% in 2012 of net profits income was derived from natural gas sales.
Trust administration expense was $1,153,924 in 2014 as compared to $2,827,015 in 2013 and $1,859,626 in 2012.
Included in 2014 administration expense is $1,600,000 which the trustee reserved for legal expenses regarding the Lamb lawsuit
Included in 2013 administration expense is
but partially offset by $1,470,618 related to the arbitration reimbursement.
$1,600,000 which the trustee has reserved for legal expenses regarding the Goebel lawsuit and included in 2012 was $900,000
which the trustee reserved for legal expenses regarding the arbitration relating to the Fankhouser class action settlement. Interest
income was $517,131 in 2014, $700 in 2013 and $508 in 2012. Interest income for 2014 included $514,820 related to the
arbitration reimbursement. Changes in interest income are attributable to fluctuations in net profits income and interest rates.
Distributable income was $43,809,680 or $1.095242 per unit in 2014, $34,507,280 or $0.862682 per unit in 2013 and
$23,272,920 or $0.581823 per unit in 2012.
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 2013 to 2014, underlying gas sales volumes decreased 7% and underlying oil sales volumes decreased 6% primarily
due to natural production decline. 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.
The estimated rate of natural production decline on the underlying oil and gas properties is approximately 6% to 8% a year.
Prices
Gas.
The 2014 average gas price was $4.60 per Mcf, a 14% increase from the 2013 average gas price of $4.03 per Mcf,
which was a 23% increase from the 2012 average gas price of $3.28 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 2014 through
January 2015 was $3.73 per MMBtu. At February 18, 2015, the average NYMEX gas price for the following 12 months was
$3.05 per MMBtu.
Oil.
The average oil price for 2014 was $95.35 per Bbl, relatively flat from the average oil price for 2013 of $95.25 per Bbl,
which was 4% higher than the average oil price for 2012 of $91.30 per Bbl. Oil prices are expected to remain volatile. The average
NYMEX price for November 2014 through January 2015 was $60.89 per Bbl. At February 18, 2015, the average NYMEX oil price for
the following 12 months was $57.14 per Bbl.
23
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.
Taxes, transportation and other.
Taxes, transportation and other generally fluctuates with changes in total revenues.
Taxes, transportation and other decreased 2% from 2013 to 2014 primarily because of decreased property taxes related to lower
valuations and decreased oil production taxes related to lower oil revenues, partially offset by increased gas production taxes
related to higher gas 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.
Production expense.
Production expense remained relatively flat from 2013 to 2014 primarily because increased repairs
and maintenance, labor and field costs were offset by decreased compressor rental and chemical costs. 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.
Development costs.
Development costs deducted were $5.3 million in 2014, $6.5 million in 2013 and $6.0 million in 2012.
In 2014, actual development costs were $4.6 million. At December 31, 2014, cumulative budgeted costs deducted exceeded
cumulative actual costs by approximately $1.2 million. The monthly development cost deduction was $500,000 from the January
2012 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 it was maintained at this level
through the February 2014 distribution. Due to lower than anticipated actual costs as a result of the timing of cash expenditures,
the development cost deduction was decreased to $500,000 beginning with the March 2014 distribution and to $400,000
beginning with the June 2014 distribution and was maintained at that level through the November 2014 distribution. Due to lower
than anticipated actual costs as a result of reduced activity and revisions to the 2014 development budget, the development cost
deduction was decreased to $200,000 beginning with the December 2014 distribution. 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. For further information on 2015 budgeted development costs, see Properties, under Item 2.
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 that decreased underlying gas volumes related to a prior period adjustment caused
costs to exceed revenues by $123,577 ($98,862 net to the trust) on properties underlying the Kansas net profits interests in
November 2014. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO advised the
trustee that increased gas production led to the partial recovery of excess costs, plus accrued interest, of $40,694 ($32,555 net to
the trust) in December 2014. Remaining excess costs totaled $82,883 ($66,306 net to the trust) for the period ended
December 31, 2014.
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. The excess costs claimed underlying the Kansas and Oklahoma net profits interests above were the subject of an
arbitration ruling issued in April 2014. As a result of the arbitration ruling, XTO Energy was prohibited from charging any portion
of the Fankhouser settlement to the trust. Therefore, the May 2014 distribution included a refund for the amounts withheld from
the September and October 2012 distributions. For additional information see Note 8 to Financial Statements under Item 8,
Financial Statements and Supplementary Data.
24
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.
Legal Expense.
legal expense for 2014 included reimbursement of
$5,482,995 ($4,386,396 net to the trust) for the amounts withheld from trust proceeds in September and October 2012. For
additional information see Note 8 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
the arbitration ruling,
As a result of
Fourth Quarter 2014 and 2013
During fourth quarter 2014 the trust received net profits income totaling $8,347,594 compared with fourth quarter 2013 net
profits income of $9,228,643. This 10% decrease in net profits income was primarily due to decreased oil and gas production
($1.5 million) and lower oil prices ($0.5 million), partially offset by lower development costs ($0.6 million) and higher gas prices
($0.6 million).
Administration expense was $177,007 and interest income was $93, resulting in fourth quarter 2014 distributable income of
$8,170,680 or $0.204267 per unit. Distributable income for fourth quarter 2013 was $7,428,920 or $0.185723 per unit.
Distributions to unitholders for the quarter ended December 31, 2014 were:
Record Date
Payment Date
October 31, 2014
November 28, 2014
December 31, 2014
November 17, 2014
December 12, 2014
January 15, 2015
Per Unit
$0.074840
0.065919
0.063508
$0.204267
Volumes
Fourth quarter underlying gas sales volumes decreased 6% and underlying oil sales volumes decreased 14% from 2013 to
2014. Gas sales volumes decreased primarily due to natural production decline. Oil sales volumes decreased primarily due to
natural production decline and the timing of cash receipts.
Prices
The average fourth quarter 2014 gas price was $4.13 per Mcf, or 4% higher than the fourth quarter 2013 average price of
$3.97 per Mcf. The average fourth quarter 2014 oil price was $89.45 per Bbl, or 13% lower than the fourth quarter 2013 average
price of $102.44 per Bbl. For further information about product prices, see “Years Ended December 31, 2014, 2013 and 2012 –
Prices” above.
Costs
Taxes, transportation and other.
Taxes, transportation and other decreased 6% from fourth quarter 2013 to 2014 primarily
because of decreased oil production taxes related to lower oil revenues and decreased property taxes related to decreased
valuations.
Production expense.
Fourth quarter production expense increased 4% from 2013 to 2014 primarily because of increased
labor and repairs and maintenance costs, partially offset by decreased compressor rental costs.
Development costs.
Development costs, which were deducted based on budgeted development costs, decreased 44% from
fourth quarter 2013 to 2014. For further information about development costs, see “Years Ended December 31, 2014, 2013 and
2012 — Development Costs” above.
25
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 that decreased underlying gas volumes related to a prior period adjustment caused
costs to exceed revenues by $123,577 ($98,862 net to the trust) on properties underlying the Kansas net profits interests in
November 2014. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO advised the
trustee that increased gas production led to the partial recovery of excess costs, plus accrued interest, of $40,694 ($32,555 net to
the trust) in December 2014. Remaining excess costs totaled $82,883 ($66,306 net to the trust) for the period ended
December 31, 2014.
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.
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.
26
Contractual Obligations
As shown below, the trust had no obligations and commitments to make future contractual payments as of December 31,
2014, other than the December distribution payable to unitholders in January 2015, 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 . . . . . . . . . . . . . . . . . . . . . . .
$2,540,320
$2,540,320
$—
$—
$—
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, 2014, the
monthly overhead charge, based on the number of operated wells, was approximately $1,022,000 ($817,600 net to the trust) and
is subject to annual adjustment based on an oil and gas industry index.
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. For further information regarding natural gas sales from the underlying properties to affiliates of XTO
Energy, see Significant Properties, under Item 2, Properties and Note 7 to Financial Statements under Item 8, Financial
Statements and Supplementary Data. Total gas sales from the underlying properties to XTO Energy’s wholly owned subsidiaries
were $30.4 million for 2014, or 38% of total gas sales, $29.0 million for 2013, or 38% of total gas sales and $22.3 million for
2012, or 34% of total gas sales.
On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.
Critical Accounting Policies
The financial statements of the trust are significantly affected by its basis of accounting and estimates related to its oil and
gas properties and proved reserves, as summarized below.
Basis of Accounting
The trust’s financial statements are prepared on a modified cash basis, which is a comprehensive basis of accounting other
than U.S. 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.
27
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.
including consideration of other factors, could have a significant impact on the
Changes in any of these assumptions,
standardized measure. Accordingly, the standardized measure does not represent XTO Energy’s or the trustee’s estimated current
market value of proved reserves.
Forward-Looking Statements
Certain information included in this annual report and other materials filed, or to be filed, by the trust with the Securities
and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by
XTO Energy or the trustee) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act
of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the trust, operations of the
underlying properties and the oil and gas industry. Such forward-looking statements may concern, among other things, reserve-
to-production ratios, future production, development activities, 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
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statements of Assets, Liabilities and Trust Corpus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statements of Distributable Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statements of Changes in Trust Corpus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
30
31
31
31
32
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
Report of Independent Registered Public Accounting Firm
To the Unitholders of Hugoton Royalty Trust and
Southwest Bank, Trustee
We have audited the accompanying statements of assets, liabilities and trust corpus of Hugoton Royalty Trust (the “Trust”)
as of December 31, 2014 and 2013, and the related statements of distributable income and changes in trust corpus for each of
the three years in the period ended December 31, 2014. We also have audited the Trust’s internal control over financial reporting
as of December 31, 2014, based on criteria established in Internal Control — Integrated Framework (2013) 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, 2014 and 2013, and the distributable income and changes in trust corpus for each of
the three years in the period ended December 31, 2014, 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, 2014, based on
criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 6, 2015
30
HUGOTON ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
December 31
2014
2013
Assets
Cash and short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net profits interests in oil and gas properties – net
$ 4,324,131
$
3,646,537
(Notes 1 and 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
89,596,828
98,854,558
$93,920,959
$102,501,095
Liabilities and Trust Corpus
Distribution payable to unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Legal reserve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding) . . . . . . . .
$ 2,540,320
1,783,811
89,596,828
$
2,207,160
1,439,377
98,854,558
$93,920,959
$102,501,095
STATEMENTS OF DISTRIBUTABLE INCOME
Year Ended December 31
2013
2014
2012
Net profits income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest income(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$44,446,473
517,131
$37,333,595
700
$25,132,038
508
Total income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Administration expense(a)
44,963,604
1,153,924
37,334,295
2,827,015
25,132,546
1,859,626
Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$43,809,680
$34,507,280
$23,272,920
Distributable income per unit (40,000,000 units)
. . . . . . . . . . . . . . . . . . . . .
$ 1.095242
$ 0.862682
$ 0.581823
(a)
Interest income and administration expense for the period ended December 31, 2014, includes a refund of $514,820 and
$1,470,618, respectively, related to the arbitration reimbursement. For further information see Note 8 of the accompanying
notes to financial statements.
STATEMENTS OF CHANGES IN TRUST CORPUS
Year Ended December 31
2013
2012
2014
Trust corpus, beginning of year
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of net profits interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions declared . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 98,854,558
(9,257,730)
43,809,680
(43,809,680)
$109,892,977
(11,038,419)
34,507,280
(34,507,280)
$115,367,996
(5,475,019)
23,272,920
(23,272,920)
Trust corpus, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 89,596,828
$ 98,854,558
$109,892,977
See accompanying notes to financial statements.
31
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).
Southwest Bank is the trustee for the trust. 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.
U.S. Trust, Bank of America Private Wealth Management, a division of Bank of America, N.A., as trustee of the Hugoton
Royalty Trust, announced that at the special meeting of the trust’s unitholders held on May 23, 2014, the unitholders of the trust
voted to approve the proposal to appoint Southwest Bank as successor trustee of the trust effective May 30, 2014. References to
the trustee for periods prior to May 30, 2014 shall mean Bank of America, N.A., and for periods on or after May 30, 2014 shall
mean Southwest Bank.
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
32
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
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, 2014.
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 $157,470,123 as of December 31,
2014 and $148,212,393 as of December 31, 2013.
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).
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
XTO advised the trustee that decreased underlying gas volumes related to a prior period adjustment caused costs to exceed
revenues by $123,577 ($98,862 net to the trust) on properties underlying the Kansas net profits interests in November 2014.
However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO advised the trustee that increased
33
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
gas production led to the partial recovery of excess costs, plus accrued interest, of $40,694 ($32,555 net to the trust) in December
2014. Remaining excess costs totaled $82,883 ($66,306 net to the trust) for the period ended December 31, 2014.
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. The excess costs claimed underlying the Kansas and Oklahoma net profits interests above were the subject of an
arbitration ruling issued in April 2014. As a result of the arbitration ruling, XTO Energy was prohibited from charging any portion
of the Fankhouser settlement to the trust. Therefore, the May 2014 distribution included a refund for the amounts withheld from
the September and October 2012 distributions. For additional information see Note 8.
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.
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
2013
2014
2012
Cumulative actual costs under (over) the amount deducted –
beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actual costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Budgeted costs deducted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
588,742
(4,645,744)
5,300,000
$ (301,922)
(5,609,336)
6,500,000
$ 2,396,920
(8,698,842)
6,000,000
Cumulative actual costs under (over) the amount deducted – end of
period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,242,998
$
588,742
$ (301,922)
The monthly development cost deduction was $500,000 from the January 2012 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 it was maintained at this level through the February 2014 distribution. Due to
lower than anticipated actual costs as a result of the timing of cash expenditures, the development cost deduction was decreased
to $500,000 beginning with the March 2014 distribution and to $400,000 beginning with the June 2014 distribution and was
maintained at that level through the November 2014 distribution. Due to lower than anticipated actual costs as a result of
reduced activity and revisions to the 2014 development budget, the development cost deduction was decreased to $200,000
beginning with the December 2014 distribution. 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. For further information on 2015
budgeted development costs, see Properties, under Item 2.
34
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
6. Income Taxes
For federal income tax purposes, the trust constitutes a fixed investment trust that is taxed as a grantor trust. A grantor
trust is not subject to tax at the trust level. Accordingly, no provision for income taxes has been made in the financial statements.
The unitholders are considered to own the trust’s income and principal as though no trust were in existence. The income of the
trust is deemed to have been received or accrued by each unitholder at the time such income is received or accrued by the trust
and not when distributed by the trust.
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, 2014,
the overhead charge was approximately $1,022,000 ($817,600 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. Prior to May 1, 2014, most of the production from the Hugoton area was sold under a contract to
Timberland Gathering & Processing Company, Inc. (“TGPC”) based on the index price. Effective May 1, 2014, XTO Energy has a
gas purchase contract in place with DCP Midstream, L.P. TGPC will provide gathering from the wellhead to DCP’s gathering
system for approximately $0.75 per Mcf. 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 $30.4 million for 2014, or
38% of total gas sales, $29.0 million for 2013, or 38% of total gas sales and, $22.3 million for 2012, or 34% of total gas sales.
On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.
8. Contingencies
Litigation
XTO Energy settled the Fankhouser v. XTO Energy, Inc. royalty class action lawsuit for $37 million. The settlement was given
final approval by the court on October 10, 2012. XTO Energy advised the trustee that $1.4 million of the settlement was
attributable to Kansas claims which predated the trust. The settlement also included a new royalty calculation for future royalty
payments.
XTO Energy and the trustee arbitrated the issue of whether the Fankhouser settlement could be charged to the trust net
proceeds ($28.5 million; $23.4 million and $5.1 million affecting the net proceeds from Oklahoma and Kansas, respectively, in
35
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
addition to a reduction in the net profits going forward). The three panel tribunal issued a decision on April 21, 2014. Based on
that ruling, XTO Energy is prohibited from charging any portion of the Fankhouser settlement (including the new royalty
calculation for future royalty payments) to the trust, now or in the future. Additionally, XTO Energy had to reimburse $4,386,396
which represents amounts withheld from the September and October 2012 distributions and $1,985,438 which represents
attorney fees, arbitration expenses and interest.
The trust filed Southwest Bank, as Successor Trustee to Bank of America, N.A., as Trustee for the Hugoton Royalty Trust
v. XTO Energy, Inc., no. 017-274777-14 in the 17th state district court of Tarrant County, Texas, seeking judicial confirmation of
the April 21, 2014 arbitration award. The arbitration award was entered into as a final judgment on December 12, 2014.
In September 2008, a royalty 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. The case was removed 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; later reduced to Kansas. 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 its pleadings, the plaintiff has alleged damages in excess of $42.5 million.
In December 2010, a royalty class action lawsuit was filed against XTO Energy styled Chieftain Royalty Company v. XTO
Energy Inc. in Coal County District Court, Oklahoma. XTO Energy removed the case to federal court in the Eastern District of
Oklahoma. The plaintiffs allege that XTO Energy wrongfully deducted fees from royalty payments on Oklahoma wells, failed to
make diligent efforts to secure the best terms available for the sale of gas and its constituents, and demand an accounting to
determine whether they have been fully and fairly paid gas royalty interests. The case was certified as a class action in April
2012. 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. In light of the arbitration tribunal’s decision on the treatment of the Fankhouser
settlement, to the extent that the claims in Chieftain or Roderick are similar to those in Fankhouser, the trustee would likely object
to such claimed reductions. 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 through the American Arbitration Association under the
terms of the Indenture creating the trust.
36
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
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 alleged that XTO Energy failed to properly pay and account to the trust under the terms of the net
overriding royalty conveyances on certain Kansas and Oklahoma properties and that Bank of America, N.A., as the previous
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 plaintiff sought unspecified amounts for actual/compensatory damages, punitive damages, disgorgement
and injunctive relief. Sandra Goebel, another unitholder of the trust, filed a Motion to Intervene in Lamb’s lawsuit and to stay the
action in favor of her lawsuit pending in the Dallas County District Court (see discussion below) or, in the alternative, for the court
to appoint her attorneys lead counsel in Lamb’s lawsuit. On September 5, 2014, Goebel withdrew her Motion to Intervene. That
same day, Lamb filed a Motion to Voluntarily Dismiss his claims. On September 29, 2014, the Lamb case was dismissed without
prejudice to refile in state court. Lamb’s counsel has been added as counsel of record for Goebel.
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 (“AAA”). 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 did 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. (the previous
trustee) 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. Bank of America, N.A. 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 Bank of
America, N.A. 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 and
Processing Company, Inc. and Bank of America, N.A. in Dallas County District Court. The allegations are the same as those
contained in the previous arbitration demand. Defendants answered with general denials and additionally filed pleas to the
jurisdiction, special exceptions, and a plea in abatement challenging, among other things, Goebel’s putative authority to bring
claims on behalf of the trust over the trustee’s objection. The Defendants also filed a joint motion to stay the Goebel case in favor
of the first filed Lamb case discussed above. The court denied Defendants’ pleas to the jurisdiction and special exceptions,
although it did not rule on the plea in abatement. Simultaneously, the judge conditionally stayed the case pending a ruling on
Goebel’s Motion to Intervene in the Lamb case. On September 5, 2014, however, Goebel withdrew her Motion to Intervene. That
same day, Lamb filed a Motion to Voluntarily Dismiss his federal district court lawsuit (see discussion above). Goebel filed a
motion to lift the stay in the state district court; while XTO Energy, Timberland and Bank of America (individually and now as
former trustee) filed a motion to stay the case pending a mandamus appeal of the district court’s denial of their pleas to the
jurisdiction and special exceptions. On October 30, 2014, the district court granted Plaintiff’s motion to lift stay. On October 31,
2014, the district court denied Defendants’ motion to stay pending mandamus. On November 7, 2014, the Defendants filed their
petition for writ of mandamus with the Dallas Court of Appeals. Defendants also filed a motion seeking a stay from the court of
appeals, along with the petition for writ of mandamus. On November 13, 2014, the court of appeals granted Defendants’ motion
and stayed the lawsuit, including all associated discovery, until the court opines on the petition for writ of mandamus. Goebel
filed a response to the petition for the writ of mandamus on December 16, 2014 and the Defendants replied on January 13, 2015.
Accordingly, the petition has been fully briefed and is awaiting a decision from the court of appeals. Southwest Bank, the current
trustee, has not yet been named a party in the case. The trustee will vigorously defend any claims that may be asserted against it.
XTO Energy has informed the trustee that it believes that XTO Energy and Timberland have strong defenses to this lawsuit and
intend to vigorously defend their positions. Bank of America has informed the trustee that it believes it has strong defenses to the
37
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
lawsuit and will vigorously defend its position. The terms of the trust indenture provide that Bank of America 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 lawsuit.
As a result, the trustee reserved an additional $1.6 million from trust distributions for the Goebel litigation, beginning with the
September 2013 distribution. The September 2013 through December 2013 distributions each reflected a deduction of $400,000
in connection with such reserve. Additionally, the trustee previously reserved an additional $1.6 million from trust distributions for
the Lamb litigation but that is now a part of the reserve for the Goebel lawsuit. The January 2014 through April 2014 distributions
each reflected a deduction of $400,000 in connection with such reserve. As the Goebel lawsuit progresses, the trustee may need to
revise the reserve.
Certain of the underlying properties are involved in various other lawsuits and governmental proceedings arising in the
ordinary course of business. XTO Energy has advised the trustee that it does not believe that the ultimate resolution of these
claims will have a material effect on the financial position or liquidity of the trust, but may have an effect on annual distributable
income.
Other
Several states have enacted legislation requiring state income tax withholding from nonresident recipients of oil and gas
proceeds. After consultation with its tax counsel, the trustee believes that it is not required to withhold on payments made to the
unitholders. However, regulations are subject to change by the various states, which could change this conclusion. Should
amounts be withheld on payments made to the trust or the unitholders, distributions to the unitholders would be reduced by the
required amount, subject to the filing of a claim for refund by the trust or unitholders for such amount.
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.
38
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
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 $4.35 per Mcf in 2014, $3.92 per Mcf in
2013, $3.21 per Mcf in 2012 and $4.67 per Mcf in 2011. Oil prices used to determine the standardized measure were based on
average realized oil prices of $92.70 per Bbl in 2014, $94.32 per Bbl in 2013, $91.90 per Bbl in 2012 and $92.92 per Bbl in 2011.
Proved Reserves
(in thousands)
Underlying Properties
Oil (Bbls)
Gas (Mcf)
Net Profits Interests
Oil (Bbls)
Gas (Mcf)
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance, December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
289,909
217
(21,574)
(20,371)
—
248,181
5
12,050
(18,713)
(50)
241,473
123
(13,981)
(17,427)
—
2,739
32
(29)
(229)
—
2,513
2
214
(217)
(27)
2,485
8
(70)
(204)
—
126,262
96
(43,010)
(5,992)
—
1,287
14
(350)
(76)
—
77,356
3
15,900
(7,770)
(15)
85,474
46
(1,353)
(8,004)
—
875
1
200
(99)
(8)
969
3
(5)
(111)
—
856
Balance, December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
210,188
2,219
76,163
Extensions, additions and discoveries in 2012, 2013 and 2014 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. 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.
39
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Proved Developed Reserves
(in thousands)
Underlying Properties
Oil (Bbls)
Gas (Mcf)
Net Profits Interests
Oil (Bbls)
Gas (Mcf)
December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
250,833
2,391
113,312
1,159
December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
211,638
2,192
71,327
December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
204,611
2,163
76,239
December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
177,389
1,847
68,335
806
878
767
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
Underlying Properties
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future costs:
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% discount factor
2014
December 31
2013
2012
$1,119,099
$1,181,208
$1,028,147
572,635
72,227
474,237
227,641
621,958
64,064
495,186
237,147
579,185
64,064
384,898
181,595
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 246,596
$ 258,039
$ 203,303
Net Profits Interests
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future production taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 412,882
33,492
$ 431,190
35,041
$ 334,857
26,939
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% discount factor
379,390
182,112
396,149
189,718
307,918
145,275
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 197,278
$ 206,431
$ 162,643
40
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
Underlying Properties
Standardized measure, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014
2013
2012
$258,039
$203,303
$ 418,691
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53,081
(17,867)
22,088
(12,192)
(1,371)
43,739
376
(60,858)
5,300
—
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
—
Net change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(11,443)
54,736
(215,388)
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$246,596
$258,039
$ 203,303
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$206,431
301
17,671
17,321
—
(44,446)
$162,643
82
14,710
66,861
(531)
(37,334)
$ 334,953
882
29,189
(177,249)
—
(25,132)
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$197,278
$206,431
$ 162,643
41
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 2014
and 2013:
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter
Net Profits
Income
Distributable
Income
$ 9,290,470
16,484,703
10,323,706
8,347,594
$ 7,650,320
17,846,840
10,141,840
8,170,680
Distributable
Income
per Unit
$0.191258
0.446171
0.253546
0.204267
$44,446,473
$43,809,680
$1.095242
$ 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
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.
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, Southwest Bank, is responsible for establishing and maintaining adequate internal control over financial
reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The
trustee conducted an evaluation of the effectiveness of the trust’s internal control over financial reporting based on the criteria
established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on the trustee’s evaluation under the framework in Internal Control — Integrated Framework
(2013), the trustee concluded that the trust’s internal control over financial reporting was effective as of December 31, 2014. The
reporting as of December 31, 2014 has been audited by
effectiveness of
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report under Item 8, Financial
Statements and Supplementary Data.
the trust’s internal control over
financial
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, 2014
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
Item 10. Directors, Executive Officers and Corporate Governance
PART III
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,
2014.
Because the trust has no employees, it does not have a code of ethics. Employees of the trustee, Southwest Bank, must
comply with the bank’s standards of conduct, a copy of which will be made available to unitholders without charge, upon request
by appointment at 2911 Turtle Creek Boulevard, Suite 850, Dallas, Texas, 75219.
Item 11. Executive Compensation
The trustee received the following annual compensation from 2012 through 2014 as specified in the trust indenture:
U.S. Trust, Bank of America
Private Wealth Management, Trustee(1)(2) . . . . . . . . . . . . .
Southwest Bank, Trustee(1)(2) . . . . . . . . . . . . . . . . . . . . . .
$29,739
$35,728
$63,343
—
$58,873
—
2014
2013
2012
(1)
(2)
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.
Compensation for U.S. Trust is for the period January 2014 through May 2014 and compensation for Southwest Bank is for
the period May 2014 through December 2014.
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.
(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, 2014 was
approximately $1,022,000 per month, or $12,264,000 annually (net to the trust of $817,600 per month or $9,811,200 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 a significant 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 2012 through 2014.
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, 2014 and 2013
are:
Audit fees-KPMG(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Audit fees-PwC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Audit-related fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All other fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014
2013
$ — $
$140,850
—
—
—
7,034
$116,850
—
—
—
$140,850
$123,884
(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, 2014 and 2013
Statements of Distributable Income for the years ended December 31, 2014, 2013 and 2012
Statements of Changes in Trust Corpus for the years ended December 31, 2014, 2013 and 2012
Notes to Financial Statements
2.
Financial Statement Schedules
Financial statement schedules are omitted because of the absence of conditions under which they are required or because
the required information is given in the financial statements or notes thereto.
3.
Exhibits
(4) (a)
(b)
(c)
(d)
Hugoton Royalty Trust Indenture by and between NationsBank, N.A., as trustee, and Cross Timbers Oil
Company (predecessor of XTO Energy) heretofore filed as Exhibit 4.1 to the trust’s Registration Statement
No. 333-68441 on Form S-1 filed with the Securities and Exchange Commission on December 4, 1998, is
incorporated herein by reference.
Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80% - Kansas) as amended and restated from
Cross Timbers Oil Company (predecessor of XTO Energy)
to NationsBank, N.A., as trustee, dated
December 1, 1998, heretofore filed as Exhibit 10.1.1 to the trust’s Registration Statement No. 333-68441
on Form S-1 filed with the Securities and Exchange Commission on March 16, 1999, is incorporated herein
by reference.
Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80% - Oklahoma) as amended and restated
from Cross Timbers Oil Company (predecessor of XTO Energy) to NationsBank, N.A., as trustee, dated
December 1, 1998, heretofore filed as Exhibit 10.1.2 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., 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, Southwest Bank, P.O. Box 962020, Fort Worth, Texas 76162-2020.
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 SOUTHEST BANK, TRUSTEE
By /S/ NANCY G. WILLIS
Nancy G. Willis
Vice President
EXXON MOBIL CORPORATION
Date: March 6, 2015
By /S/ BETH E. CASTEEL
Beth E. Casteel
Vice President – Upstream Business Services
(The trust has no directors or executive officers.)
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.hgt-hugoton.com.
Hugoton Royalty Trust
Southwest Bank
P.O. Box 962020
Fort Worth, Texas 76162-2020
Attention: Annual Reports
1-855-588-7839
Web site
www.hgt-hugoton.com
Auditors
PricewaterhouseCoopers LLP
Houston, 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, 2014.
Hugoton Royalty Trust
Southwest Bank
P.O. Box 962020
Fort Worth, Texas 76162-2020
1-855-588-7839
www.hgt-hugoton.com
2014
Annual Report and Form 10-K