Hugoton Royalty Trust
2015
Annual Report and Form 10-K
Glossary of Terms
Bbl
Barrel (of oil)
Bcf
Mcf
MMBtu
Net Proceeds
Net Profits Income
Net Profits Interest
Underlying Properties
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.
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 2015 and 2014:
2015
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2014
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Sales Price
High
Low
Distributions
per Unit
$ 8.49
6.00
3.55
3.58
$ 9.11
12.04
11.11
10.25
$ 5.70
3.50
2.50
1.47
$ 7.48
7.62
8.93
7.51
$0.094150
0.029643
0.033681
0.036357
$0.193831
$0.191258
0.446171
0.253546
0.204267
$1.095242
At December 31, 2015, there were 40,000,000 units outstanding and approximately 673 unitholders of record; 37,928,224 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.
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.
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 January 2015 through September
2015, November 2015, December 2015, and November 2014,
and on properties underlying the Wyoming net profits interests
in March 2015 through May 2015, July 2015, and September
2015 through December 2015. 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 2015 tax booklet
for specific instructions. Unitholders should consult their tax
advisors for further information.
Selected Financial Data
2015
Years Ended December 31,
Net Profits Income ............................... $ 8,243,917
Distributable Income ............................ 7,753,240
Distributable Income per Unit ...............
0.193831
Distributions per Unit ...........................
0.193831
Total Assets at Year End ........................ $ 88,185,111
2014
$ 44,446,473
43,809,680
1.095242
1.095242
$ 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
$ 56,565,368
55,764,960
1.394124
1.394124
$ 118,965,716
To Unitholders:
We are pleased to present the 2015 Annual Report on
information on excess costs, see “Trustee’s Discussion
Form 10-K of the Hugoton Royalty Trust as filed with
and Analysis of Financial Condition and Results of
the Securities and Exchange Commission. This report
Operations” under Item 7 of the accompanying
contains important information about the Trust’s net
Form 10-K.
profits interests, including information provided to the
The Trust and XTO Energy are parties to
trustee by XTO Energy.
several legal proceedings that may affect future
For the year ended December 31, 2015, net
Trust distributions. For further information, please
profits income totaled $8,243,917. After adding
see “Legal Proceedings” under Item 3 of the
interest income of $213 and deducting Trust
accompanying Form 10-K.
administration expense of $490,890, distributable
Natural gas prices averaged $2.72 per Mcf for
income was $7,753,240 or $0.193831 per unit.
2015, 41% lower compared to the 2014 average price
Net profits income and distributions were 81%
of $4.60 per Mcf. The average 2015 oil price was
and 82%, respectively, lower than 2014 amounts
$49.90 per Bbl, 48% lower compared to the 2014
primarily because of lower oil and gas prices, the
average price of $95.35 per Bbl.
arbitration reimbursement included in 2014 and
Gas sales volumes from the underlying
decreased oil and gas production, partially offset by
properties for 2015 were 15,736,066 Mcf, or 43,113
decreased taxes, transportation and other costs, lower
Mcf per day, a decrease of 10% from 47,745 Mcf per
development costs and excess costs on the Kansas
day in 2014. Oil sales volumes from the underlying
and Wyoming net profit interests in 2015. For further
properties were 194,381 Bbls, or 533 Bbls per day
information on the arbitration reimbursement, see
in 2015, a decrease of 5% from 558 Bbls per day in
“Legal Proceedings” under Item 3 and for further
2014. For further information on sales volumes and
To Unitholders: Continued
product prices, see “Trustee’s Discussion and Analysis
year production. All reserve information prepared
of Financial Condition and Results of Operations”
by independent engineers has been provided to the
under Item 7 of the accompanying Form 10-K.
trustee by XTO Energy.
As of December 31, 2015, proved reserves
Estimated future net cash flows from proved
for the underlying properties were estimated by
reserves of the net profits interests at December 31,
independent engineers to be 104.0 Bcf of natural
2015 were $35 million. Using an annual discount
gas and 1.2 million Bbls of oil. Natural gas reserves
factor of 10%, the present value of estimated future
for the underlying properties declined 106.2 Bcf and
net cash flows at December 31, 2015 was $24 million.
oil reserves for the underlying properties declined
Proved reserve estimates and related future net cash
approximately 1.0 million Bbls primarily due to
flows have been determined based on a 12-month
lower oil and gas prices used to estimate reserves
average gas price of $2.10 per Mcf and a 12-month
and current year production. Based on an allocation
average oil price of $46.56 per Bbl, based on the
of these reserves, proved reserves attributable to the
first-day-of-the-month price for each month in the
net profits interests were estimated to be 14.5 Bcf of
period, and year end costs. Other guidelines used
natural gas and 179,000 Bbls of oil. Estimated gas
in estimating proved reserves, as prescribed by the
and oil reserves attributable to the net profits interests
Financial Accounting Standards Board, are described
decreased from previously reported reserves at year-
in Note 9 to Financial Statements under Item 8,
end 2014 due to lower oil and gas prices and current
“Financial Statements and Supplementary Data” of
To Unitholders: Continued
the accompanying Form 10-K. The present value of
estimated future net cash flows is computed based on
SEC guidelines and is not necessarily representative of
Hugoton Royalty Trust
By: Southwest Bank, Trustee
the market value of Trust units.
By: Nancy G. Willis
Vice President
As disclosed in the tax instructions provided
March 11, 2016
to unitholders in February 2016, Trust distributions
are considered portfolio income, rather than passive
income. Unitholders should consult their tax advisors
for further information.
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, 2015
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, 2015 (the last business day of its most recently
completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $140 million.
At February 15, 2016, 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
2015 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
Glossary of Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk Factors
Unresolved Staff Comments
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part II
Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trustee’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 15.
Part IV
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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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
underlying properties
working 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.
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.
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 for January 2015 through September 2015, November
2015, December 2015 and November 2014, and on properties underlying the Wyoming net profits interests for March 2015 through May 2015, July 2015
and September 2015 through December 2015. For further information on excess costs, see Trustee’s Discussion and Analysis of Financial Condition and
Results of Operations, under Item 7.
The Trust is not liable for any production costs or liabilities attributable to the underlying properties. If at any time the Trust receives net profits income
in excess of the amount due, the Trust is not obligated to return such overpayment, but net profits income payable to the Trust for the next month will be
reduced by the overpayment, plus interest at the prime rate.
As a working interest owner, XTO Energy can generally decline participation in any operation and allow consenting parties to conduct such operations,
as provided under the operating agreements. XTO Energy also can assign, sell, or otherwise transfer its interest in the underlying properties, subject to the net
profits interests, or can abandon an underlying property if it is incapable of producing in paying quantities, as determined by XTO Energy.
To the extent allowed, XTO Energy is responsible for marketing its production from the underlying properties under existing sales contracts, or new
arrangements on the best terms reasonably obtainable in the circumstances. See “Pricing and Sales Information” under Item 2, Properties.
2
Net profits income received by the Trust on or before the last business day of the month is related to net proceeds received by XTO Energy in the
preceding month, and is generally attributable to oil and gas production two months prior. The amount to be distributed to unitholders each month by the
trustee is determined by:
Adding –
(1) net profits income received,
(2) interest income and any other cash receipts and
(3) cash available as a result of reduction of cash reserves, then
Subtracting –
(1) liabilities paid and
(2) the reduction in cash available related to establishment of or increase in any cash reserve.
The monthly distribution amount is distributed to unitholders of record within ten business days after the monthly record date. The monthly record date
is generally the last business day of the month. The trustee calculates the monthly distribution amount and announces the distribution per unit at least ten days
prior to the monthly record date.
The trustee may establish cash reserves for contingencies. Cash held for such reserves, as well as for pending payment of the monthly distribution
amount, may be invested in federal obligations or certificates of deposit of major banks.
The trustee’s function is to collect the net profits income from the net profits interests, to pay all trust expenses, and pay the monthly distribution
amount to unitholders. The trustee’s powers are specified by the terms of the Trust indenture. The Trust cannot engage in any business activity or acquire any
assets other than the net profits interests and specific short-term cash investments. The Trust has no employees since all administrative functions are performed
by the trustee.
Approximately 76% of the net profits income received by the Trust during 2015, as well as 78% of the estimated proved reserves of the net profits
interests at December 31, 2015 (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.
The oil and gas industry has been challenged throughout 2015 with abundance of crude oil and natural gas supplies causing commodity prices to
decrease. However, current market conditions are not necessarily indicative of future conditions.
Item 1A. Risk Factors
The following factors could cause actual results to differ materially from those contained in forward-looking statements made in this report and
presented elsewhere by the trustee from time to time. Such factors may have a material adverse effect upon the trust’s financial condition, distributable
income and changes in trust corpus.
The following discussion of risk factors should be read in conjunction with the financial statements and related notes included under Item 8, Financial
Statements and Supplementary Data. Because of these and other factors, past financial performance should not be considered an indication of future
performance.
The market price for the Trust units may not reflect the value of the net profits interests held by the trust.
The public trading price for the Trust units tends to be tied to the recent and expected levels of cash distributions on the Trust units. The amounts
available for distribution by the Trust vary in response to numerous factors outside the control of the Trust or XTO Energy, including prevailing prices for oil and
natural gas produced from the underlying properties. The market price of the Trust units is not necessarily indicative of the value that the Trust would realize if
3
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. A significant decline in oil or natural gas prices could have a material adverse effect on the amount
of oil and natural gas that is economic to produce, Trust net profits (and therefore cash available for distribution to unitholders) and proved reserves
attributable to the Trust’s interests. 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 for January 2015 through September 2015, November 2015, December 2015 and November
2014, and the Wyoming net profits interests for March 2015 through May 2015, July 2015 and September 2015 through December 2015), 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.
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.
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.
4
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. This creditworthiness may be impacted by 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. Future maintenance and development projects
on the underlying properties will affect the quantity of proved reserves and can offset the reduction in the depletion of 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 geopolitical hostilities could adversely affect trust distributions or the market price of the Trust units.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response, cause instability
in the global financial and energy markets. Terrorism and other geopolitical hostilities could adversely affect trust distributions or the market price of the Trust
units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in oil and natural gas prices, or the possibility
that the infrastructure on which the operators of the underlying properties rely could be a direct target or an indirect casualty of an act of terror.
XTO Energy may transfer its interest in the underlying properties without the consent of the Trust or the Trust unitholders.
XTO Energy may at any time transfer all or part of its interest in the underlying properties to another party. Neither the Trust nor the Trust unitholders
are entitled to vote on any transfer of the properties underlying the trust’s net profits interests, and the Trust will not receive any proceeds of any such transfer.
Following any transfer, the transferred property will continue to be subject to the net profits interests of the trust, but the calculation, reporting and remitting of
net proceeds to the Trust will be the responsibility of the transferee.
XTO Energy or any other operator of any underlying property may abandon the property, thereby terminating the related net
profits interest payable to the trust.
XTO Energy or any other operator of the underlying properties, or any transferee thereof, may abandon any well or property without the consent of the
Trust or the Trust unitholders if they reasonably believe that the well or property can no longer produce in commercially economic quantities. This could result in
the termination of the net profits interest relating to the abandoned well or property.
5
The net profits interests can be sold and the Trust would be terminated. The Trust will also be terminated if it fails to
generate sufficient gross proceeds.
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 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:
• continued low oil or natural gas prices;
• 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.
6
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. See “Regulation” on pp. 13-14 and “Greenhouse Gas
Emissions and Climate Change Regulations” on p. 23.
Item 1B. Unresolved Staff Comments
As of December 31, 2015, 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, 2015 is approximately 8 years. This index is calculated using total proved reserves and estimated 2016 production for the underlying
properties. The projected 2016 production is from proved developed producing reserves as of December 31, 2015. Based on estimated future net cash flows
at 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period, the proved reserves of the underlying properties
are approximately 80% natural gas and 20% oil. XTO Energy operates approximately 95% of the underlying properties.
Because the underlying properties are working interests, production expense, development costs and overhead are deducted in calculating net profits
income. As a result, net profits income is affected by the level of maintenance and development activity on the underlying properties. See Trustee’s Discussion
and Analysis of Financial Condition and Results of Operations, under Item 7. Total 2015 development costs deducted for the underlying properties were $2.8
million, a decrease of 47% from the prior year. XTO Energy has informed the trustee that total 2016 budgeted development costs for the underlying properties
are between $3 million and $5 million. Changes in oil or natural gas prices could impact future development plans on the underlying properties.
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 2015, daily sales volumes from the underlying properties in the
Hugoton area averaged approximately 10,500 Mcf of gas and 35 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. Prior to 2011, XTO Energy drilled wells to these formations and plans to continue this development program sometime in the future.
7
Within this area, XTO Energy did not drill any wells but did perform 10 workovers in 2015. XTO Energy has informed the trustee that it does not plan
to drill any new wells but may perform up to 13 workovers during 2016.
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
• future drilling of 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 advised the trustee that Timberland permanently shut down the processing portion of its facilities as of May 1, 2014 due to reliability
issues. XTO Energy then advised the trustee that Timberland believed that investments and repairs were not economically feasible; however, Timberland
continued to gather and compress gas from the Hugoton area. Effective May 1, 2014, XTO Energy entered into a gas sales and processing contract 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 has advised the trustee, in recent
months, has been approximately 11,000 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 has exercised its contractual right to take in kind and sell its NGLs and helium when the DCP plant
started processing again. 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. XTO Energy will sell 100% of the net value for any recovered NGLs to Oneok at
Conway pricing as posted by Oil Price Information Services minus an adjusted base differential. XTO Energy will sell the helium to Air Products and Chemicals,
Inc. and Air Products Helium, Inc. under a pricing formula based upon the open market crude helium sales price established by the U. S. Bureau of Land
Management. 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. 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.
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 20,200 Mcf of gas and 475 Bbls of oil in 2015.
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 25 workovers in 2015. XTO Energy has informed the trustee that it does not plan to drill any new wells but may perform up to 25 workovers
in Major County during 2016.
8
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
2015. 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 2016.
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 6 workovers in 2015. XTO
Energy has informed the trustee that it does not plan to drill any new wells but may perform up to 5 workovers within the Elk City field during 2016.
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
• future drilling of 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 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 2015, the gathering system collected approximately 9,000 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 2015 sales volumes from the underlying properties in the Fontenelle field averaged 12,400 Mcf of natural gas and 23 Bbls of oil. XTO Energy did
not drill any wells or perform any workovers in the Green River Basin in 2015. XTO Energy has advised the trustee that it does not plan to drill any new wells
or perform any workovers in the Green River Basin during 2016. 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.
9
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 2015, the fuel
charge was 2.53% 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 $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, 2015. Undeveloped acreage is not significant.
Hugoton Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Anadarko Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Green River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross
208,703
166,401
35,237
Net
195,355
129,698
26,190
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
410,341
351,243
The following is a summary of the producing wells on the underlying properties as of December 31, 2015:
Gas
Oil
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross
1,183.0
42.0
Net
1,048.0
38.9
Gross
265.0
4.0
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,225.0
1,086.9
269.0
Net
58.1
0.9
59.0
Gross
1,448.0
46.0
Net
1,106.1
39.8
1,494.0
1,145.9
Operated
Wells
Nonoperated
Wells
Total
The following is a summary of the number of wells drilled on the underlying properties during the years indicated. During 2015, 2014 and 2013 no
exploratory wells were drilled on the underlying properties. There were no wells in process of drilling at December 31, 2015.
2015
2014
2013
Net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — —
Completed gas wells
Completed oil wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — —
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — —
Dry wells
Gross
Gross
Gross
Net
Net
Total(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — —
(a)
Included in totals are zero wells in 2015, 2014 and 2013 drilled on nonoperated interests.
10
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, 2015:
Underlying Properties
Proved Reserves(a)
Gas
(Mcf)
Oil
(Bbls)
Net Profits Interests
Proved Reserves(a)(b)
Gas
(Mcf)
Oil
(Bbls)
Future Net Cash Flows
from Proved Reserves(a)(c)
Discounted
Undiscounted
(in thousands)
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kansas
75,098
21,100
7,764
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
103,962
1,126
30
30
1,186
11,437
2,023
1,027
14,487
172
3
4
179
$29,566
3,968
1,942
$35,476
$19,378
2,999
1,306
$23,683
(a)
(b)
(c)
Based on 12-month average oil price of $46.56 per Bbl and $2.10 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 88% from year-end 2014 to 2015, primarily because of a 52%
decrease in gas prices, a 50% decrease in oil prices, reserve revisions due to lower prices and 2015 production.
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%.
When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under the SEC definition of
proved reserves, certain quantities of oil and natural gas may no longer qualify as proved reserves.
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
102,683
1,279
Total proved reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
103,962
1,178
8
1,186
14,411
76
14,487
178
1
179
Approximately 99% 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, 2015, 2014, 2013
and 2012. Miller and Lents’ primary technical person responsible for calculating the trust’s reserves has more than 40 years of experience as a reserve
engineer. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the
net profits interests. Numerous uncertainties are inherent in estimating reserve volumes and values, and such estimates are subject to change as additional
information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original
estimates.
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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.
When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under the SEC definition of
proved reserves, certain quantities of oil and natural gas may no longer qualify as proved reserves. Amounts required to be de-booked as proved reserves on an
SEC basis are subject to being re-booked as proved reserves at some point in the future when price levels recover.
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)
2015
2014
2013
15,736,066
43,113
194,381
533
17,426,780
47,745
203,667
558
18,712,650
51,268
216,634
594
2,292,205
6,280
40,817
112
8,004,435
21,930
110,515
303
7,770,148
21,288
99,363
272
Average Sales Price
Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2.72
$49.90
$ 4.60
$95.35
$ 4.03
$95.25
Oil and gas production by conveyance attributable to the underlying properties for each of the three years ended December 31 were as follows:
Conveyance
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015
Underlying Gas Production (Mcf)
2014
1,531,314
11,255,819
4,639,647
2013
1,606,436
12,041,983
5,064,231
1,267,647
9,933,308
4,535,111
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15,736,066
17,426,780
18,712,650
Conveyance
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Underlying Oil Production (Bbls)
2014
2015
2013
5,938
180,129
8,314
194,381
7,023
188,911
7,733
203,667
9,427
196,345
10,862
216,634
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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 is in effect 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.
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.
13
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 2015, 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 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
investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels
investment income from all
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 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 and 2013, the trustee 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). In 2015 the trustee distributed a portion
14
of the legal reserve and elected to reserve amounts from monthly distributions to establish an administrative expense reserve, so the taxable income per
period has frequently differed from the actual amount distributed to unitholders. The amounts distributed from the legal reserve are treated as additional gross
royalty income to the 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 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 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
15
by the various states, which could change this conclusion. Should amounts be withheld on payments made to the Trust or the unitholders, distributions to the
unitholders would be reduced by the required amount, subject to the filing of a claim for refund by the Trust or unitholders for such amount.
Other Regulation
The Minerals Management Service of the United States Department of the Interior amended the crude oil valuation regulations in July 2004 and the
natural gas valuation regulations in June 2005 for oil and natural gas produced from federal oil and natural gas leases. The principal effect of the oil
regulations pertains to which published market prices are most appropriate to value crude oil not sold in an arm’s-length transaction and what transportation
deductions should be allowed. The principal effect of the natural gas valuation regulations pertains to the calculation of transportation deductions and changes
necessitated by judicial decisions since the regulations were last amended. Seven percent of the net acres of the underlying properties, primarily located in
Wyoming, involve federal leases. Neither of these changes have had a significant effect on trust distributions.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws, including, but not limited to,
regulations and laws relating to environmental protection, occupational safety, resource conservation and equal employment opportunity. XTO Energy has
advised the trustee that it does not believe that compliance with these laws will have any material adverse effect upon the unitholders.
Item 3. Legal Proceedings
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 decided on April 21, 2014 that the settlement cannot be charged to the Trust, including the new royalty calculation for
future royalty payments. Additionally, XTO Energy had to reimburse $4,386,396, representing amounts withheld from the September and October 2012
distributions and $1,985,438, representing attorney fees, arbitration expenses and interest. The arbitration award was entered into as a final judgment in
State District Court of Tarrant County, Texas 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.
The case was previously stayed pending a final decision from the Kansas Supreme Court on the Fawcett v. OPIK appeal. Following the decision in Fawcett, the
Judge in Roderick ordered new briefing on the pending motions. 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
16
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.
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. On September 5, 2014,
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 was added as counsel of record for Goebel in Sandra G. Goebel vs. XTO Energy, Inc., Timberland Gathering & Processing Company, Inc. and Bank of
America, N.A.
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 Energy
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. After dismissal as non-arbitrable, Goebel 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. After a series of pleadings, writ of
mandamus and court of appeals decision, the matter was finally dismissed with prejudice by the Dallas County District Court on October 12, 2015. Goebel
failed to appeal the final judgment. 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 anticipated that the Trust would incur additional legal and other expenses in connection with the Goebel lawsuit. As a result, the trustee
reserved $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 had previously reserved an
additional $1.6 million from trust distributions for the Lamb litigation, which was dismissed, and was included as 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. The Goebel
lawsuit was
dismissed on October 12, 2015. As a result, the trustee moved $750,000 of the remaining legal expense reserve to the administrative expense reserve and
the remaining balance of $601,920 was included in the November 2015 distribution to unitholders. The amounts distributed from the legal reserve are
treated as additional gross royalty income to the unitholders.
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.
17
PART II
Item 5. Market for Units of the Trust, Related Unitholder 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 2015 and 2014:
Quarter
Sales Price
High
Low
Distributions
per Unit
2015
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
First
Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 8.49
6.00
3.55
3.58
$5.70
3.50
2.50
1.47
2014
First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 9.11
12.04
11.11
10.25
$ 7.48
7.62
8.93
7.51
$0.094150
0.029643
0.033681
0.036357
$0.193831
$ 0.191258
0.446171
0.253546
0.204267
$ 1.095242
At December 31, 2015, there were 40,000,000 units outstanding and approximately 673 unitholders of record; 37,928,224 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
2015
Net Profits Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8,243,917 $44,446,473 $ 37,333,595 $ 25,132,038 $ 56,565,368
55,764,960
Distributable Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.394124
Distributable Income per Unit . . . . . . . . . . . . . . . . . . . . . . . . .
1.394124
Distributions per Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
118,965,716
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
7,753,240
0.193831
0.193831
88,185,111
43,809,680
1.095242
1.095242
93,920,959
2014
2012
2011
Year Ended December 31
2013
18
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)
2014
2015
Three Months Ended December 31(a)
2013
2015
2014
Sales Volumes
Gas (Mcf)(b)
Underlying properties . . . . . . . . . . . . . . . . . . . .
Average per day . . . . . . . . . . . . . . . . . . . . .
Net profits interests . . . . . . . . . . . . . . . . . . . . .
15,736,066
43,113
2,292,205
17,426,780
47,745
8,004,435
18,712,650
51,268
7,770,148
4,123,283
44,818
359,172
4,395,822
47,781
1,703,649
Oil (Bbls)(b)
Underlying properties . . . . . . . . . . . . . . . . . . . .
Average per day . . . . . . . . . . . . . . . . . . . . .
Net profits interests . . . . . . . . . . . . . . . . . . . . .
Average Sales Prices
Gas (per Mcf)
. . . . . . . . . . . . . . . . . . . . . . . . . .
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revenues
Gas sales
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
194,381
533
40,817
$2.72
$49.90
203,667
558
110,515
$4.60
$95.35
216,634
594
99,363
$4.03
$95.25
46,285
503
5,839
$2.58
$41.32
48,226
524
21,722
$4.13
$89.45
$42,864,131
9,699,090
$80,236,274
19,419,502
$75,469,935
20,635,040
$10,657,373
1,912,652
$18,159,388
4,313,582
Total Revenues
. . . . . . . . . . . . . . . . . . . . . . .
52,563,221
99,655,776
96,104,975
12,570,025
22,472,970
Costs
Taxes, transportation and other . . . . . . . . . . . . . . . .
Production expense . . . . . . . . . . . . . . . . . . . . . . .
Development costs(c)
. . . . . . . . . . . . . . . . . . . . . .
Overhead . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . .
Legal Expense(f)
. . . . . . . . . . . . . . . . . . . . . . . . . .
Excess costs(d)
7,554,245
20,898,895
2,800,000
12,542,488
10,523,008
21,683,844
5,300,000
12,156,711
— (5,482,995)
(82,883)
(1,537,304)
10,779,085
21,593,324
6,500,000
11,754,002
—
—
2,057,074
5,369,131
900,000
3,196,465
—
(275,904)
2,458,968
5,598,020
1,000,000
3,064,373
—
(82,883)
Total Costs . . . . . . . . . . . . . . . . . . . . . . . .
42,258,324
44,097,685
50,626,411
11,246,766
12,038,478
Other Proceeds
Property Sales(e) . . . . . . . . . . . . . . . . . . . . . . .
Net Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Profits Percentage . . . . . . . . . . . . . . . . . . . .
$
— $
10,304,897
55,558,091
— $ 1,188,430
46,666,994
—
1,323,259
—
10,434,492
80%
80%
80%
80%
80%
Net Profits Income . . . . . . . . . . . . . . . . . . . . . . .
$ 8,243,917
$44,446,473
$37,333,595
$ 1,058,607
$ 8,347,594
(a)
(b)
(c)
(d)
(e)
(f)
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.
See Note 8 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
19
Results of Operations
Years Ended December 31, 2015, 2014 and 2013
Net profits income for 2015 was $8,243,917, as compared with $44,446,473 for 2014 and $37,333,595 for 2013. The 81% decrease in net
profits income from 2014 to 2015 is primarily the result of lower oil and gas prices ($33.6 million), the arbitration reimbursement included in 2014 ($4.4
million) and decreased oil and gas production ($4.1 million), partially offset by decreased taxes, transportation and other costs ($2.4 million), lower
development costs ($2.0 million) and excess costs on the Kansas and Wyoming net profit interests in 2015 ($1.2 million). The 19% increase in net profits
income from 2013 to 2014 is primarily the result of higher gas prices ($8.5 million) and the 2014 arbitration reimbursement ($4.4 million), partially offset
by decreased oil and gas production ($5.7 million). Approximately 76% in 2015, 78% in 2014 and 76% in 2013 of net profits income was derived from
natural gas sales.
Trust administration expense was $490,890 in 2015 as compared to $1,153,924 in 2014 and $2,827,015 in 2013. Included in 2015
administration expense is $250,000 which the trustee reserved for administrative expenses, offset by a refund of $601,920 which represents the remaining
balance of the legal reserve that was included in the November 2015 distribution. Included in 2014 administration expense is $1,600,000 which the trustee
reserved for legal expenses regarding the Lamb lawsuit, partially offset by $1,470,618 related to the arbitration reimbursement. Included in 2013
administration expense is $1,600,000 which the trustee had reserved for legal expenses regarding the Goebel lawsuit. Interest income was $213 in 2015,
$517,131 in 2014 and $700 in 2013. 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 $7,753,240 or $0.193831 per unit in 2015, $43,809,680
or $1.095242 per unit in 2014 and $34,507,280 or $0.862682 per unit in 2013.
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
Gas.
From 2014 to 2015, underlying gas sales volumes decreased 10% primarily due to repairs and maintenance at a third party gas processing
system in the Hugoton area following a force majeure incident and natural production decline. From 2013 to 2014, underlying gas sales volumes decreased
7% primarily due to natural production decline.
XTO Energy advised the trustee that repairs and maintenance in the first half of 2015 at a third party gas processing system in the Hugoton area
following a force majeure incident has resulted in decreased underlying gas volumes of approximately 5,000 Mcf per day. After being advised by the third
party processor that the repairs were completed, XTO Energy then received notice that the force majeure event was being extended to the processing portion
of the third party plant due to an equipment malfunction. The processor was able to bypass the plant and take gas; however, the plant was not able to process
gas for NGLs or helium for a period of time. In late October, XTO Energy received notice that the plant returned to full capacity at the end of October 2015,
including the processing of gas for NGLs and helium. XTO Energy will continue to monitor the situation and assess its options.
Oil.
From 2014 to 2015, underlying oil sales volumes decreased 5% primarily due to natural production decline. From 2013 to 2014, underlying oil
sales volumes decreased 6% primarily due to natural production decline.
The estimated rate of natural production decline on the underlying oil and gas properties is approximately 6% to 8% a year.
Prices
Gas.
The 2015 average gas price was $2.72 per Mcf, a 41% decrease from the 2014 average gas price of $4.60 per Mcf, which was a 14%
increase from the 2013 average gas price of $4.03 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 2015 through January 2016 was $2.20 per MMBtu. At March 3, 2016, the average NYMEX gas price for the following
12 months was $2.18 per MMBtu.
20
Oil.
The average oil price for 2015 was $49.90 per Bbl, a 48% decrease from the average oil price for 2014 of $95.35 per Bbl, which was
relatively flat from the average oil price for 2013 of $95.25 per Bbl. Oil prices are expected to remain volatile. The average NYMEX price for November 2015
through January 2016 was $37.44 per Bbl. At March 3, 2016, the average NYMEX oil price for the following 12 months was $39.29 per Bbl.
Costs
The calculation of net profits income includes deductions for production expense, development costs and overhead since the related underlying
properties are working interests. If monthly costs exceed revenues for any state, these excess costs must be recovered, with accrued interest, from future net
proceeds of that state and cannot reduce net profits income from another state. See “Excess costs” below.
Taxes, transportation and other.
Taxes, transportation and other generally fluctuates with changes in total revenues. Taxes, transportation and other
decreased 28% from 2014 to 2015 primarily because of decreased oil and gas production taxes and other deductions related to lower oil and gas revenues,
partially offset by increased property taxes related to higher valuations. 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.
Production expense.
Production expense decreased 4% from 2014 to 2015 primarily because of decreased repairs and maintenance, fuel, and water
disposal costs, partially offset by increased labor costs. 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.
Development costs.
Development costs deducted were $2.8 million in 2015, $5.3 million in 2014 and $6.5 million in 2013. In 2015, actual
development costs were $3.8 million. At December 31, 2015, cumulative budgeted costs deducted exceeded cumulative actual costs by approximately $0.2
million. The monthly development cost deduction was $500,000 from the January 2013 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 and was maintained at that level through the August 2015 distribution. Due to the anticipated level of actual costs and the 2015
development budget, the development cost deduction was increased to $300,000 beginning with the September 2015 distribution and was maintained at
that level through the end of 2015. 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. Changes in oil or natural gas prices could impact future development plans on the underlying
properties. XTO Energy has advised the trustee that this monthly deduction will continue to be evaluated and revised as necessary. For further information on
2016 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 Energy advised the trustee that lower gas prices and decreased gas production resulted in net excess costs of $1,058,569
($846,855 net to the Trust) on properties underlying the Kansas net profits interest for the year ended December 31, 2015. This included net excess costs of
$91,057 ($72,846 net to the Trust) related to the quarter ended December 31, 2015. However, these excess costs did not reduce net proceeds from the
remaining conveyance.
XTO Energy advised the trustee that lower gas prices resulted in net excess costs of $478,735 ($382,988 net to the Trust) on properties underlying
the Wyoming net profits interest for the year ended December 31, 2015. This included net excess costs of $184,847 ($147,878 net to the Trust) related to
the quarter ended December 31, 2015. However, these excess costs did not reduce net proceeds from the remaining conveyance.
Cumulative excess costs for the Kansas and Wyoming conveyances remaining as of December 31, 2015 totaled $1,620,187 ($1,296,150 net to the
Trust).
XTO advised the trustee that decreased gas production related to a prior period adjustment resulted in net excess costs of $82,883 ($66,306 net to
the Trust) on properties underlying the Kansas net profits interests for the year ended December 31, 2014. However, these excess costs did not reduce net
proceeds from the remaining conveyances.
21
Legal Expense.
As a result of the arbitration ruling, legal expense for 2014 included a 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.
Fourth Quarter 2015 and 2014
During fourth quarter 2015 the Trust received net profits income totaling $1,058,607 compared with fourth quarter 2014 net profits income of
$8,347,594. This 87% decrease in net profits income was primarily due lower oil and gas prices ($7.3 million) and decreased oil and gas production ($0.6
million), partially offset by lower taxes, transportation and other costs ($0.3 million).
Administration expense was ($395,626) and interest income was $47, resulting in fourth quarter 2015 distributable income of $1,454,280 or
$0.036357 per unit. Included in fourth quarter 2015 administration expense is a refund of $601,920 which represents the remaining balance of the legal
reserve that was included in the November 2015 distribution. Distributable income for fourth quarter 2014 was $8,170,680 or $0.204267 per unit.
Distributions to unitholders for the quarter ended December 31, 2015 were:
Record Date
Payment Date
October 30, 2015
November 30, 2015
December 31, 2015
Volumes
November 16, 2015
December 14, 2015
January 15, 2016
Per Unit
$0.008643
0.020592
0.007122
$0.036357
Fourth quarter underlying gas sales volumes decreased 6% and underlying oil sales volumes decreased 4% from 2014 to 2015 primarily due to natural
production decline.
Prices
The average fourth quarter 2015 gas price was $2.58 per Mcf, or 38% lower than the fourth quarter 2014 average price of $4.13 per Mcf. The
average fourth quarter 2015 oil price was $41.32 per Bbl, or 54% lower than the fourth quarter 2014 average price of $89.45 per Bbl. For further
information about product prices, see “Years Ended December 31, 2015, 2014 and 2013 – Prices” above.
Costs
Taxes, transportation and other.
Taxes, transportation and other decreased 16% from fourth quarter 2014 to 2015 primarily because of decreased
oil and gas production taxes and other deductions related to lower oil and gas revenues, partially offset by increased property taxes related to increased
valuations.
Production expense.
Fourth quarter production expense decreased 4% from 2014 to 2015 primarily because of decreased compressor rental,
location, fuel and water disposal costs.
Development costs.
Development costs, which were deducted based on budgeted development costs, decreased 10% from fourth quarter 2014 to
2015. For further information about development costs, see “Years Ended December 31, 2015, 2014 and 2013 – Development costs” above.
Overhead.
Overhead is charged by XTO Energy for administrative expenses incurred to support operations of the underlying properties. Overhead
fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well as an annual cost level adjustment.
Excess costs.
For further information about excess costs, see “Years Ended December 31, 2015, 2014 and 2013 – Excess costs” above.
Purchaser Adjustment
XTO Energy advised the trustee that the February 2015 distribution included a one-time prior period adjustment for the recoupment of natural gas
liquids revenue from the Trust in the amount of $353,069 ($282,455 net to the Trust) which was deducted from net proceeds in the first quarter of 2015.
22
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. The climate accord reached at the recent Conference of the Parties (COP21) in Paris set many new goals, and while many
related policies are still emerging, XTO Energy has informed the trustee that it continues to anticipate that such policies will increase the cost of carbon dioxide
emissions over time. As these regulations are under development, XTO Energy is unable to predict the total impact of the potential regulations upon the
operators of the underlying properties, and it is possible that the operators of the underlying properties could face increases in operating costs in order to
comply with climate change or GHG emissions legislation, which costs could reduce net proceeds payable to the Trust and trust distributions.
Off-Balance Sheet Arrangements
The Trust has no off-balance sheet financing arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other
arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.
Contractual Obligations
As shown below, the Trust had no obligations and commitments to make future contractual payments as of December 31, 2015, other than the
December distribution payable to unitholders in January 2016, as reflected in the statement of assets, liabilities and trust corpus.
Distribution payable to unitholders
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Related Party Transactions
Payments due by Period
Total
$284,880
Less than
1 Year
$284,880
1 -3 Years
$—
3 -5 Years
$—
More than
5 Years
$—
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, 2015, the monthly overhead charge, based on the number of operated wells, was approximately
$1,059,000 ($847,200 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
23
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 $16.4 million for 2015, or 38% of total gas sales, $30.4 million for 2014, or 38% of total gas sales and $29.0 million for 2013,
or 38% 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.
Impairment
The trustee reviews the Trust’s net profits interests (“NPI”) in oil and gas properties for impairment whenever events or circumstances indicate that the
carrying value of the NPI may not be recoverable.
In general, the trustee does not view temporarily low prices as a trigger event for conducting an impairment test. The markets for crude oil and natural
gas have a history of significant price volatility and though prices will occasionally drop significantly, industry prices over the long term will continue to be
driven by market supply and demand. If a trigger event occurred, the trustee would use the estimated undiscounted future net cash flows from the NPI to
evaluate the recoverability of the Trust assets. If the undiscounted future net cash flows from the NPI are less than the NPI carrying value, the Trust would
recognize an impairment loss for the difference between the NPI carrying value and the estimated fair value of the NPI. The determination as to whether the
NPI is impaired requires a significant amount of judgment by the trustee and is based on the best information available to the trustee at the time of the
evaluation.
In light of the continued excess costs on two conveyances and the significant decrease in distributions, the trustee concluded that an impairment trigger
event had occurred in the fourth quarter of 2015. An assessment of the forecasted net cash flows was performed for the NPI. Cash flows used in the
assessment were developed using estimates for future crude oil and natural gas commodity prices published by third-party industry experts. Volumes and costs
were based on assumptions developed in the XTO Energy annual planning and budgeting process which includes the underlying properties from which the Trust
NPI were conveyed. The result of the assessment confirmed that the undiscounted future net cash flows from the NPI exceeds the carrying value of the NPI.
The assumption that prices will
increase in the future is key to the long-term profitability of the NPI. There was no impairment of the assets as of
December 31, 2015.
24
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.
When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under the SEC definition of
proved reserves, certain quantities of oil and natural gas may no longer qualify as proved reserves. Amounts required to be de-booked as proved reserves on an
SEC basis are subject to being re-booked as proved reserves at some point in the future when price levels recover.
The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 9 to Financial Statements under
Item 8, Financial Statements and Supplementary Data, is prepared using assumptions required by the Financial Accounting Standards Board and the Securities
and Exchange Commission. Such assumptions include using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in
the period, and year end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10%
rate. Changes in any of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure. Accordingly,
the standardized measure does not represent XTO Energy’s or the trustee’s estimated current market value of proved reserves.
Forward-Looking Statements
Certain information included in this annual report and other materials filed, or to be filed, by the Trust with the Securities and Exchange Commission (as
well as information included in oral statements or other written statements made or to be made by XTO Energy or the trustee) contain forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act of 1934, 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 and competition. 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 financial and operational 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. A
significant decline in oil or natural gas prices could have a material adverse effect on the amount of oil and natural gas that is economic to produce, Trust net
profits and proved reserves attributable to the Trust’s interests. 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.
25
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
27
28
28
28
29
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.
26
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, 2015
and 2014, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31,
2015. We also have audited the Trust’s internal control over financial reporting as of December 31, 2015, 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
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.
financial statement presentation. Our audit of
internal control over
financial
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, 2015 and 2014, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2015,
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, 2015, based on criteria established in Internal Control—Integrated Framework (2013) issued by COSO.
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
March 11, 2016
27
HUGOTON ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
Assets
Cash and short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net profits interests in oil and gas properties – net
$ 1,284,880
$ 4,324,131
(Notes 1 and 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
86,900,231
89,596,828
$88,185,111
$93,920,959
December 31
2015
2014
Liabilities and Trust Corpus
Distribution payable to unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Legal reserve(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expense reserve(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding) . . . . . . . . . . . . . . . . . . .
$
284,880
$ 2,540,320
— 1,783,811
—
89,596,828
1,000,000
86,900,231
(a)
The trustee moved $750,000 of the legal reserve to the expense reserve in November 2015. The remaining balance of the legal reserve totaling
$601,920 was included in the November 2015 distribution. The expense reserve allows the trustee to pay its obligations should it be unable to pay
them out of the net profits income.
$88,185,111
$93,920,959
STATEMENTS OF DISTRIBUTABLE INCOME
2015
Year Ended December 31
2014
$44,446,473
517,131
2013
$37,333,595
700
Net profits income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest income(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$8,243,917
213
Total income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Administration expense(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,244,130
490,890
44,963,604
1,153,924
37,334,295
2,827,015
Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$7,753,240
$43,809,680
$34,507,280
Distributable income per unit (40,000,000 units) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 0.193831
$ 1.095242
$ 0.862682
(a)
Administration expense for the period ended December 31, 2015 includes a refund of $601,920 which represents the remaining balance of the legal
reserve that was included in the November 2015 distribution. 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 on the arbitration
reimbursement see Note 8 of the accompanying notes to financial statements.
STATEMENTS OF CHANGES IN TRUST CORPUS
2015
Trust corpus, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of net profits interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions declared . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$89,596,828
(2,696,597)
7,753,240
(7,753,240)
Trust corpus, end of year
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$86,900,231
$ 89,596,828
$ 98,854,558
See accompanying notes to financial statements.
28
Year Ended December 31
2014
$ 98,854,558
(9,257,730)
43,809,680
(43,809,680)
2013
$109,892,977
(11,038,419)
34,507,280
(34,507,280)
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 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.
29
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
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 trustee reviews the Trust’s net profits interests (“NPI”) in oil and gas properties for impairment whenever events or circumstances indicate that the
carrying value of the NPI may not be recoverable.
In general, the trustee does not view temporarily low prices as a trigger event for conducting an impairment test. The markets for crude oil and natural
gas have a history of significant price volatility and though prices will occasionally drop significantly, industry prices over the long term will continue to be
driven by market supply and demand. If a trigger event occurred, the trustee would use the estimated undiscounted future net cash flows from the NPI to
evaluate the recoverability of the Trust assets. If the undiscounted future net cash flows from the NPI are less than the NPI carrying value, the Trust would
recognize an impairment loss for the difference between the NPI carrying value and the estimated fair value of the NPI.
The determination as to whether the NPI is impaired requires a significant amount of judgment by the trustee and is based on the best information
available to the trustee at the time of the evaluation. There was no impairment of the assets as of December 31, 2015.
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 $160,166,720 as of December 31, 2015 and $157,470,123 as of December 31, 2014.
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
Cumulative excess costs remaining at 12/31/14 . . . . . . . . . . . . . . . . . . . . . . . . .
Net excess costs for the quarter ended 3/31/15 . . . . . . . . . . . . . . . . . . . . . . . . .
Net excess costs for the quarter ended 6/30/15 . . . . . . . . . . . . . . . . . . . . . . . . .
Net excess costs for the quarter ended 9/30/15 . . . . . . . . . . . . . . . . . . . . . . . . .
Net excess costs for the quarter ended 12/31/15 . . . . . . . . . . . . . . . . . . . . . . . .
Conveyances
(Underlying)
WY
$ — $
87,082
125,832
80,974
184,847
Total
82,883
425,750
493,646
342,004
275,904
$
KS
82,883
338,668
367,814
261,030
91,057
Cumulative excess costs remaining at 12/31/15 . . . . . . . . . . . . . . . . . . . . . . . . .
$1,141,452
$478,735
$1,620,187
30
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
XTO Energy advised the trustee that lower gas prices and decreased gas production resulted in net excess costs of $1,058,569 ($846,855 net to the
Trust) on properties underlying the Kansas net profits interest for the year ended December 31, 2015. This included net excess costs of $91,057 ($72,846
net to the Trust) related to the quarter ended December 31, 2015. However, these excess costs did not reduce net proceeds from the remaining conveyance.
XTO Energy advised the trustee that lower gas prices resulted in net excess costs of $478,735 ($382,988 net to the Trust) on properties underlying
the Wyoming net profits interest for the year ended December 31, 2015. This included net excess costs of $184,847 ($147,878 net to the Trust) related to
the quarter ended December 31, 2015. However, these excess costs did not reduce net proceeds from the remaining conveyance.
Cumulative excess costs for the Kansas and Wyoming conveyances remaining as of December 31, 2015 totaled $1,620,187 ($1,296,150 net to the
Trust).
XTO advised the trustee that decreased gas production related to a prior period adjustment resulted in net excess costs of $82,883 ($66,306 net to
the Trust) on properties underlying the Kansas net profits interests for the year ended December 31, 2014. However, these excess costs did not reduce net
proceeds from the remaining conveyances.
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
2014
2015
2013
Cumulative actual costs under (over) the amount deducted – beginning of
period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actual costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Budgeted costs deducted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,242,998
(3,803,470)
2,800,000
$
588,742
(4,645,744)
5,300,000
$ (301,922)
(5,609,336)
6,500,000
Cumulative actual costs under (over) the amount deducted – end of period . . . . . .
$
239,528
$ 1,242,998
$
588,742
The monthly development cost deduction was $500,000 from the January 2013 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 and was maintained at that level through the August 2015 distribution. Due to the anticipated level of actual costs and the 2015
development budget, the development cost deduction was increased to $300,000 beginning with the September 2015 distribution and was maintained at
that level through the end of 2015. 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. Changes in oil or natural gas prices could impact future development plans on the underlying
properties. XTO Energy has advised the trustee that this monthly deduction will continue to be evaluated and revised as necessary. For further information on
2016 budgeted development costs, see Properties, under Item 2.
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.
31
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
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, 2015, the overhead charge was approximately
$1,059,000 ($847,200 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 $16.4 million for 2015, or 38% of total gas sales,
$30.4 million for 2014, or 38% of total gas sales and, $29.0 million for 2013, or 38% 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 addition to a reduction in the net profits going
forward). The three panel tribunal decided on April 21, 2014 that the settlement cannot be charged to the Trust, including the new royalty calculation for
future royalty payments. Additionally, XTO Energy had to reimburse $4,386,396, representing amounts withheld from the September and October 2012
distributions and $1,985,438, representing attorney fees, arbitration expenses and interest. The arbitration award was entered into as a final judgment in
State District Court of Tarrant County, Texas 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,
32
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
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.
The case was previously stayed pending a final decision from the Kansas Supreme Court on the Fawcett v. OPIK appeal. Following the decision in Fawcett, the
Judge in Roderick ordered new briefing on the pending motions. 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.
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. On September 5, 2014,
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 was added as counsel of record for Goebel in Sandra G. Goebel vs. XTO Energy, Inc., Timberland Gathering & Processing Company, Inc. and Bank of
America, N.A.
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 Energy
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. After dismissal as non-arbitrable, Goebel refiled the matter as a lawsuit styled Sandra G. Goebel vs. XTO
33
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Energy, Inc., Timberland Gathering and Processing Company, Inc. and Bank of America, N.A. in Dallas County District Court. After a series of pleadings, writ of
mandamus and court of appeals decision, the matter was finally dismissed with prejudice by the Dallas County District Court on October 12, 2015. Goebel
failed to appeal the final judgment. 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 anticipated that the Trust would incur additional legal and other expenses in connection with the Goebel lawsuit. As a result, the trustee
reserved $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 had previously reserved an
additional $1.6 million from trust distributions for the Lamb litigation, which was dismissed, and was included as 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. The Goebel
lawsuit was
dismissed on October 12, 2015. As a result, the trustee moved $750,000 of the remaining legal expense reserve to the administrative expense reserve and
the remaining balance of $601,920 was included in the November 2015 distribution to unitholders. The amounts distributed from the legal reserve are
treated as additional gross royalty income to the unitholders.
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.
When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under the SEC definition of
proved reserves, certain quantities of oil and natural gas may no longer qualify as proved reserves. Amounts required to be de-booked as proved reserves on an
SEC basis are subject to being re-booked as proved reserves at some point in the future when price levels recover.
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.
34
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 $2.10 per Mcf in 2015, $4.35 per Mcf in 2014, $3.92 per Mcf in
2013 and $3.21 per Mcf in 2012. Oil prices used to determine the standardized measure were based on average realized oil prices of $46.56 per Bbl in
2015, $92.70 per Bbl in 2014, $94.32 per Bbl in 2013 and $91.90 per Bbl in 2012.
Proved Reserves
(in thousands)
Underlying Properties
Oil (Bbls)
Gas (Mcf)
Net Profits Interests
Oil (Bbls)
Gas (Mcf)
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance, December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production – sales volumes
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
248,181
5
12,050
(18,713)
(50)
241,473
123
(13,981)
(17,427)
—
210,188
71
(90,561)
(15,736)
—
2,513
2
214
(217)
(27)
2,485
8
(70)
(204)
—
2,219
2
(841)
(194)
—
77,356
3
15,900
(7,770)
(15)
85,474
46
(1,353)
(8,004)
—
76,163
5
(59,389)
(2,292)
—
Balance, December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
103,962
1,186
14,487
875
1
200
(99)
(8)
969
3
(5)
(111)
—
856
—
(636)
(41)
—
179
Revisions of prior estimates of the proved gas reserves for the underlying properties in each year are primarily because of changes in the gas and oil
prices. Negative revisions for 2015 are primarily due to lower oil and gas 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.
35
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, 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
December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
102,683
1,178
14,411
806
878
767
178
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
2015
December 31
2014
2013
Underlying Properties
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future costs:
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$273,346
$1,119,099
$1,181,208
227,298
1,704
44,344
14,739
572,635
72,227
474,237
227,641
621,958
64,064
495,186
237,147
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 29,605
$ 246,596
$ 258,039
Net Profits Interests
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future production taxes
$ 38,668
3,192
$ 412,882
33,492
$ 431,190
35,041
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35,476
11,793
379,390
182,112
396,149
189,718
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 23,683
$ 197,278
$ 206,431
36
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
2015
2014
2013
Underlying Properties
Standardized measure, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 246,596
$258,039
$203,303
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(259,248)
(30,036)
21,887
60,798
(104)
(206,703)
16
(13,104)
2,800
—
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)
Net change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(216,991)
(11,443)
54,736
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 29,605
$246,596
$258,039
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 197,278
13
17,510
(182,874)
—
(8,244)
$206,431
301
17,671
17,321
—
(44,446)
$162,643
82
14,710
66,861
(531)
(37,334)
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 23,683
$197,278
$206,431
10. Quarterly Financial Data (Unaudited)
The following is a summary of net profits income, distributable income and distributable income per unit by quarter for 2015 and 2014:
2015
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter
37
Net Profits
Income
Distributable
Income
Distributable
Income per
Unit
$4,136,842
1,463,774
1,584,694
1,058,607
$3,766,000
1,185,720
1,347,240
1,454,280
$0.094150
0.029643
0.033681
0.036357
$8,243,917
$7,753,240
$0.193831
$ 9,290,470
16,484,703
10,323,706
8,347,594
$ 7,650,320
17,846,840
10,141,840
8,170,680
$ 0.191258
0.446171
0.253546
0.204267
$ 44,446,473
$ 43,809,680
$ 1.095242
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
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.
12. Purchaser Adjustment
XTO Energy advised the trustee that the February 2015 distribution included a one-time prior period adjustment for the recoupment of natural gas
liquids revenue from the Trust in the amount of $353,069 ($282,455 net to the Trust) which was deducted from net proceeds in the first quarter of 2015.
38
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, 2015. The effectiveness of the trust’s
internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report under Item 8, Financial Statements and Supplementary Data.
Changes in Internal Control Over Financial Reporting
There were no changes in the trust’s internal control over financial reporting during the quarter ended December 31, 2015 that have materially
affected, or are reasonably likely to materially affect, the trust’s internal control over financial reporting.
Item 9B. Other Information
None.
39
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, 2015.
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 2013 through 2015 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
$68,288
$63,343
—
2015
2014
2013
(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, 2015 was approximately $1,059,000 per month, or
$12,708,000 annually (net to the Trust of $847,200 per month or $10,166,400 annually), 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 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 2013 through 2015.
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.
40
Item 14. Principal Accountant Fees and Services
Fees for services performed by PricewaterhouseCoopers LLP for the years ended December 31, 2015 and 2014 are:
Audit fees-PwC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Audit-related fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax fees
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All other fees
2015
$143,190
—
—
—
2014
$140,850
—
—
—
$143,190
$140,850
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.
41
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, 2015 and 2014
Statements of Distributable Income for the years ended December 31, 2015, 2014 and 2013
Statements of Changes in Trust Corpus for the years ended December 31, 2015, 2014 and 2013
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.
42
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 SOUTHWEST BANK, TRUSTEE
By /S/ NANCY G. WILLIS
Nancy G. Willis
Vice President
EXXON MOBIL CORPORATION
By /S/ BETH E. CASTEEL
Beth E. Casteel
Vice President – Upstream Business Services
(The Trust has no directors or executive officers.)
Date: March 11, 2016
43
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
Dallas, Texas
Legal and Tax Counsel
Thompson & Knight LLP
Dallas, Texas
Transfer Agent and Registrar
American Stock Transfer and Trust Company LLC
www.amstock.com
Certification
The Trustee’s certification, required by Section 302 of the Sarbanes-Oxley Act of 2002, has been filed as
Exhibit 31 of the Trust’s Form 10-K, for the fiscal year ended December 31, 2015.
Hugoton Royalty Trust
Southwest Bank
P.O. Box 962020
Fort Worth, Texas 76162-2020
1-855-588-7839
www.hgt-hugoton.com