Hugoton Royalty Trust
2016
Annual Report and Form 10-K
Sales Price Distributions2016 High Low per UnitFirst Quarter $ 1.97 $ 0.98 $0.000000Second Quarter 2.60 1.25 0.000000Third Quarter 2.75 1.91 0.019798Fourth Quarter 2.75 1.90 0.026587 $0.0463852015First Quarter $ 8.49 $ 5.70 $0.094150Second Quarter 6.00 3.50 0.029643Third Quarter 3.55 2.50 0.033681Fourth Quarter 3.58 1.47 0.036357 $0.193831Glossary of TermsBbl Barrel (of oil)Bcf Billion cubic feet (of natural gas) BOE Barrel of oil equivalentMcf Thousand cubic feet (of natural gas)MMBtu One million British Thermal Units, a common energy measurementNet Proceeds Gross proceeds received by XTO Energy from sale of production from the underlying properties, less applicable costs, as defined in the net profits interest conveyances.Net Profits Income Net proceeds multiplied by the net profits percentage of 80%, which is paid to the Trust by XTO Energy. “Net profits income” is referred to as “royalty income” for tax reporting purposes.Net Profits Interest An interest in an oil and gas property measured by net profits from the sale of production, rather than a specific portion of production. The following defined net profits interests were conveyed to the Trust from the underlying properties: 80% net profits interests – interests that entitle the Trust to receive 80% of the net proceeds from the underlying properties.Underlying Properties XTO Energy’s interest in certain oil and gas properties from which the net profits interests were conveyed. The underlying properties include working interests in predominantly gas- producing properties located in Kansas, Oklahoma and Wyoming.Working Interest An operating interest in an oil and gas property that provides the owner a specified share of production that is subject to all production expense and development costs.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 2016 and 2015:At December 31, 2016, there were 40,000,000 units outstanding and approximately 644 unitholders of record; 39,392,323 of these units were held by depository institutions.Units of Beneficial Interest 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. Cumulative excess costs for the Kansas and Wyoming conveyances remaining as of December 31, 2016 totaled $2,207,806 ($1,766,245 net to the Trust). For further information on excess costs, see Note 4 to Financial Statements under Item 8, “Financial Statements and Supplementary Data” 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 2016 tax booklet for specific instructions. Unitholders should consult their tax advisors for further information.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.The Trust Years Ended December 31, 2016 2015 2014 2013 2012Net Profits Income .................... $ 2,617,640 $ 8,243,917 $ 44,446,473 $ 37,333,595 $ 25,132,038Distributable Income ................. 1,855,400 7,753,240 43,809,680 34,507,280 23,272,920Distributable Income per Unit .... 0.046385 0.193831 1.095242 0.862682 0.581823Distributions per Unit ................ 0.046385 0.193831 1.095242 0.862682 0.581823Total Assets at Year End ............. 28,143,303 88,185,111 93,920,959 102,501,095 112,956,689SummarySelected Financial Data To Unitholders:
We are pleased to present the 2016 Annual
Report on Form 10-K of the Hugoton
costs. For further information, see “Trustee’s
Discussion and Analysis of Financial
Royalty Trust as filed with the Securities and
Condition and Results of Operations” under
Exchange Commission. This report contains
Item 7 of the accompanying Form 10-K.
important information about the Trust’s net
XTO Energy is a party to legal
profits interests, including information provided
proceedings that may affect future Trust
to the trustee by XTO Energy.
distributions. For further information, see
For the year ended December 31, 2016,
Note 8 to Financial Statements under Item 8,
net profits income totaled $2,617,640.
“Financial Statements and Supplementary
After adding interest income of $43,242
Data” of the accompanying Form 10-K.
and deducting Trust administration expense
Natural gas prices averaged $2.09 per
of $805,482, distributable income was
Mcf for 2016, 23% lower compared to the
$1,855,400 or $0.046385 per unit. Net
2015 average price of $2.72 per Mcf. The
profits income and distributions were 68%
average 2016 oil price was $37.59 per Bbl,
and 76%, respectively, lower than 2015
25% lower compared to the 2015 average
amounts primarily because of lower oil and
price of $49.90 per Bbl.
gas prices, decreased oil and gas production,
Gas sales volumes from the underlying
and excess costs on the Kansas and Wyoming
properties for 2016 were 14,855,263 Mcf,
net profit interests in 2015, partially offset
or 40,588 Mcf per day, a decrease of 6%
by decreased production expense, lower
from 43,113 Mcf per day in 2015. Oil sales
overhead, decreased taxes, transportation
volumes from the underlying properties were
and other costs and lower development
179,259 Bbls, or 490 Bbls per day in 2016,
To Unitholders: Continued
a decrease of 8% from 533 Bbls per day
determined using an allocation formula, any
in 2015. For further information on sales
fluctuations in actual or assumed prices or
volumes and product prices, see “Trustee’s
costs will result in revisions to the estimated
Discussion and Analysis of Financial
reserve quantities allocated to the net profits
Condition and Results of Operations” under
interests. All reserve information prepared by
Item 7 of the accompanying Form 10-K.
independent engineers has been provided to
As of December 31, 2016, proved
the trustee by XTO Energy.
reserves for the underlying properties were
Estimated future net cash flows from
estimated by independent engineers to be
proved reserves of the net profits interests at
92.5 Bcf of natural gas and 1.1 million Bbls
December 31, 2015 were $9.6 million. Using
of oil. Natural gas reserves for the underlying
an annual discount factor of 10%, the present
properties declined 11.5 Bcf and oil reserves
value of estimated future net cash flows at
for the underlying properties declined
December 31, 2016 was $7.6 million. Proved
approximately 89,000 Bbls primarily due to
reserve estimates and related future net cash
current year production and lower oil and gas
flows have been determined based on a
prices used to estimate reserves, partially
12-month average gas price of $1.94 per Mcf
offset by lower year end costs used to
and a 12-month average oil price of $39.08
estimate reserves. Based on an allocation of
per Bbl, based on the first-day-of-the-month
these reserves, proved reserves attributable
price for each month in the period, and year
to the net profits interests were estimated to
end costs, including recovery of cumulative
be 4.2 Bcf of natural gas and 66,000 Bbls
excess costs remaining at year end. Other
of oil. Because Trust reserve quantities are
guidelines used in estimating proved reserves,
as prescribed by the Financial Accounting Standards Board, are described in Note 9 to Financial Statements under Item 8, “Financial Statements and Supplementary Data” of 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 the market value of Trust units.As disclosed in the tax instructions provided to unitholders in February 2017, Trust distributions are considered portfolio income, rather than passive income. Unitholders should consult their tax advisors for further information.Hugoton Royalty Trust By: Southwest Bank, TrusteeBy: Nancy G. Willis Vice PresidentMarch 10, 2017To Unitholders: Continued 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, 2016
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.
Yes ‘ No Í
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes ‘ No Í
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes Í No ‘
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files).
Yes ‘ No ‘
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will
not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. Í
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the
definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):
Large accelerated filer ‘
Accelerated filer Í
Non-accelerated filer ‘
(Do not check if 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, 2016
(the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $94 million.
At February 15, 2017, 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
2016 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
Page
Glossary of Terms
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
Part I
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1.
Item 1A.
Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 3.
Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4.
Part II
Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units . . . . . . . . . . . . . . .
Item 5.
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 6.
Item 7.
Trustee’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . .
Item 7A. Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 8.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . .
Item 9.
Item 9A.
Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part III
Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 11.
Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters . . . . . .
Item 13. Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . . . . . . . .
Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 14.
Item 15.
Part IV
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2
3
7
7
18
18
19
19
20
27
28
45
45
45
46
46
46
46
47
48
HUGOTON ROYALTY TRUST
GLOSSARY OF TERMS
The following are definitions of significant terms used in this Annual Report on Form 10-K:
Bbl
Bcf
BOE
Mcf
MMBtu
net proceeds
net profits income
net profits interest
Barrel (of oil)
Billion cubic feet (of natural gas)
Barrel of oil equivalent
Thousand cubic feet (of natural gas)
One million British Thermal Units, a common energy measurement
Gross proceeds received by XTO Energy from sale of production from the underlying
properties, less applicable costs, as defined in the net profits interest conveyances.
Net proceeds multiplied by the net profits percentage of 80%, which is paid to the Trust
by XTO Energy. “Net profits income” is referred to as “royalty income” for tax reporting
purposes.
An interest
in an oil and gas property measured by net profits from the sale of
production, rather than a specific portion of production. The following defined net profits
interests were conveyed to the Trust from the underlying properties:
80% net profits interests - interests that entitle the Trust to receive 80% of the net
proceeds from the underlying properties.
underlying properties
XTO Energy’s interest in certain oil and gas properties from which the net profits interests
were conveyed. The underlying properties include working interests in predominantly
gas-producing properties located in Kansas, Oklahoma and Wyoming.
working interest
An operating interest in an oil and gas property that provides the owner a specified
share of production that is subject to all production expense and development costs.
1
Item 1. Business
PART I
Hugoton Royalty Trust (the “Trust”) is an express trust created under the laws of Texas pursuant to the Hugoton Royalty
Trust Indenture entered into on December 1, 1998 between XTO Energy Inc. (formerly known as Cross Timbers Oil
Company), as grantor, and NationsBank, N.A., as trustee. On January 9, 2014, the successor of NationsBank, N.A., U.S.
Trust, Bank of America Private Wealth Management, a division of Bank of America, N.A., gave notice to 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.
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).
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. For further information on
excess costs, see Note 4 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
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
future net profits income payable to the Trust will be reduced until the overpayment, plus interest at the prime rate, is
recovered.
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 to
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 73% of the net profits income received by the Trust during 2016 was attributable to natural gas, as well
as 76% of the Trust’s estimated future net cash flows from proved reserves at December 31, 2016 (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). 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. 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
3
market price of the Trust units is not necessarily indicative of the value that the Trust would realize if the net profits interests
were sold to a third party buyer. In addition, such market price is not necessarily reflective of the fact that, since the assets
of the Trust are depleting assets, a portion of each cash distribution paid on the Trust units should be considered by
investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that
distributions made to a unitholder over the life of these depleting assets will equal or exceed the purchase price paid by the
unitholder.
Oil and natural gas prices fluctuate due to a number of uncontrollable factors, and any decline will adversely affect the
net proceeds payable to the Trust and Trust distributions.
The Trust’s monthly cash distributions are highly dependent upon the prices realized from the sale of natural gas and,
to a lesser extent, oil. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of
factors that are beyond the control of the Trust and XTO Energy. Factors that contribute to price fluctuations include
instability in oil-producing regions, worldwide economic conditions, weather conditions, the supply 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, the Trust will not receive net profits
income for those properties until future net 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.
4
Operational risks and hazards associated with the development of the underlying properties may decrease Trust
distributions.
There are operational risks and hazards associated with the production and transportation of oil and natural gas,
including without limitation natural disasters, blowouts, explosions, fires, leakage of oil or natural gas, releases of other
hazardous materials, mechanical failures, cratering, and pollution. Any of these or similar occurrences could result in the
interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or
equipment, damage to the environment or natural resources, or cleanup obligations. The operation of oil and gas properties
is also subject to various laws and regulations. Non-compliance with such laws and regulations could subject the operator
to additional costs, sanctions or liabilities. The uninsured costs resulting from any of the above or similar occurrences could
be deducted as a production expense or development cost in calculating the net proceeds payable to the Trust, and would
therefore reduce Trust distributions by the amount of such uninsured costs.
Future net profits 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 exposure to credit markets. The Trust’s future net profits, 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.
5
XTO Energy may transfer its interest in the underlying properties without the consent of the Trust or the Trust
unitholders.
XTO Energy may at any time transfer all or part of its interest in the underlying properties to another party. Neither the
Trust nor the Trust unitholders are entitled to vote on any transfer of the properties underlying the Trust’s net profits interests,
and the Trust will not receive any proceeds of any such transfer. Following any transfer, the transferred property will continue
to be subject to the net profits interests of the Trust, but the calculation, reporting and remitting of net proceeds to the Trust
will be the responsibility of the transferee.
XTO Energy or any other operator of any underlying property may abandon the property, thereby terminating the related
net profits interest payable to the Trust.
XTO Energy or any other operator of the underlying properties, or any transferee thereof, may abandon any well or
property without the consent of the Trust or the Trust unitholders if they reasonably believe that the well or property can no
longer produce in commercially economic quantities. This could result in the termination of the net profits interest relating to
the abandoned well or property.
The net profits interests can be sold and the Trust would be terminated. The Trust 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.
6
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:
• reduced 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.
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. 14-18 and
“Greenhouse Gas Emissions and Climate Change Regulations” on p. 24-25.
Item 1B. Unresolved Staff Comments
As of December 31, 2016, 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
7
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, 2016 is approximately 8 years. This
index is calculated using total proved reserves and estimated 2017 production for the underlying properties. The projected
2017 production is from proved developed producing reserves as of December 31, 2016. 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 future net cash flows from proved reserves of the underlying properties are approximately 76% natural gas and 24% oil.
XTO Energy operates approximately 94% 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 2016 development costs deducted for the underlying properties were $1.7 million, a
decrease of 40% from the prior year. XTO Energy has informed the trustee that total 2017 budgeted development costs for
the underlying properties are between $2 million and $4 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
2016, daily sales volumes from the underlying properties in the Hugoton area averaged approximately 10,500 Mcf of gas
and 37 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.
Within this area, XTO Energy did not drill any wells but did perform 5 workovers in 2016. XTO Energy has informed the
trustee that it does not plan to drill any new wells but may perform up to 9 workovers during 2017.
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
8
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 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. Under this contract DCP is entitled to
charge a processing fee of $0.25 and a helium processing fee of $0.05 per Delivery Point MMBtu in addition to other
deductions such as for fuel and transportation. XTO Energy has exercised its contractual right to take in kind and sell its
NGLs and helium. XTO Energy sells 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 sells 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 18,500 Mcf of gas and 429 Bbls of oil in 2016.
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 21 workovers in 2016. XTO Energy
has informed the trustee that it does not plan to drill any new wells but may perform up to 20 workovers in Major County
during 2017.
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 1 workover in 2016. 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 2017.
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 12 workovers in 2016. XTO Energy has informed the trustee that it does not
plan to drill any new wells but may perform up to 10 workovers within the Elk City field during 2017.
9
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 2016, 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 2016 sales volumes from the underlying properties in the Fontenelle field averaged 11,600 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 2016. 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
2017. XTO Energy has advised the trustee that it is continuing its efforts to reduce pipeline pressure which has shown
potential for increasing production and extending field life in the Fontenelle Field.
Potential development activities for the underlying properties in this area include:
• installing artificial lift,
• restimulating producing intervals utilizing new technology,
• additional compression to lower line pressures, and
• opening new producing zones in existing wells.
XTO Energy markets the gas produced from the Fontenelle field and nearby properties under various marketing
arrangements. Under the agreement covering the majority of the gas sold, XTO Energy compresses the gas on the lease,
10
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 2016, the fuel charge was 1% of the volumes produced and the processing
fee was approximately $0.12 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, 2016. Undeveloped acreage is not significant.
Hugoton Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 206,690 193,386
Anadarko Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 161,968 125,115
26,254
Green River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35,237
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 403,895 344,755
Gross
Net
The following is a summary of the producing wells on the underlying properties as of December 31, 2016:
Operated
Wells
Nonoperated
Wells
Total
Gross
Net
Gross
Net
Gross
Net
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,165.0 1,034.7 254.0 56.2 1,419.0 1,090.9
39.5
Oil
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
42.0
39.1
44.0
2.0
0.4
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,207.0 1,073.8 256.0 56.6 1,463.0 1,130.4
During 2016, 2015 and 2014 there were no wells drilled on the underlying properties. There were no wells in process
of drilling at December 31, 2016.
11
Estimated Proved Reserves and Future Net Cash Flows
The following are proved reserves of the underlying properties, as estimated by independent engineers, and proved
reserves and future net cash flows from proved reserves of the net profits interests, based on an allocation of these
reserves, at December 31, 2016:
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)
Undiscounted
Discounted
(in thousands)
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66,594
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,136
5,738
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,034
30
33
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92,468
1,097
4,167
—
—
4,167
66
—
—
66
$9,608
—
—
$9,608
$7,628
—
—
$7,628
(a) Based on 12-month average oil price of $39.08 per Bbl and $1.94 per Mcf for gas, based on the first-day-of-the-
month price for each month in the period.
(b) Since the Trust has defined net profits interests, the Trust does not own a specific percentage of the oil and gas
reserves. Oil and gas reserves are allocated to the net profits interests by dividing Trust net cash inflows by 12-month
average oil and gas prices. As such, reserves allocated to the Trust have been reduced to reflect recovery of the Trust’s
portion of applicable production and development costs, which includes overhead and excess costs. Any conveyance
where costs exceed revenues will result in zero allocated net profits interests reserves for that conveyance.
(c) Before income taxes, since future net cash flows are not subject to taxation at the trust level. Future net cash flows are
discounted at an annual rate of 10%.
Proved reserves at December 31, 2016 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
91,734
734
Total proved reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
92,468
1,097
—
1,097
4,167
—
4,167
66
—
66
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 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, 2016, 2015, 2014 and 2013. Miller and Lents’ primary technical person
responsible for calculating the Trust’s reserves has more than 25 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
12
attributable to the net profits interests. Numerous uncertainties are inherent in estimating reserve volumes and values, and
such estimates are subject to change as additional information becomes available. The reserves actually recovered and the
timing of production of these reserves may be substantially different from the original estimates.
Reserve quantities and revenues for the net profits interests were estimated from projections of reserves and revenues
attributable to the underlying properties. Since the Trust has defined net profits interests, the Trust does not own a specific
percentage of the oil and gas reserves. Oil and gas reserves are allocated to the net profits interests by dividing Trust net
cash inflows by 12-month average oil and gas prices.
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 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 such, the underlying property production volume changes may not correlate with the Trust’s net profit
share of those volumes in any given period.
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:
2016
2015
2014
Production
Underlying Properties
Gas – Sales (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average per day (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . .
Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average per day (Bbls) . . . . . . . . . . . . . . . . . . . . . . . .
14,855,263
40,588
179,259
490
15,736,066
43,113
194,381
533
17,426,780
47,745
203,667
558
Net Profits Interests
Gas – Sales (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average per day (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . .
Oil – Sales (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average per day (Bbls) . . . . . . . . . . . . . . . . . . . . . . . .
1,095,601
2,993
18,367
50
2,292,205
6,280
40,817
112
8,004,435
21,930
110,515
303
Average Sales Price
Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average Production Cost per BOE . . . . . . . . . . . . . . . . . . . . .
$ 2.09
$37.59
$10.24
$ 2.72
$49.90
$11.87
$ 4.60
$95.35
$10.89
13
Oil and gas production by conveyance attributable to the underlying properties for each of the three years ended
December 31 were as follows:
Conveyance
Underlying Gas Production (Mcf)
2015
2016
2014
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,169,372
9,443,712
4,242,179
1,267,647
9,933,308
4,535,111
1,531,314
11,255,819
4,639,647
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14,855,263
15,736,066
17,426,780
Conveyance
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Underlying Oil Production (Bbls)
2015
2016
2014
7,004
163,679
8,576
179,259
5,938
180,129
8,314
194,381
7,023
188,911
7,733
203,667
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.
14
Federal Regulation of Oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The
net price received from the sale of these products is affected by market transportation costs. Under rules adopted by FERC
effective January 1995, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms
may be used in specific circumstances.
On December 19, 2007,
the President signed into law the Energy Independence & Security Act of 2007
(PL 110-140). The EISA, among other things, prohibits market manipulation by any person in connection with the purchase
or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the
Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes
penalties for violations thereunder. XTO Energy has advised the trustee that it cannot predict the impact of
future
government regulation on any crude oil, condensate or natural gas liquids facilities, sales or transportation transactions.
Environmental Regulation
Companies that are engaged in the oil and gas industry are affected by federal, state and local laws regulating the
discharge of materials into the environment. Those laws may impact operations of the underlying properties. No material
expenses have been incurred on the underlying properties in complying with environmental laws and regulations. XTO Energy
does not expect that future compliance will have a material adverse effect on the Trust.
There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions
and climate change. Several states have adopted climate change legislation and regulations, and various other regulatory
bodies have announced their intent to regulate GHG emissions or adopt climate change regulations. As these regulations
are under development, XTO Energy is unable to predict the total impact of the potential regulations upon the operators of
the underlying properties, and it is possible that operators of the underlying properties could face increases in operating
costs in order to comply with climate change or GHG emissions legislation, which costs could reduce net proceeds payable
to the Trust and Trust distributions.
State Regulation
The various states regulate the production and sale of oil and natural gas, including imposing requirements for
obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of
waste of oil and gas 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. Impairment for book purposes
will not result in a loss for tax purposes for the unitholders until the loss is recognized.
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 2016,
income on funds held for
distribution and for the cash reserve maintained for the payment of contingent and future obligations of the Trust.
incurred administration expenses and earned interest
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
15
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 investment income from all
investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels
depending on such individual’s federal income tax filing status. In the case of an estate or trust, the tax is imposed on the
lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which
the highest income tax bracket applicable to an estate or trust begins.
The 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; (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; and (iv) items that constitute taxable income due to the recovery of prior
period expense adjustments. Because of these types of items and when the trustee elects to reserve amounts from monthly
distributions to maintain an administrative expense reserve, the taxable income per period frequently differs from the actual
amount distributed to unitholders, including in 2016.
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.
16
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
income tax purposes. Southwest Bank, EIN: 75-1105980, Post Office Box
investment trust (“WHFIT”) for U.S. federal
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 is not taxed at the trust level in Kansas or
Oklahoma. While the Trust does not owe tax, the trustee is required to file a return with Oklahoma reflecting the income and
deductions of the Trust attributable to properties located in the 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. Oklahoma also imposes 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).
Kansas also taxes the income of nonresidents from property located within the state. However, the Trust will not file a
return for the 2016 tax year because the Trust had no revenues, income or deductions in 2016 attributable to properties
located in Kansas. The Trust did not file a return with Kansas for the 2015 tax year for the same reason.
Wyoming does not have a state income tax.
Each unitholder should consult his or her own tax advisor regarding state income tax requirements, if any, applicable
to such person’s ownership of Trust units.
State Tax Withholding
Several states have enacted legislation requiring state income tax withholding from nonresident recipients of oil and
gas proceeds. After consultation with its tax counsel, the trustee believes that it is not required to withhold on payments
made to the unitholders. However, regulations are subject to change by the various states, which could change this
conclusion. Should amounts be withheld on payments made to the Trust or the unitholders, distributions to the unitholders
would be reduced by the required amount, subject to the filing of a claim for refund by the Trust or unitholders for such
amount.
17
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
leases. Neither of these changes have had a
the underlying properties, primarily located in Wyoming, involve federal
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
For information on legal proceedings, see Note 8 to Financial Statements under Item 8, Financial Statements and
Supplementary Data.
Item 4. Mine Safety Disclosures
Not Applicable.
18
Item 5. Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units
Units of Beneficial Interest
PART II
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 2016 and 2015:
Quarter
Sales Price
High
Low
Distributions
per Unit
2016
First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1.97
2.60
2.75
2.75
$0.98
1.25
1.91
1.90
2015
First . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$8.49
6.00
3.55
3.58
$5.70
3.50
2.50
1.47
$0.000000
0.000000
0.019798
0.026587
$0.046385
$0.094150
0.029643
0.033681
0.036357
$0.193831
At December 31, 2016, there were 40,000,000 units outstanding and approximately 644 unitholders of record;
39,392,323 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
2016
2015
2014
2013
2012
Year Ended December 31
Net Profits Income . . . . . . . . . . . . . . . . . . . $ 2,617,640 $ 8,243,917 $44,446,473 $ 37,333,595 $ 25,132,038
23,272,920
Distributable Income . . . . . . . . . . . . . . . . .
0.581823
Distributable Income per Unit . . . . . . . . . . .
0.581823
Distributions per Unit . . . . . . . . . . . . . . . . .
112,956,689
Total Assets at Year-End . . . . . . . . . . . . . . .
34,507,280
0.862682
0.862682
102,501,095
1,855,400
0.046385
0.046385
28,143,303
43,809,680
1.095242
1.095242
93,920,959
7,753,240
0.193831
0.193831
88,185,111
19
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)
2015
2016
Three Months Ended December 31(a)
2014
2016
2015
Sales Volumes
Gas (Mcf)(b)
Underlying properties . . . . . . . . . . .
Average per day . . . . . . . . . . . .
Net profits interests . . . . . . . . . . . .
14,855,263
40,588
1,095,601
15,736,066
43,113
2,292,205
17,426,780
47,745
8,004,435
3,591,313
39,036
388,766
4,123,283
44,818
359,172
Oil (Bbls)(b)
Underlying properties . . . . . . . . . . .
Average per day . . . . . . . . . . . .
Net profits interests . . . . . . . . . . . .
Average Sales Prices
Gas (per Mcf) . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . .
Oil (per Bbl)
Revenues
179,259
490
18,367
$2.09
$37.59
194,381
533
40,817
$2.72
$49.90
203,667
558
110,515
$4.60
$95.35
39,906
434
6,162
$2.74
$43.06
46,285
503
5,839
$2.58
$41.32
Gas sales . . . . . . . . . . . . . . . . . . . . . $31,025,713 $42,864,131 $80,236,274 $ 9,826,058 $10,657,373
1,912,652
Oil sales . . . . . . . . . . . . . . . . . . . . . .
19,419,502
6,737,833
1,718,212
9,699,090
Total Revenues . . . . . . . . . . . . . . .
37,763,546
52,563,221
99,655,776
11,544,270
12,570,025
Costs
. . . . .
Taxes, transportation and other
Production expense . . . . . . . . . . . . . .
Development costs(c) . . . . . . . . . . . . .
Overhead . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . .
Legal Expense(e)
Excess costs(d) . . . . . . . . . . . . . . . . . .
6,284,951
16,762,302
1,675,000
10,355,802
—
(586,559)
7,554,245
20,898,895
2,800,000
12,542,488
—
(1,537,304)
10,523,008
21,683,844
5,300,000
12,156,711
(5,482,995)
(82,883)
1,640,684
4,135,755
600,000
2,889,156
—
902,381
2,057,074
5,369,131
900,000
3,196,465
—
(275,904)
Total Costs . . . . . . . . . . . . . . . . . .
34,491,496
42,258,324
44,097,685
10,167,976
11,246,766
Net Proceeds . . . . . . . . . . . . . . . . . . . .
Net Profits Percentage . . . . . . . . . . . . .
3,272,050
80%
10,304,897
80%
55,558,091
80%
1,376,294
80%
1,323,259
80%
Net Profits Income . . . . . . . . . . . . . . . . $ 2,617,640 $ 8,243,917 $44,446,473 $ 1,101,035 $ 1,058,607
(a) Because of the two-month interval between time of production and receipt of net profits income by the Trust: 1) oil
and gas sales for the year ended December 31 generally relate to twelve months of production for the period
November through October, and 2) oil and gas sales for the three months ended December 31 generally relate to
production for the period August through October.
(b) Oil and gas sales volumes are allocated to the net profits interests by dividing Trust net cash inflows by average sales
prices. As oil and gas prices change, the Trust’s allocated production volumes are impacted as the quantity of
production necessary to cover expenses changes inversely with price. As such, the underlying property production
volume changes may not correlate with the Trust’s allocated production volumes in any given period. Therefore,
comparative discussion of oil and gas sales volumes is based on the underlying properties.
(c) See Note 5 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
(d) See Note 4 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
(e) See Note 8 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
20
Results of Operations
Years Ended December 31, 2016, 2015 and 2014
Net profits income for 2016 was $2,617,640, as compared with $8,243,917 for 2015 and $44,446,473 for 2014.
The 68% decrease in net profits income from 2015 to 2016 is primarily the result of lower oil and gas prices ($9.9 million),
decreased oil and gas production ($1.9 million), and excess costs on the Kansas and Wyoming net profit interests in 2015
($0.8 million), partially offset by decreased production expense ($3.3 million), lower overhead ($1.7 million), decreased
taxes, transportation and other costs ($1.0 million) and lower development costs ($0.9 million). 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). Approximately 73% in 2016, 76% in 2015 and 78% in
2014 of net profits income was derived from natural gas sales.
Trust administration expense was $805,482 in 2016 as compared to $842,810 in 2015 and $1,024,542 in 2014.
Net cash reserve activity was $0 in 2016 as compared to a reduction of $351,920 in 2015 and additions of $129,382 in
2014. Reductions to the cash reserve during the first half of 2016 for the payment of Trust expenses were offset by the
increase to the reserve in July 2016, which fully replenished the reserve to the $1,000,000 level. Cash reserve activity for
2015 included additions of $250,000 which the trustee reserved for administrative expenses, offset by a refund of
$601,920 which represents the remaining balance of
reserve that was included in the November 2015
distribution. Cash reserve activity for 2014 included $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. Interest income was $43,242 in
2016, $213 in 2015 and $517,131 in 2014. Interest income for 2016 included $42,291 related to a one-time prior
period revenue adjustment and 2014 included $514,820 related to the arbitration reimbursement. Other changes in
rates. Distributable income was
interest
$1,855,400 or $0.046385 per unit
in 2015 and $43,809,680 or
$1.095242 per unit in 2014.
income are attributable to fluctuations in net profits income and interest
in 2016, $7,753,240 or $0.193831 per unit
the legal
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 2015 to 2016, underlying gas sales volumes decreased 6% primarily due to natural production decline,
partially offset by completion of repairs and maintenance at a third party gas processing system in the Hugoton area
following a force majeure incident. 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.
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
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. 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.
Oil.
From 2015 to 2016, underlying oil sales volumes decreased 8% primarily due to natural production decline.
From 2014 to 2015, underlying oil sales volumes decreased 5% primarily due to natural production decline.
21
The estimated rate of natural production decline on the underlying oil and gas properties is approximately 6% to 8% a
year.
Prices
Gas.
The 2016 average gas price was $2.09 per Mcf, a 23% decrease from the 2015 average gas price of $2.72
per Mcf, which was a 41% decrease from the 2014 average gas price of $4.60 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 2016 through January 2017 was $3.31 per MMBtu. At March 1, 2017, the average NYMEX gas price for the
following 12 months was $3.13 per MMBtu.
Oil.
The average oil price for 2016 was $37.59 per Bbl, a 25% decrease from the average oil price for 2015 of
$49.90 per Bbl, which was a 48% decrease from the average oil price for 2014 of $95.35 per Bbl. Oil prices are expected
to remain volatile. The average NYMEX price for November 2016 through January 2017 was $50.19 per Bbl. At March 1,
2017, the average NYMEX oil price for the following 12 months was $54.78 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.
Taxes, transportation and other.
Taxes, transportation and other generally fluctuates with changes in total revenues.
Taxes, transportation and other decreased 17% from 2015 to 2016 primarily because of decreased production and property
taxes related to lower oil and gas revenues, partially offset by increased gas deductions related to increased gathering fees.
For further information on gathering fees, see Note 12 to Financial Statements under Item 8, Financial Statements and
Supplementary Data. 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.
Production expense.
Production expense decreased 20% from 2015 to 2016 primarily because of decreased repairs
and maintenance, labor, water disposal, compression and field costs. 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.
Development costs. Development costs, which were deducted based on budgeted development costs, were $1.7
million in 2016, $2.8 million in 2015 and $5.3 million in 2014. In 2016, actual development costs were $1.9 million. At
December 31, 2016, cumulative budgeted costs deducted exceeded cumulative actual costs by approximately $56,000.
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 development costs, see Note 5 to Financial
Statements under Item 8, Financial Statements and Supplementary Data.
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. Overhead decreased 17% from 2015 to 2016, primarily due to
operated overhead corrections in 2016. For
information on overhead corrections, see Note 11 to Financial
Statements under Item 8, Financial Statements and Supplementary Data.
further
Excess costs.
accrued interest,
If monthly costs exceed revenues for any conveyance, these excess costs must be recovered, with
from future net proceeds of that conveyance and cannot reduce net profits income from another
22
conveyance. Cumulative excess costs for the Kansas and Wyoming conveyances remaining as of December 31, 2016
totaled $2,207,806 ($1,766,245 net to the Trust). For further information on excess costs, see Note 4 to Financial
Statements under Item 8, Financial Statements and Supplementary Data.
Legal Expense.
As a result of the Fankhouser 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 2016 and 2015
During fourth quarter 2016 the Trust received net profits income totaling $1,101,035 compared with fourth quarter
2015 net profits income of $1,058,607. This 4% increase in net profits income was primarily due to decreased production
expense ($1.0 million), higher oil and gas prices ($0.6 million), decreased taxes, transportation and other costs ($0.3
million), lower overhead ($0.2 million) and decreased development costs ($0.2 million), partially offset by decreased oil
and gas production ($1.4 million) and excess costs activity ($0.9 million).
After adding interest income of $42,698 and deducting administration expense of $80,253, distributable income for
fourth quarter 2016 was $1,063,480 or $0.026587 per unit. Interest income included $42,291 related to a one-time prior
period revenue adjustment. Distributable income for fourth quarter 2015 was $1,454,280 or $0.036357 per unit. The
fourth quarter 2015 distribution included a refund of $601,920 which represents the remaining balance of the legal reserve
that was included in the November 2015 distribution.
Distributions to unitholders for the quarter ended December 31, 2016 were:
Record Date
Payment Date
October 31, 2016
November 30, 2016
December 30, 2016
November 15, 2016
December 14, 2016
January 17, 2017
Per Unit
$0.009194
0.010948
0.006445
$0.026587
Volumes
Fourth quarter underlying gas sales volumes decreased 13% from 2015 to 2016 primarily due to natural production
decline, repairs and maintenance at a third party gas processing system in the Hugoton area and the timing of cash
receipts. Underlying oil sales volumes decreased 14% from 2015 to 2016 primarily due to natural production decline and
the timing of cash receipts.
XTO Energy advised the trustee that repairs and maintenance at a third party gas processing system in the Hugoton
area resulted in decreased underlying gas volumes of approximately 4,000 Mcf per day for the month of October 2016. The
third party notified XTO Energy that maintenance was completed by the end of October.
Prices
The average fourth quarter 2016 gas price was $2.74 per Mcf, or 6% higher than the fourth quarter 2015 average
price of $2.58 per Mcf. The average fourth quarter 2016 oil price was $43.06 per Bbl, or 4% higher than the fourth quarter
2015 average price of $41.32 per Bbl. For further information about product prices, see “Years Ended December 31, 2016,
2015 and 2014 – Prices” above.
Costs
Taxes, transportation and other. Taxes, transportation and other decreased 20% from fourth quarter 2015 to 2016
primarily because of decreased production and property taxes and other deductions related to lower oil and gas revenues.
23
Production expense. Fourth quarter production expense decreased 23% from 2015 to 2016 primarily because of
decreased repairs and maintenance, labor, compression and fuel costs.
Development costs. Development costs, which were deducted based on budgeted development costs, decreased 33%
from fourth quarter 2015 to 2016. For further information on development costs, see Note 5 to Financial Statements under
Item 8, Financial Statements and Supplementary Data.
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. Overhead decreased 10% from fourth quarter 2015 to 2016 due to
operated overhead corrections in 2016. For
information on overhead corrections, see Note 11 to Financial
Statements under Item 8, Financial Statements and Supplementary Data.
further
Excess costs. If monthly costs exceed revenues for any conveyance, these excess costs must be recovered, with
accrued interest,
from future net proceeds of that conveyance and cannot reduce net profits income from another
conveyance. For information on excess costs, see Note 4 to Financial Statements under Item 8, Financial Statements and
Supplementary Data.
Impairment of Net Profits Interest
In light of lower long term prices used to develop projections of future cash flows, continued excess costs on two
conveyances and zero distributions to unitholders for the six months ended June 30, 2016, the trustee concluded in the
second quarter of 2016 that the events or circumstances indicated the carrying value may not be recoverable and an
assessment of the forecasted net cash flows was performed for the NPI. The fair value of the NPI was developed using
estimates for future oil and gas production attributable to the Trust, future crude oil and natural gas commodity prices
published by third-party industry experts (adjusted for basis differentials), estimated taxes, development and operating
expenses, and a risk-adjusted discount rate. The result of the assessment indicated that the estimated undiscounted future
net cash flows from the NPI were below the carrying value of the NPI. The NPI was written down to its fair value of $28.8
million, resulting in a $57.3 million impairment charged directly to Trust corpus, which did not affect distributable income.
There have been no events or changes in circumstances to indicate the carrying value of the NPI may not be recoverable,
and there is no further impairment of the assets as of December 31, 2016.
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.
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
24
bodies have announced their intent to regulate GHG emissions or adopt climate change regulations. The climate accord
reached at the 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, 2016, other than the December distribution payable to unitholders in January 2017, as reflected in the
statement of assets, liabilities and trust corpus.
Payments due by Period
Total
Less than
1 Year
1 - 3 Years
3 - 5 Years
More than
5 Years
Distribution payable to unitholders . . . . . . . . . . . . . . . . . . . . . $257,800 $257,800
$—
$—
$—
Related Party Transactions
The underlying properties from which the net profits interests were carved are currently owned by XTO Energy, which
operates approximately 94% 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,
2016, the monthly overhead charge, based on the number of operated wells, was approximately $964,000 ($771,200 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 the 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 $15.0 million for 2016, or 48% of total gas sales, $16.4 million for 2015, or 38% of total gas
sales and $30.4 million for 2014, 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
25
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 of Net Profits Interest
The trustee reviews the Trust’s net profits interests (“NPI”) in oil and gas properties for impairment whenever events or
circumstances indicate that the carrying value of the NPI may not be recoverable. In general, the trustee does not view
temporarily low prices as an indication of impairment. The markets for crude oil and natural gas have a history of significant
price volatility and though prices will occasionally drop significantly, industry prices over the long term will continue to be
driven by market supply and demand. If events and circumstances indicated that the carrying value may not be recoverable,
the trustee would use the estimated undiscounted future net cash flows from the NPI to evaluate the recoverability of the
Trust assets. If the undiscounted future net cash flows from the NPI are less than the NPI carrying value, the Trust would
recognize an impairment loss for the difference between the NPI carrying value and the estimated fair value of the NPI. The
determination as to whether the NPI is impaired requires a significant amount of judgment by the trustee and is based on
the best information available to the trustee at the time of the evaluation.
In light of lower long term prices used to develop projections of future cash flows, continued excess costs on two
conveyances and zero distributions to unitholders for the six months ended June 30, 2016, the trustee concluded in the
second quarter of 2016 that the events or circumstances indicated the carrying value may not be recoverable and an
assessment of the forecasted net cash flows was performed for the NPI. The fair value of the NPI was developed using
estimates for future oil and gas production attributable to the Trust, future crude oil and natural gas commodity prices
published by third-party industry experts (adjusted for basis differentials), estimated taxes, development and operating
expenses, and a risk-adjusted discount rate. The result of the assessment indicated that the estimated undiscounted future
net cash flows from the NPI were below the carrying value of the NPI. The NPI was written down to its fair value of $28.8
million, resulting in a $57.3 million impairment charged directly to Trust corpus, which did not affect distributable income.
There have been no events or changes in circumstances to indicate the carrying value of the NPI may not be recoverable,
and there is no further impairment of the assets as of December 31, 2016.
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.
26
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, including recovery of cumulative excess
costs remaining at year end. 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.
financial and operational results may differ materially from expectations, estimates or assumptions
Therefore, actual
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. The Trust does not engage in
transactions in foreign currencies which could expose the Trust to any foreign currency related market risk.
27
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
29
30
30
31
32
All financial statement schedules are omitted as they are inapplicable or the required information has been included in
the consolidated financial statements or notes thereto.
28
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, 2016 and 2015, and the related statements of distributable income and changes in trust
corpus for each of the three years in the period ended December 31, 2016. We also have audited the Trust’s internal
control over financial reporting as of December 31, 2016, based on criteria established in Internal Control — Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trustee
is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its
assessment of the effectiveness of internal control over financial reporting, included in the Trustee’s Report on Internal
Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial
statements and on the Trust’s internal control over financial reporting based on our integrated audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement and whether effective internal control over financial reporting was
maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and
significant estimates made by the trustee, and evaluating the overall financial statement presentation. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the
risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control
based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our opinions.
As described in Note 2, these financial statements were prepared on the modified cash basis of accounting, which is a
comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
A trust’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A trust’s internal control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the trust; (ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and
that receipts and expenditures of the trust are being made only in accordance with authorizations of the trustee; and
(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of
the trust’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities
and trust corpus of the Trust at December 31, 2016 and 2015, and the distributable income and changes in trust corpus
for each of the three years in the period ended December 31, 2016, on the basis of accounting described in Note 2. Also in
our opinion,
reporting as of
December 31, 2016, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
respects, effective internal control over
the Trust maintained,
in all material
financial
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
March 10, 2017
29
HUGOTON ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
Assets
Cash and short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,257,800 $ 1,284,880
Net profits interests in oil and gas properties – net
(Notes 1 and 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
26,885,503
86,900,231
$28,143,303 $88,185,111
December 31
2016
2015
Liabilities and Trust Corpus
Distribution payable to unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Expense reserve(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding) . . .
1,000,000
26,885,503
257,800 $
284,880
1,000,000
86,900,231
(a)
The expense reserve allows the trustee to pay its obligations should it be unable to pay them out of the net profits
income. The reserve is fully funded at $1,000,000.
$28,143,303 $88,185,111
STATEMENTS OF DISTRIBUTABLE INCOME
Year Ended December 31
2015
2014
2016
Net profits income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,617,640 $8,243,917 $44,446,473
517,131
Interest income(a)(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
43,242
213
Total income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Administration expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash reserves withheld (used) for Trust expenses(a) . . . . . . . . . . . . . . . . . . . .
2,660,882
805,482
—
8,244,130
842,810
(351,920)
44,963,604
1,024,542
129,382
Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,855,400 $7,753,240 $43,809,680
Distributable income per unit (40,000,000 units)
. . . . . . . . . . . . . . . . $ 0.046385 $ 0.193831 $ 1.095242
(a) Cash reserves 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 cash
reserves 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 the financial statements.
Interest income for the period ended December 31, 2016, includes $42,291 related to a one-time prior period
revenue adjustment.
(b)
30
STATEMENTS OF CHANGES IN TRUST CORPUS
Year Ended December 31
2015
2016
2014
Trust corpus, beginning of year
Amortization of net profits interests . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment of net profits interest (Note 1) . . . . . . . . . . . . . . . . . . . . . . .
Distributable income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions declared . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 86,900,231 $89,596,828 $ 98,854,558
(9,257,730)
—
43,809,680
(43,809,680)
(2,708,201)
(57,306,527)
1,855,400
(1,855,400)
(2,696,597)
—
7,753,240
(7,753,240)
Trust corpus, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 26,885,503 $86,900,231 $ 89,596,828
See accompanying notes to financial statements.
31
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
1. Trust Organization and Provisions
Hugoton Royalty Trust (the “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).
32
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
The most significant differences between the Trust’s financial statements and those prepared in accordance with U.S.
generally accepted accounting principles are:
• Net profits income is recognized in the month received rather than accrued in the month of production.
• Expenses are recognized when paid rather than when incurred.
• Cash reserves may be established by the trustee for contingencies that would not be recorded under U.S. generally
accepted accounting principles.
This comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the U.S.
Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty
Trusts.
Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with U.S.
generally accepted accounting principles, directing such entities to accrue or defer revenues and expenses in a period other
than when such revenues were received or expenses were paid. Because the Trust’s financial statements are prepared on
the modified cash basis, as described above, most accounting pronouncements are not applicable to the Trust’s financial
statements.
Impairment of Net Profits Interest
The trustee reviews the Trust’s net profits interests (“NPI”) in oil and gas properties for impairment whenever events or
circumstances indicate that the carrying value of the NPI may not be recoverable. In general, the trustee does not view
temporarily low prices as an indication of impairment. The markets for crude oil and natural gas have a history of significant
price volatility and though prices will occasionally drop significantly, industry prices over the long term will continue to be
driven by market supply and demand. If events and circumstances indicated that the carrying value may not be recoverable,
the trustee would use the estimated undiscounted future net cash flows from the NPI to evaluate the recoverability of the
Trust assets. If the undiscounted future net cash flows from the NPI are less than the NPI carrying value, the Trust would
recognize an impairment loss for the difference between the NPI carrying value and the estimated fair value of the NPI. The
determination as to whether the NPI is impaired requires a significant amount of judgment by the trustee and is based on
the best information available to the trustee at the time of the evaluation.
In light of lower long term prices used to develop projections of future cash flows, continued excess costs on two
conveyances and zero distributions to unitholders for the six months ended June 30, 2016, the trustee concluded in the
second quarter of 2016 that the events or circumstances indicated the carrying value may not be recoverable and an
assessment of the forecasted net cash flows was performed for the NPI. The fair value of the NPI was developed using
estimates for future oil and gas production attributable to the Trust, future crude oil and natural gas commodity prices
published by third-party industry experts (adjusted for basis differentials), estimated taxes, development and operating
expenses, and a risk-adjusted discount rate. The result of the assessment indicated that the estimated undiscounted future
net cash flows from the NPI were below the carrying value of the NPI. The NPI was written down to its fair value of $28.8
million, resulting in a $57.3 million impairment charged directly to Trust corpus, which did not affect distributable income.
There have been no events or changes in circumstances to indicate the carrying value of the NPI may not be recoverable,
and there is no further impairment of the assets as of December 31, 2016.
Net profits interests in oil and gas properties
The initial carrying value of the net profits interests of $247,066,951 represents XTO Energy’s historical net book value
for the interests on December 1, 1998, the date of the transfer to the Trust. During the second quarter 2016, the carrying
value of the NPI was written down to its fair value of $28,801,000, resulting in an impairment of $57,306,527 charged
33
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
directly to Trust corpus. Amortization of the net profits interests is calculated on a unit-of-production basis and charged
directly to Trust corpus. Accumulated amortization was $162,874,921 as of December 31, 2016 and $160,166,720 as of
December 31, 2015.
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,
legal and marketing charges, production expense,
transportation,
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
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.
Conveyances (Underlying)
KS
OK
WY
Total
Cumulative excess costs remaining at 12/31/15 . . . . . . . . . . . . . . $1,141,452
255,605
Net excess costs for the quarter ended 3/31/16 . . . . . . . . . . . . . .
(71,807)
Net excess costs (recovery) for the quarter ended 6/30/16 . . . . . .
93,933
Net excess costs (recovery) for the quarter ended 9/30/16 . . . . . .
(369,582)
Net excess costs (recovery) for the quarter ended 12/31/16 . . . . .
$
— $ 478,735
472,481
570,141
169,646
(532,798)
97,457
(97,457)
—
—
$1,620,187
825,543
400,877
263,579
(902,380)
Cumulative excess costs remaining at 12/31/16 . . . . . . . . . . . . . . $1,049,601
$
— $1,158,205
$2,207,806
XTO Energy advised the trustee that a one-time reimbursement for overhead corrections and a one-time prior period
revenue adjustment resulted in the partial recovery of excess costs of $91,851 ($73,481 net to the Trust) on properties
underlying the Kansas net profits interest for the year ended December 31, 2016. This included the partial recovery of
excess costs of $369,582 ($295,666 net to the Trust) related to the quarter ended December 31, 2016.
XTO Energy advised the trustee that a one-time reimbursement for overhead corrections led to full recovery of excess
costs, plus accrued interest of $1,059 ($847 net to the Trust), on properties underlying the Oklahoma net profits interest for
the year ended December 31, 2016.
34
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
XTO Energy advised the trustee that lower gas prices in the first half of 2016, partially offset by a one-time
reimbursement for overhead corrections and improved gas prices in the second half of 2016 resulted in net excess costs of
$679,470 ($543,576 net to the Trust) on properties underlying the Wyoming net profits interest for the year ended
December 31, 2016. This included the partial recovery of excess costs of $532,798 ($426,238 net to the Trust) related to
the quarter ended December 31, 2016.
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.
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.
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.
Cumulative excess costs for the Kansas and Wyoming conveyances remaining as of December 31, 2016 totaled
$2,207,806 ($1,766,245 net to the Trust).
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
2015
2016
2014
Cumulative actual costs under (over) the amount deducted
— beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actual costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Budgeted costs deducted . . . . . . . . . . . . . . . . . . . . . . . . . .
$
239,528
(1,858,285)
1,675,000
$ 1,242,998
(3,803,470)
2,800,000
$
588,742
(4,645,744)
5,300,000
Cumulative actual costs under (over) the amount deducted
— end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
56,243
$
239,528
$ 1,242,998
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.
The monthly development cost deduction was $600,000 from the January 2014 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. The deduction was maintained at that level through the November 2014 distribution. Due to lower
than anticipated actual costs as a result of
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
reduced activity and revisions to the 2014 development budget,
35
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
distribution and was maintained at that level through January 2016. Due to the level of actual development costs, the
monthly development cost deduction was decreased to $187,500 beginning in February 2016 and was maintained at that
level through March 2016. Due to the revised 2016 budget, the monthly development cost deduction was decreased to
$100,000 beginning in April 2016. Due to the level of actual development costs, the monthly development cost deduction
was further decreased to $50,000 beginning in June 2016. Based on an increased level of development activity and costs,
the deduction was increased from $50,000 to $200,000 beginning with the October 2016 distribution and was maintained
at that level through the end of 2016.
For further information on 2017 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. Impairment for book purposes will not result in a loss for tax
purposes for the unitholders until the loss is recognized.
All revenues from the Trust are from sources within Kansas, Oklahoma or Wyoming. Because it distributes all of its net
income to unitholders, the Trust has not been taxed at the trust level in Kansas or Oklahoma. While the Trust has not owed
tax, the trustee is generally required to file 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. However, the Trust will not file a Kansas return for the 2016 tax year because the Trust had no revenues,
income or deductions in 2016 attributable to properties located in Kansas. The Trust did not file a return with Kansas for the
2015 tax year for the same reason.
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 94% 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, 2016, the overhead charge was approximately $964,000 ($771,200 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 provides 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.
36
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Total gas sales from the underlying properties to XTO Energy’s wholly owned subsidiaries were $15.0 million for 2016,
or 48% of total gas sales, $16.4 million for 2015, or 38% of total gas sales and, $30.4 million for 2014, or 38% of total
gas sales.
On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.
8. Contingencies
Litigation
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 had alleged damages in excess of $40 million. On June 22, 2016, plaintiffs’
Second Motion for Class Certification was denied. In light of the denied certification, the plaintiff moved to dismiss the case.
A dismissal order has been signed and the case is now concluded.
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. A non-binding mediation occurred September 1, 2016, but was unsuccessful.
Pretrial discovery continues.
XTO Energy has informed the trustee that it believes that XTO Energy has strong defenses to the Chieftain lawsuit and
intends to vigorously defend its position. However, XTO Energy has informed the trustee that it is cognizant of other, similar
litigation. 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, 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,
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 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
the trustee intends to review any claimed reductions in payment
37
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
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.
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.
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.
is a unitholder
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,
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.
38
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
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.
Certain of the underlying properties are involved in various other lawsuits and governmental proceedings arising in the
ordinary course of business. XTO Energy has advised the trustee that it does not believe that the ultimate resolution of these
claims will have a material effect on the financial position or liquidity of the Trust, but may have an effect on annual
distributable income.
Other
Several states have enacted legislation requiring state income tax withholding from nonresident recipients of oil and
gas proceeds. After consultation with its tax counsel, the trustee believes that it is not required to withhold on payments
made to the unitholders. However, regulations are subject to change by the various states, which could change this
conclusion. Should amounts be withheld on payments made to the Trust or the unitholders, distributions to the unitholders
would be reduced by the required amount, subject to the filing of a claim for refund by the Trust or unitholders for such
amount.
9. Supplemental Oil and Gas Reserve Information (Unaudited)
Oil and Natural Gas Reserves
Proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are those
quantities of oil and natural gas, which, by analysis of geoscience and engineering data can be estimated with reasonable
certainty to be economically producible from a given date forward, from known reservoirs and under existing economic
conditions, operating methods, and government regulation before the time at which contracts providing the right to operate
expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected
to be recovered through existing wells with existing equipment and operating methods in which the cost of the required
equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature
of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually
recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions
result primarily from new information obtained from development drilling and production history and from changes in
economic factors.
Standardized Measure
The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using
assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month
average prices for oil and gas, based on the first-day-of-the-month price for each month in the period, and year end costs
for estimated future development and production expenditures to produce the proved reserves, including recovery of
cumulative excess costs remaining at year end. Future net cash flows are discounted at an annual rate of 10%. No provision
is included for federal income taxes since future net cash flows are not subject to taxation at the trust level.
39
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
The standardized measure does not represent management’s estimate of future cash flows or the value of proved oil
and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the
calculations. Furthermore, prices used to determine the standardized measure are influenced by supply and demand as
affected by recent economic conditions as well as other factors and may not be the most representative in estimating future
revenues or reserve data.
Estimated costs to plug and abandon wells on the underlying working interest properties at the end of their productive
lives have not been deducted from cash flows since this is not a legal obligation of the Trust. These costs are the legal
obligation of 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 $1.94 per Mcf in 2016, $2.10 per
Mcf in 2015, $4.35 per Mcf in 2014 and $3.92 per Mcf in 2013. Oil prices used to determine the standardized measure
were based on average realized oil prices of $39.08 per Bbl in 2016, $46.56 per Bbl in 2015, $92.70 per Bbl in 2014 and
$94.32 per Bbl in 2013.
Reserve quantities and revenues for the net profits interests were estimated from projections of reserves and revenues
attributable to the underlying properties. Since the Trust has defined net profits interests, the Trust does not own a specific
percentage of the oil and gas reserves. Oil and gas reserves are allocated to the net profits interests by dividing Trust net
cash inflows by 12-month average oil and gas prices. Any fluctuations in 12-month average prices or estimated costs will
result in revisions to the estimated reserve quantities allocated to the net profits interests, which may not correlate with
revisions of underlying proved reserves.
40
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Proved Reserves
(in thousands)
Underlying Properties
Oil (Bbls)
Gas (Mcf)
Net Profits Interests
Gas (Mcf)
Oil (Bbls)
Balance, December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 241,473
123
(13,981)
(17,427)
—
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance, December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 210,188
71
(90,561)
(15,736)
—
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance, December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103,962
—
3,361
(14,855)
—
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production – sales volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,485
8
(70)
(204)
—
2,219
2
(841)
(194)
—
1,186
—
90
(179)
—
85,474
46
(1,353)
(8,004)
—
76,163
5
(59,389)
(2,292)
—
14,487
—
(9,224)
(1,096)
—
969
3
(5)
(111)
—
856
—
(636)
(41)
—
179
—
(95)
(18)
—
Balance, December 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
92,468
1,097
4,167
66
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. Positive revisions for the underlying properties during the year ended December 31,
2016 are primarily due to lower operating costs. Revisions for the net profits interests may not correlate with underlying
properties in any given year since the Trust’s allocated reserves reflect recovery of the Trust’s portion of production and
development costs at 12-month average prices. Any conveyance where costs exceed revenues will result in zero allocated
net profits interests reserves for that conveyance.
Proved Developed Reserves
(in thousands)
Underlying Properties
Oil (Bbls)
Gas (Mcf)
Net Profits Interests
Gas (Mcf)
Oil (Bbls)
December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 204,611
2,163
76,239
878
December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 177,389
1,847
68,335
767
December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102,683
1,178
14,411
178
December 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
91,734
1,097
4,167
66
41
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
2016
December 31
2015
2014
Underlying Properties
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $222,625 $273,346 $1,119,099
Future costs:
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% discount factor
209,820
795
12,010
2,474
227,298
1,704
44,344
14,739
572,635
72,227
474,237
227,641
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,536 $ 29,605 $ 246,596
Net Profits Interests
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 10,353 $ 38,668 $ 412,882
33,492
Future production taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,192
745
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% discount factor
9,608
1,980
35,476
11,793
379,390
182,112
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,628 $ 23,683 $ 197,278
42
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
(in thousands)
2016
2015
2014
Underlying Properties
Standardized measure, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 29,605 $ 246,596 $258,039
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(18,980)
988
2,569
(738)
(636)
(16,797)
—
(4,947)
1,675
—
(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
—
Net change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(20,069)
(216,991)
(11,443)
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,536 $ 29,605 $246,596
Net Profits Interests
Standardized measure, January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 23,683 $ 197,278 $206,431
Extensions, additions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
301
17,671
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of discount
17,321
Revisions of prior estimates, changes in price and other
. . . . . . . . . . . . . . . . . . . . .
—
Sales in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(44,446)
Net profits income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13
17,510
(182,874)
—
(8,244)
—
2,055
(15,492)
—
(2,618)
Standardized measure, December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,628 $ 23,683 $197,278
43
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—(Continued)
10. Quarterly Financial Data (Unaudited)
The following is a summary of net profits income, distributable income and distributable income per unit by quarter for
2016 and 2015:
2016
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2015
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Net Profits
Income
Distributable
Income
Distributable
Income per
Unit
$
63,562
199,545
1,253,498
1,101,035
$
—
—
791,920
1,063,480
$0.000000
0.000000
0.019798
0.026587
$2,617,640
$1,855,400
$0.046385
$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
11. Operated Overhead
XTO Energy advised the trustee that the August 2016 distribution included a one-time reimbursement of approximately
$450,000 related to operated overhead corrections for the period of January 2014 through May 2016. This reimbursement
affected the net profits income under the Oklahoma conveyance.
XTO Energy advised the trustee that the May 2016 distribution included a one-time reimbursement of $788,000
related to operated overhead corrections for the period of January 2014 through February 2016. This reimbursement
affected the net profits income under the Kansas, Oklahoma and Wyoming conveyances by approximately $186,000,
$320,000 and $282,000 respectively.
12. Taxes, Transportation and Other Deductions
XTO Energy advised the trustee that net profits income for August 2016 included approximately $500,000 in
additional gathering fees for the period of December 2015 through May 2016 related to a renegotiated gas purchase
contract that included production from properties underlying the Oklahoma conveyance. The current contract term is
December 1, 2015 until November 30, 2017.
13. Purchaser and Other Adjustments
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.
XTO Energy advised the trustee that the December 2016 distribution included a one-time prior period adjustment of
approximately $230,000 in additional gas revenue from properties underlying the Kansas net profits interest.
44
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, 2016. The effectiveness of the Trust’s internal control over financial reporting as of December 31, 2016 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,
2016 that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial
reporting.
Item 9B. Other Information
None.
45
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, 2016.
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 2014 through 2016 as specified in the Trust indenture:
2016
2015
2014
U.S. Trust, Bank of America Private Wealth Management, Trustee(1)(2)
Southwest Bank, Trustee(1)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
$65,032
—
$68,288
$29,739
$35,728
(1) Under the Trust indenture, the trustee is entitled to an annual administrative fee, paid in equal monthly installments.
Such fee can be adjusted annually based on an oil and gas industry index. Upon termination of the Trust, the trustee is
entitled to a termination fee of $15,000.
(2) 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, 2016
was approximately $964,000 per month, or $11,568,000 annually (net to the Trust of $771,200 per month or $9,254,400
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.
46
See Item 11, Executive Compensation, for the remuneration received by the trustee from 2014 through 2016.
As noted in Item 10, Directors, Executive Officers and Corporate Governance, the Trust has no directors, executive
officers or audit committee. The trustee is a corporate trustee which may be removed, with or without cause, by the
affirmative vote of the holders of a majority of all the units then outstanding.
Item 14. Principal Accountant Fees and Services
Fees for services performed by PricewaterhouseCoopers LLP for the years ended December 31, 2016 and 2015 are:
Audit fees-PwC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Audit-related fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All other fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
2015
$148,129
—
—
—
$143,190
—
—
—
$148,129
$143,190
As referenced in Item 10, Directors, Executive Officers and Corporate Governance, above, the Trust has no audit
to fees paid to
committee pre-approval policy with respect
committee, and as a result, has no audit
PricewaterhouseCoopers LLP.
47
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, 2016 and 2015
Statements of Distributable Income for the years ended December 31, 2016, 2015 and 2014
Statements of Changes in Trust Corpus for the years ended December 31, 2016, 2015 and 2014
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.
48
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 10, 2017
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.astfinancial.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, 2016.
Hugoton Royalty Trust
Southwest Bank
P.O. Box 962020
Fort Worth, Texas 76162-2020
1-855-588-7839
www.hgt-hugoton.com