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.
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 Trusts 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:
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the Trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments;
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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;
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the trustee may establish a cash reserve for payment of any liability that is contingent or not currently payable;
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the trustee may borrow funds to pay Trust liabilities if repaid in full prior to further distributions to unitholders;
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the trustee will make monthly cash distributions to unitholders (Note 3); and
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the Trust will terminate upon the first occurrence of:
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disposition of all net profits interests pursuant to terms of the Trust indenture,
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gross proceeds from the underlying properties falling below $1 million per year for two successive years, or
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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.
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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 Trusts 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:
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Net profits income is recorded in the month received by the trustee (Note 3).
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Trust expenses are recorded based on liabilities paid and cash reserves established by the trustee for liabilities and contingencies.
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Distributions to unitholders are recorded when declared by the trustee (Note 3).
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32
HUGOTON ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS(Continued)
The most significant differences between the Trusts financial statements and those prepared in
accordance with U.S. generally accepted accounting principles are:
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Net profits income is recognized in the month received rather than accrued in the month of production.
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Expenses are recognized when paid rather than when incurred.
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Cash reserves may be established by the trustee for contingencies that would not be recorded under U.S. generally accepted accounting principles.
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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 Trusts financial statements are prepared on the modified cash basis, as described above, most accounting pronouncements are not applicable to the Trusts financial statements.
Impairment of Net Profits Interest
The trustee reviews the
Trusts 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 Energys
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, transportation, legal and marketing charges, production expense, development and drilling
costs, and overhead (Note 7).
XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the three
conveyances (one for each of the states of Kansas, Oklahoma and Wyoming). If costs exceed revenues for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net
profits income from the other conveyances (Note 4).
4. Excess Costs
If monthly costs exceed revenues for any of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming), such excess costs must be
recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds from other conveyances.
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Conveyances (Underlying)
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KS
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OK
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WY
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Total
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Cumulative excess costs remaining at 12/31/15
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$
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1,141,452
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$
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$
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478,735
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$
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1,620,187
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Net excess costs for the quarter ended 3/31/16
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255,605
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97,457
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472,481
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825,543
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Net excess costs (recovery) for the quarter ended 6/30/16
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(71,807
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)
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(97,457
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)
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570,141
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400,877
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Net excess costs (recovery) for the quarter ended 9/30/16
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93,933
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169,646
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263,579
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Net excess costs (recovery) for the quarter ended 12/31/16
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(369,582
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)
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(532,798
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)
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(902,380
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Cumulative excess costs remaining at 12/31/16
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$
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1,049,601
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$
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$
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1,158,205
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$
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2,207,806
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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 ($1,766,245 net to the Trust).
5. Development Costs
The following summarizes actual development costs, budgeted development costs deducted in the calculation of net profits income, and the cumulative
actual costs compared to the amount deducted:
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Year Ended December 31
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2016
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2015
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2014
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Cumulative actual costs under (over) the amount deducted beginning of period
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$
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239,528
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$
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1,242,998
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$
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588,742
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Actual costs
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(1,858,285
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)
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(3,803,470
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)
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(4,645,744
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)
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Budgeted costs deducted
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1,675,000
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2,800,000
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5,300,000
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Cumulative actual costs under (over) the amount deducted end of period
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$
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56,243
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$
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239,528
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$
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1,242,998
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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 reduced activity and revisions to the 2014 development budget, the development cost deduction
was decreased to $200,000 beginning with the December 2014 distribution and was maintained at that level through the August 2015 distribution. Due to the anticipated level of actual costs and the 2015 development budget, the development cost
deduction was increased to $300,000 beginning with the September 2015
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 Trusts 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 persons 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 Energys 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 DCPs 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 Energys 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 Trusts net profits interests require the Trust to bear its 80% share of such settlement or judgment related to production from the underlying properties. Additionally, if the judgment or settlement
increases the amount of future payments to royalty owners, XTO Energy has informed the trustee that the Trust would bear its proportionate share of the increased payments through reduced net proceeds. In the event of any such settlement or judgment,
the trustee intends to review any claimed reductions in payment to the Trust based on the facts and circumstances of such settlement or judgment. In light of the arbitration tribunals 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 managements opinion, the amount is not currently expected to be material to the Trusts financial position or liquidity though it could be material to the Trusts 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
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 Trusts 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. Lambs counsel was
added as counsel of record for Goebel in
Sandra G. Goebel vs. XTO Energy, Inc., Timberland Gathering & Processing Company, Inc. and Bank of America, N.A.
On August 12, 2013, a demand for arbitration styled
Sandra G. Goebel vs. XTO Energy, Inc., Timberland Gathering & Processing Company,
Inc. and Bank of America, N.A.
was filed with the American Arbitration Association (AAA). The claimant, Sandra Goebel, is a unitholder in the Trust and alleged that XTO Energy breached the conveyances by misappropriating funds from
the Trust by failing to modify its existing sales contracts with its affiliate Timberland Gathering & Processing Company, Inc. (Timberland). Goebel alleged that these contracts did not currently reflect market rate
terms, and that XTO Energy had a duty to renegotiate the contracts to obtain more favorable terms. The claimant further alleged that Bank of America, N.A. (the previous trustee) breached its fiduciary duty by acquiescing to and facilitating XTO
Energys alleged self-dealing and concealing information from unitholders that would have revealed XTO Energys 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 managements 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Underlying Properties
|
|
|
Net Profits Interests
|
|
(in thousands)
|
|
Gas (Mcf)
|
|
|
Oil (Bbls)
|
|
|
Gas (Mcf)
|
|
|
Oil (Bbls)
|
|
|
|
|
|
|
Balance, December 31, 2013
|
|
|
241,473
|
|
|
|
2,485
|
|
|
|
85,474
|
|
|
|
969
|
|
Extensions, additions and discoveries
|
|
|
123
|
|
|
|
8
|
|
|
|
46
|
|
|
|
3
|
|
Revisions of prior estimates
|
|
|
(13,981
|
)
|
|
|
(70
|
)
|
|
|
(1,353
|
)
|
|
|
(5
|
)
|
Production sales volumes
|
|
|
(17,427
|
)
|
|
|
(204
|
)
|
|
|
(8,004
|
)
|
|
|
(111
|
)
|
Sales in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2014
|
|
|
210,188
|
|
|
|
2,219
|
|
|
|
76,163
|
|
|
|
856
|
|
Extensions, additions and discoveries
|
|
|
71
|
|
|
|
2
|
|
|
|
5
|
|
|
|
|
|
Revisions of prior estimates
|
|
|
(90,561
|
)
|
|
|
(841
|
)
|
|
|
(59,389
|
)
|
|
|
(636
|
)
|
Production sales volumes
|
|
|
(15,736
|
)
|
|
|
(194
|
)
|
|
|
(2,292
|
)
|
|
|
(41
|
)
|
Sales in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2015
|
|
|
103,962
|
|
|
|
1,186
|
|
|
|
14,487
|
|
|
|
179
|
|
Extensions, additions and discoveries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of prior estimates
|
|
|
3,361
|
|
|
|
90
|
|
|
|
(9,224
|
)
|
|
|
(95
|
)
|
Production sales volumes
|
|
|
(14,855
|
)
|
|
|
(179
|
)
|
|
|
(1,096
|
)
|
|
|
(18
|
)
|
Sales in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Trusts allocated reserves reflect recovery of the Trusts portion of production and development costs at 12-month average prices. Any conveyance where costs exceed revenues will result in zero
allocated net profits interests reserves for that conveyance.
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Underlying Properties
|
|
|
Net Profits Interests
|
|
(in thousands)
|
|
Gas (Mcf)
|
|
|
Oil (Bbls)
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31
|
|
(in thousands)
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Underlying Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
222,625
|
|
|
$
|
273,346
|
|
|
$
|
1,119,099
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
209,820
|
|
|
|
227,298
|
|
|
|
572,635
|
|
Development
|
|
|
795
|
|
|
|
1,704
|
|
|
|
72,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
12,010
|
|
|
|
44,344
|
|
|
|
474,237
|
|
10% discount factor
|
|
|
2,474
|
|
|
|
14,739
|
|
|
|
227,641
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure
|
|
$
|
9,536
|
|
|
$
|
29,605
|
|
|
$
|
246,596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Profits Interests
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
10,353
|
|
|
$
|
38,668
|
|
|
$
|
412,882
|
|
Future production taxes
|
|
|
745
|
|
|
|
3,192
|
|
|
|
33,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
9,608
|
|
|
|
35,476
|
|
|
|
379,390
|
|
10% discount factor
|
|
|
1,980
|
|
|
|
11,793
|
|
|
|
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
|
|
|
(18,980
|
)
|
|
|
(259,248
|
)
|
|
|
53,081
|
|
Quantity estimates
|
|
|
988
|
|
|
|
(30,036
|
)
|
|
|
(17,867
|
)
|
Accretion of discount
|
|
|
2,569
|
|
|
|
21,887
|
|
|
|
22,088
|
|
Future development costs
|
|
|
(738
|
)
|
|
|
60,798
|
|
|
|
(12,192
|
)
|
Production rates and other
|
|
|
(636
|
)
|
|
|
(104
|
)
|
|
|
(1,371
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net revisions
|
|
|
(16,797
|
)
|
|
|
(206,703
|
)
|
|
|
43,739
|
|
Extensions, additions and discoveries
|
|
|
|
|
|
|
16
|
|
|
|
376
|
|
Production
|
|
|
(4,947
|
)
|
|
|
(13,104
|
)
|
|
|
(60,858
|
)
|
Development costs
|
|
|
1,675
|
|
|
|
2,800
|
|
|
|
5,300
|
|
Sales in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
13
|
|
|
|
301
|
|
Accretion of discount
|
|
|
2,055
|
|
|
|
17,510
|
|
|
|
17,671
|
|
Revisions of prior estimates, changes in price and other
|
|
|
(15,492
|
)
|
|
|
(182,874
|
)
|
|
|
17,321
|
|
Sales in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Net profits income
|
|
|
(2,618
|
)
|
|
|
(8,244
|
)
|
|
|
(44,446
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Profits
Income
|
|
|
Distributable
Income
|
|
|
Distributable
Income per
Unit
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
63,562
|
|
|
$
|
|
|
|
$
|
0.000000
|
|
Second Quarter
|
|
|
199,545
|
|
|
|
|
|
|
|
0.000000
|
|
Third Quarter
|
|
|
1,253,498
|
|
|
|
791,920
|
|
|
|
0.019798
|
|
Fourth Quarter
|
|
|
1,101,035
|
|
|
|
1,063,480
|
|
|
|
0.026587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,617,640
|
|
|
$
|
1,855,400
|
|
|
$
|
0.046385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
4,136,842
|
|
|
$
|
3,766,000
|
|
|
$
|
0.094150
|
|
Second Quarter
|
|
|
1,463,774
|
|
|
|
1,185,720
|
|
|
|
0.029643
|
|
Third Quarter
|
|
|
1,584,694
|
|
|
|
1,347,240
|
|
|
|
0.033681
|
|
Fourth Quarter
|
|
|
1,058,607
|
|
|
|
1,454,280
|
|
|
|
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