Item 1. Business.
DESCRIPTION OF THE TRUST
The Trust, created under the laws of the State of Texas, maintains its offices at the office of the Trustee, The Bank of New York Mellon Trust
Company, N.A., (the "Trustee"), 601 Travis Street, Floor 16, Houston, Texas 77002. The telephone number of the Trust is 713-483-6020. The Bank of New York Mellon Trust Company, N.A., is the
successor Trustee from JPMorgan Chase Bank, N.A., which is the successor by mergers to the originally named Trustee, Texas Commerce Bank National Association. The Trust has no employees.
Administrative functions of the Trust are performed by the Trustee. The Trustee maintains a website for the Trust that makes available, free of charge, filings by the Trust with the Securities and
Exchange Commission ("SEC") and other information. Any reports filed with the SEC are accessible free of charge through our website as soon as reasonably practicable after we electronically file such
material with, or furnish it to, the SEC. The Trust's website is http://mtr.investorhq.businesswire.com/.
Trust Corpus Description.
The Mesa Royalty Trust (the "Trust") was created on November 1, 1979, and is now governed by the Mesa
Royalty Trust
Indenture (as amended, the "Trust Indenture"). Through a series of conveyances, assignments, and acquisitions, the Trust currently owns an overriding royalty interest (the "Royalty") equal to 11.44%
of 90% of the Net Proceeds (as defined in the Conveyance and described below) attributable to the specified interest in certain producing oil and gas properties located in
the:
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Hugoton field of Kansas (the "Hugoton Royalty Properties");
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San Juan Basin field of New Mexico (the "San Juan BasinNew Mexico Properties"); and
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San Juan Basin field of Colorado (the "San Juan BasinColorado Properties", and together with the "San Juan BasinNew
Mexico Properties, the "San Juan Basin Royalty Properties", and together with the Hugoton Royalty Properties, the "Royalty Properties").
Trust Corpus Conveyance History.
On November 1, 1979, Mesa Petroleum Co., predecessor to Mesa Limited Partnership ("MLP"),
which was
the predecessor to MESA Inc., conveyed to the Trust the Royalty equal to 90% of the Net Proceeds (as defined in the Conveyance and described below) attributable to the specified interests in
properties conveyed by the assignor on that date (the "Subject Interests"). The Subject Interests consisted of interests in the Royalty Properties described above. The Royalty is evidenced by
counterparts of an Overriding Royalty Conveyance, dated as of November 1, 1979 (the "Conveyance"). In 1985, the Trust Indenture was amended and the Trust conveyed to an affiliate of Mesa
Petroleum Co. 88.5571% of the original Royalty (such transfer, the "1985 Assignment"). The effect of the 1985 Assignment was an overall reduction of approximately 88.56% in the size of the
Trust. As a result, the Trust is now entitled to receive 11.44% of 90% of the Net Proceeds attributable to each month.
Hugoton Royalty Properties.
Until August 7, 1997, MESA Inc. operated the Hugoton Royalty Properties through Mesa
Operating Co.,
a wholly owned subsidiary of MESA Inc. On August 7, 1997, MESA Inc. merged with and into Pioneer Natural Resources Company ("Pioneer"), formerly a wholly owned subsidiary of
MESA Inc., and Parker & Parsley Petroleum Company merged with and into Pioneer Natural Resources USA, Inc. (successor to Mesa Operating Co.), a wholly owned subsidiary of
Pioneer ("PNR") (collectively, the mergers are referred to herein as the "Merger"). Subsequent to the Merger, the Hugoton Royalty Properties were operated by PNR until December 31, 2014, at
which point Linn Energy Holdings, LLC, a subsidiary of Linn Energy, LLC ("Old Linn") took over as operator. Pursuant to the bankruptcy proceedings and court-approved plans of
reorganization involving Old Linn, which are described in detail below, Linn Energy, Inc. (together with its subsidiaries, "Linn")
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became
the operator of the Hugoton Royalty Properties on February 28, 2017. On April 18, 2018, Linn announced its Board of Directors' decision to separate Linn into two stand-alone
public companies. On August 7, 2018 Linn completed the spin-off of Riviera Resources, Inc. ("Riviera") through the pro rata distribution of all of the shares of Riviera's outstanding
common stock to Linn's stockholders. In connection with such distribution, Linn ceased to be the operator of the Hugoton Royalty Properties, and since August 7, 2018, Riviera has operated the
Hugoton Royalty Properties.
San Juan BasinColorado Properties.
On April 30, 1991, MLP sold to Conoco, Inc. ("ConocoPhillips") its interests in the
San
Juan Basin Royalty Properties (the "San Juan Basin Sale"). The Trust's interest in the San Juan Basin Royalty Properties was conveyed from PNR's working interest in 31,328 net producing acres in
northwestern New Mexico and southwestern Colorado. ConocoPhillips sold the portion of its interests in the San Juan BasinColorado
Properties to MarkWest Energy Partners, Ltd. (effective January 1, 1993) and Red Willow Production Company ("Red Willow") (effective April 1, 1992). On October 26, 1994,
MarkWest Energy Partners, Ltd. sold substantially all of its interest in the San Juan BasinColorado Properties to BP Amoco Company ("BP"), a subsidiary of BP p.l.c. BP and Red
Willow currently operate the San Juan BasinColorado Properties.
San Juan BasinNew Mexico Properties.
Starting from the date of the San Juan Basin Sale and ending on July 31, 2017,
ConocoPhillips operated substantially all of the San Juan BasinNew Mexico Properties, except an immaterial number of properties assigned to XTO Energy, Inc. ("XTO") effective
January 1, 2005. On July 31, 2017, ConocoPhillips sold its San Juan Basin assets to Hilcorp San Juan LP ("Hilcorp"), an affiliate of Hilcorp Energy Company. On March 29,
2018, XTO sold to Hilcorp an immaterial number of properties, which comprise certain portions of the San Juan BasinNew Mexico Properties. Hilcorp currently operates all of the San Juan
BasinNew Mexico Properties.
Following
Hilcorp's acquisition of ConocoPhillips' and XTO's interests in the San JuanNew Mexico Properties, Hilcorp has made an estimated payment of Net Proceeds to the
Trust each month consistent with the monthly amounts previously paid by ConocoPhillips and XTO. As a result of the payment of estimated Net Proceeds, Hilcorp has informed the Trust that it will
reconcile estimated versus actual revenue figures once it finalizes installation of its revenue decks, although Hilcorp has not indicated when such reconciliation may occur. At the time that Hilcorp
reconciles estimated versus actual revenue numbers, such estimations and reconciliations by Hilcorp will be added to or subtracted from future Net Proceeds paid to the Trust in accordance with the
Trust's basis of financial presentation. Pursuant to the Trust Indenture, the Trust is not required to pay to Hilcorp any amounts that could be owed if the estimated revenue exceeded actual revenue
figures in past periods, plus any additional required costs. However, Hilcorp may recover such amounts by withholding a portion or all of Net Proceeds that would otherwise be payable to the Trust in
subsequent periods. This could result in a decrease in Net Proceeds paid to the Trust and could result in a future material reduction in distributions to the Trust's unitholders. Net Proceeds from the
San Juan BasinNew Mexico Properties for the years ended December 31, 2018 and 2017 were $1,165,797 and $1,085,082, respectively, which revenue accounted for approximately 50% and
36%, respectively, of the total Royalty income realized by the Trust.
As
used in this report, Riviera refers to the current operator of the Hugoton Royalty Properties, Hilcorp refers to the current operator of the San Juan BasinNew Mexico
Properties, and BP and Red Willow refers to the current co-operators of certain tracts of land included in the San Juan BasinColorado Properties, unless otherwise indicated. Riviera, BP,
Red Willow and Hilcorp are each individually referred to herein as "Working Interest Owner" or collectively as the "Working Interest Owners."
The
Royalty Properties are required to be operated by the Working Interest Owners in accordance with reasonable and prudent business judgment and good oil and gas field practices. Each
Working
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Interest
Owner has the right to abandon any well or lease if, in its opinion, such well or lease ceases to produce or is not capable of producing oil, gas or other minerals in commercial quantities.
Each Working Interest Owner markets the production on terms deemed by it to be the best reasonably obtainable in the circumstances. See "Contracts". The Trustee has no power or authority to exercise
any control over the operation of the Royalty Properties or the marketing of production therefrom.
Trustee and Terms of Trust Indenture.
Effective October 2, 2006, the Trustee succeeded JPMorgan Chase Bank, N.A. as Trustee of the
Trust. The
Trust is a passive entity whose purposes are limited to: (1) converting the Royalty to cash, either by retaining it and collecting the proceeds of production (until production has ceased or the
Royalty is otherwise terminated) or by selling or otherwise disposing of the Royalty and (2) distributing such cash, net of amounts for payments of liabilities to the Trust, to the unitholders.
The Trust has no sources of liquidity or capital resources other than the revenues, if any, attributable to the Royalty and interest on cash held by the Trustee as a reserve for liabilities or for
distribution. The terms of the Trust Indenture provide, among other things, that:
(a) the
Trust cannot engage in any business or investment activity or purchase any assets;
(b) the
Royalty can be sold in part or in total for cash upon approval by the unitholders;
(c) the
Trustee can establish cash reserves and borrow funds to pay liabilities of the Trust and can pledge assets of the Trust to secure payment of the borrowings;
(d) the
Trustee will make cash distributions to the unitholders in January, April, July and October each year as discussed more fully in Note 2 of the Notes to
Financial Statements contained in Item 8 of this Form 10-K;
(e) the
Trust will terminate upon the first to occur of the following events: (i) at such time as the Trust's royalty income for two successive years is less than
$250,000 per year or (ii) a vote by the unitholders in favor of termination. Upon termination of the Trust, the Trustee will sell for cash all the assets held in the Trust estate and make a
final distribution to unitholders of any funds remaining after all Trust liabilities have been satisfied; and
(f) Riviera,
Hilcorp and BP will reimburse the Trust for 59.34%, 27.45% and 1.77%, respectively, for general and administrative expenses of the Trust.
Linn Energy, LLC Reorganization.
On May 11, 2016, Old Linn, LinnCo, LLC ("LinnCo"), an affiliate of Old Linn, and
certain of Old
Linn's direct and indirect subsidiaries (collectively with Old Linn and LinnCo, the "Debtors"), filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy
Code in the United States Bankruptcy Court for the Southern District of Texas (the "Court"). The Debtors' Chapter 11 cases were administered jointly under the
caption
In re Linn Energy, LLC, et al.
, Case No. 16 60040.
On
January 27, 2017, the Court entered the
Order Confirming (I) Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC
and its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC and (II) Amended Joint Chapter 11 Plan of Reorganization of Linn
Acquisition Company, LLC and Berry Petroleum Company, LLC,
which approved and confirmed the Amended Joint Chapter 11 Plan of Reorganization of Linn
Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the "Plan"). The Plan became effective on February 28, 2017
(the "Effective Date").
Pursuant
to the Plan, on the Effective Date, all assets of Old Linn (other than equity interests in Linn Acquisition Company, LLC and Berry Petroleum Company, LLC) were
conveyed to Linn, and LinnCo, LLC and Linn Energy, LLC were wound down and liquidated. Subsequent to the effectiveness of the Plan, Linn Energy, Inc. became the reorganized
successor to Old Linn. Under the Plan Supplement, as amended, filed with the Court, the Debtors assumed all executory contracts and unexpired leases with the Trust and Mesa Operating Limited
Partnership as the counterparty.
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Furthermore,
pursuant to the Plan, the royalty interests in the Hugoton Royalty Properties owned by the Trust shall be preserved and remain in full force and effect in accordance with the terms of the
granting instruments or other governing documents. On April 18, 2018, Linn announced its Board of Directors' decision to separate Linn into two stand-alone public companies. On August 7,
2018 Linn completed the spin-off of Riviera through the pro rata distribution of all of the shares of Riviera's outstanding common stock to Linn's stockholders. In connection with such distribution,
Linn ceased to be the operator of the Hugoton Royalty Properties, and since August 7, 2018, Riviera has operated the Hugoton Royalty Properties.
Discussion of Net Proceeds.
The Conveyance provides for a monthly computation of Net Proceeds. Net Proceeds is defined in the
Conveyance as the
"Gross Proceeds" received by the Working Interest Owners during a particular period, minus certain production and capital costs for such period. "Gross Proceeds" is defined in the Conveyance as the
amount received by the Working Interest Owners from the sale of "Subject Minerals", subject to certain adjustments. "Subject Minerals" means all oil, gas and other minerals, whether similar or
dissimilar, in and under, and which may be produced, saved and sold from, and which accrue and are attributable to, the Subject Interests from and after November 1, 1979. "Production costs"
means, generally, costs incurred on an accrual basis by the Working Interest Owners in operating the Royalty Properties, including capital and non-capital costs. If production and capital costs exceed
Gross Proceeds for any month, the excess, plus interest thereon at 120% of the prime rate of Bank of America, is recovered out of future Gross Proceeds prior to the making of further payment to the
Trust. The Trust, however, is generally not liable for any operating costs or other costs or liabilities attributable to the Royalty Properties or minerals produced therefrom. The Trust is not
obligated to return any Royalty income received in any period.
The
Working Interest Owners are required to maintain books and records sufficient to determine the amounts payable under the Royalty. Additionally, in the event of a controversy between
a Working Interest Owner and any purchaser as to the correct sales price for any production, amounts received by such Working Interest Owner and promptly deposited by it with an escrow agent are not
considered to have been received by such Working Interest Owner, and, therefore, are not subject to being payable with respect to the Royalty until the controversy is resolved; but all amounts
thereafter paid to such Working Interest Owner by the escrow agent will be considered amounts received from the sale of production. Similarly, operating costs include any amounts a Working Interest
Owner is required to pay whether as a refund, interest or penalty to any purchaser because the amount initially received by such Working Interest Owner as the sales price was in excess of that
permitted by the terms of any applicable contract, statute, regulation, order, decree or other obligation. Within 30 days following the close of each calendar quarter, the Working Interest
Owners are required to deliver to the Trustee a statement of the computation of Net Proceeds attributable to such quarter.
The
brief discussions of the Trust Indenture and the Conveyance contained herein are qualified in their entirety by reference to the Trust Indenture and the Conveyance themselves, which
are exhibits to this Form 10-K and are available upon request from the Trustee.
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DESCRIPTION OF THE UNITS
Each unit of beneficial interest is evidenced by a transferable certificate issued by the Trustee. Each unit ranks equally for purposes of
distributions and has one vote on any matter submitted to unitholders. A total of 1,863,590 units were outstanding at April 1, 2019.
Distributions
The Trustee determines for each month the amount of cash available for distribution to unitholders for such month (the "Monthly Distribution
Amount"), which consists of the cash received from the Royalty during such month, minus the obligations of the Trust paid during such
month as adjusted for changes during such month in any cash reserves established for the payment of contingent or future obligations of the Trust made by the Trustee. The Monthly Distribution Amount
for each month is payable to unitholders of record on the monthly record date, which is the close of business on the last business day of such month or such other date as the Trustee determines is
required to comply with legal or stock exchange requirements. However, pursuant to the Trust Indenture and in order to reduce the administrative expenses of the Trust, the Trustee does not distribute
cash monthly. Instead, the Trustee makes distributions during January, April, July and October of each year. While distributions are only made four times per calendar year, the Trustee distributes to
each person who was a unitholder of record on one or more of the immediately preceding three monthly record dates, an amount equal to the Monthly Distribution Amount for the month or months that such
holder was a unitholder of record plus interest earned on such Monthly Distribution Amount from the Monthly Record Date to the payment date. Under the terms of the Trust Indenture, interest is earned
at a rate of 1.5% below the greater of (i) the prime rate charged by The Bank of New York Mellon Trust Company, N.A. or (ii) the interest rate which The Bank of New York Mellon Trust
Company, N.A. pays in the normal course of business on amounts placed with it. Interest income may vary significantly across different payment dates.
The
Working Interest Owners reimburse the Trust for portions of the total expenses incurred each month. The portions of expenses incurred by the Trustee without reimbursement from the
Working Interest Owners are unreimbursed expenses. Unreimbursed expenses for any reporting period and are included in general and administrative expenses, which results in a reduction of distributable
income. As of December 31, 2018, there were $0 of unreimbursed expenses.
The
terms of the Trust Indenture provide, among other things, that the Trustee may establish cash reserves and borrow funds to pay liabilities of the Trust and may pledge assets of the
Trust to secure payment of the borrowings. During 2011, the Trustee withheld $1.0 million for future unknown contingent liabilities and expenses in accordance with the Trust Indenture. At any
given time, the amount reserved for such future unknown contingent liabilities and expenses (the "Contingent Reserve") is included in cash and short-term investments.
For
the year ended December 31, 2018, the Trustee increased the Contingent Reserve by (1) $55,725 of Royalty income received from BP in March 2018 after the distribution to
unitholders had been announced for the month of March 2018, which Royalty income was included in the April 2018 distribution to unitholders, (2) $3,627 of Royalty income received from BP in
June 2018 after the distribution to unitholders had been announced for the month of June 2018, which Royalty income was included in the July 2018 distribution to unitholders, (3) $14,501 of
general and administrative expense not reimbursed by Riviera (formerly Linn) in June 2018 but included in the June 2018 distribution to unitholders, which reimbursement was received in July 2018,
(4) $3,000 of general and administrative expense not reimbursed by Riviera in September 2018 but included in the September 2018 distribution to unitholders, which reimbursement was received in
October 2018 and (5) $38,364 cash refund from a vendor received in November 2018.
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For
the year ended December 31, 2018, the Trustee decreased the Contingent Reserve by (1) $49,211 of Royalty income received from BP in December 2017 after the distribution
to unitholders had been announced for the month of December 2017, which Royalty income was included in the January 2018 distribution to unitholders, (2) $70,460 of December 2017 expenses that
were included in the distribution calculation for December 2017, but not paid by the Trust until January 2018, (3) $55,725 of Royalty income received from BP in March 2018 after the
distribution to unitholders had been announced for the month of March 2018, which Royalty income was included in the April 2018 distribution to unitholders, (4) $3,627 of Royalty income
received from BP in June 2018 after the distribution to unitholders had been announced for the month of June 2018, which Royalty income was included in the July 2018 distribution to unitholders,
(5) $14,501 of general and administrative expense not reimbursed by Riviera (formerly Linn) in June 2018 but included in the June 2018 distribution to unitholders, which reimbursement was
received in July 2018 and (6) $3,000 of general and administrative expense not reimbursed by Riviera in September 2018 but included in the September 2018 distribution to unitholders, which
reimbursement was received in October 2018.
The
net effects of the foregoing adjustments for the year ended December 31, 2018 resulted in the balance of the Contingent Reserve being equal to $1,038,364 as of
December 31, 2018.
For
the year ended December 31, 2017, the Trustee increased the Contingent Reserve by (1) $82,244 of Royalty income received from BP in March 2017 after the distribution to
unitholders had been announced for the month of March 2017, which Royalty income was included in the April 2017 distribution to unitholders, (2) $47,840 of Royalty income received from BP in
June 2017 after the distribution to unitholders had been announced for the month of June 2017, which Royalty income was included in the July 2017 distribution to unitholders, (3) $1,307 for the
amount of September expected expense reimbursement cash receipts, received in October 2017, (4) $49,211 of Royalty income received from BP in December 2017 after the distribution to unitholders
had been announced for the month of December 2017, which Royalty income was included in the January 2018 distribution to unitholders and (5) $70,460 of December 2017 expenses that were included
in the distribution calculation for December 2017, but not paid by the Trust until January 2018.
For
the year ended December 31, 2017, the Trustee decreased the Contingent Reserve by (1) $82,244 and $47,840 of aggregate Royalty income received from BP in March 2017 and
June 2017, respectively, and (2) $1,307 for expected expense reimbursement cash receipts. The net effects of the foregoing adjustments for the year ended December 31, 2017 resulted in
the balance of the Contingent Reserve being equal to $1,119,671 as of December 31, 2017.
Liability of Unitholders
In regard to the unitholders, the Trustee is fully liable if the Trustee incurs any liability without ensuring that such liability will be
satisfiable only out of the Trust's assets (regardless of whether the assets are adequate to satisfy the liability) and in no event out of amounts distributed to, or other assets owned by, the
unitholders. However, under Texas law, it is unclear whether a unitholder would be jointly and severally liable for any liability of the Trust in the event that all of the following conditions were to
occur: (1) the satisfaction of such liability was not by contract limited to the assets of the Trust, (2) the assets of the Trust were insufficient to discharge such liability, and
(3) the assets of the Trustee were insufficient to discharge such liability.
Federal Income Tax Matters
This section is a summary of federal income tax matters of general application, which addresses the material tax consequences of the ownership
and sale of the Trust's units. Except where indicated, the discussion below describes general federal income tax considerations applicable to individuals who are citizens or residents of the U.S.
Accordingly, the following discussion has limited application to
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domestic
corporations, foreign persons and persons subject to specialized federal income tax treatment, such as regulated investment companies and insurance companies. It is impractical to comment on
all aspects of federal, state, local and foreign laws that may affect the tax consequences of the transactions contemplated hereby and of an investment in the units as they relate to the particular
circumstances of every unitholder.
Each unitholder should consult its own tax advisor with respect to its particular circumstances.
In a technical advice memorandum dated February 26, 1982, the National Office of the Internal Revenue Service (the "IRS") advised the
Dallas District Director that the Trust is classifiable as a grantor trust and not as an association taxable as a corporation. As a grantor trust, the Trust incurs no federal income tax liability and
each unitholder is subject to tax on such unitholder's pro rata share of the income and expense of the Trust as if such unitholder were the direct owner of a pro rata share of the Trust's assets. In
addition, there is no state tax liability for the period.
The
Trustee assumes that some Trust units are held by a middleman, 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 custodian in street name). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust ("WHFIT") for U.S. federal income
tax purposes. Notwithstanding the foregoing, the middlemen holding units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting
requirements under the Treasury Regulations with respect to such units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose 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 units.
The Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Floor 16, Houston, Texas 77002, telephone number 713-483-6020,
is the representative of the Trust that will provide tax information in accordance with applicable Treasury Regulations (as defined below) governing the information reporting requirements of the Trust
as a WHFIT. In compliance with the Treasury Regulations reporting requirements for WHFITs and the dissemination of Trust tax reporting information, the Trustee provides a tax information reporting
booklet which is intended to be used only to assist Trust unitholders in the preparation of their federal income tax returns. This tax information booklet can be obtained at
http://mtr.investorhq.businesswire.com/.
U.S.
federal tax reform informally known as the Tax Cuts and Jobs Act (the "TCJA") was enacted on December 22, 2017 and made significant changes to the federal income tax rules
applicable to both individuals and entities, including changes to the effective tax rate on a unitholder's allocable share of certain income from the Trust. The TCJA is complex and some areas lack
administrative guidance. Thus, unitholders should consult their tax advisor regarding the TCJA and its effect on an investment in Trust units.
This
summary is based on current provisions of the Internal Revenue Code of 1986, as amended ("Code"), existing and proposed Internal Revenue Treasury Regulations ("Treasury
Regulations") thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. No assurance can be provided that the
statements set forth herein (which do not bind the IRS or any court) will not be challenged by the IRS or will be sustained by any court if challenged.
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Royalty income, net of depletion and severance taxes, is portfolio income. Subject to certain exceptions and transitional rules, royalty income
cannot be offset by passive losses. Additionally, interest income is portfolio income.
Generally,
prior to the Revenue Reconciliation Act of 1990, the transferee of an oil and gas property could not claim percentage depletion with respect to production from the property if
it was "proved" at the time of the transfer. This rule is not applicable in the case of transfers of properties after October 11, 1990. Thus, eligible unitholders who acquired units after that
date are entitled to claim an allowance for percentage depletion with respect to Royalty income attributable to such units to the extent that this allowance exceeds cost depletion as computed for the
applicable period.
Distributions from the Trust are generally subject to backup withholding at a current rate of 24%. Backup withholding will not normally apply to
distributions to a unitholder unless the unitholder fails to properly provide to the Trust its taxpayer identification number or the IRS notifies the Trust that the taxpayer identification number
provided by the unitholder is incorrect.
Generally, except for recapture items, the sale, exchange or other disposition of a unit will result in capital gain or loss measured by the
difference between the tax basis in the unit and the amount realized. Effective for property placed in service after December 31, 1986, the amount of gain, if any, realized upon the disposition
of oil and gas property is treated as ordinary income up to the amount of intangible drilling and development costs incurred with respect to the property and depletion claimed to the extent it reduced
the taxpayer's basis in the property. Under this provision, depletion attributable to a unit acquired after 1986 will be subject to recapture as ordinary income upon disposition of the unit or upon
disposition of the oil and gas property to which the depletion is attributable. The balance of any gain or any loss will be capital gain or loss if the unit was held by the unitholder as a capital
asset, either long-term or short-term depending on the holding period of the unit. This capital gain or loss will be long-term if a unitholder's holding period exceeds one year at the time of sale or
exchange. Under current law, the highest marginal U.S. federal income tax rate applicable to long-term capital gains of individuals is 20%. Moreover, this rate is subject to change by new legislation
at any time. The deductibility of capital losses is subject to certain limitations. Capital gain or loss will be short-term if the unit has not been held for more than one year at the time of sale or
exchange.
Individuals, estates, and trusts with income above certain thresholds are subject under Section 1411 of the Code to an additional 3.8%
taxalso known as the Net Investment Income Tax ("NIIT")on their net investment income. Grantor trusts such as Mesa Royalty Trust are not subject to the NIIT; however, the
unitholders may be subject to the tax. For these purposes, investment income would generally include certain income derived from investments, such as the royalty income derived from the units and gain
realized by a unitholder from a sale of the units.
In general, a unitholder who is a nonresident alien individual or which is a foreign corporation, each a "non-U.S. unitholder" for purposes of
this discussion, will be subject to tax on the gross income (without taking into account any deductions, such as depletion) produced by the Royalty at a rate equal to 30% or, if applicable, at a lower
treaty rate. This tax will be withheld by the Trustee
and remitted directly to the U.S. Treasury. A non-U.S. unitholder may elect to treat Royalty income as effectively
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connected
with the conduct of a U.S. trade or business under provisions of the Code or pursuant to any similar provisions of applicable treaties. Upon making this election, a non-U.S. unitholder is
entitled to claim all deductions with respect to that income, but he must file a U.S. federal income tax return to claim these deductions. This election once made is irrevocable unless an
applicable treaty allows the election to be made annually.
The
Code and the Treasury Regulations thereunder treat the publicly traded Trust as if it were a U.S. real property holding corporation. Accordingly, a non-U.S. unitholder may be subject
to U.S. federal income tax on the gain on the disposition of his units if he meets certain ownership thresholds.
In
addition, if a foreign corporation elects under provisions of the Code to treat Royalty income as effectively connected with the conduct of a U.S. trade or business, the corporation
may also be subject to the U.S. branch profits tax at a rate of 30%. This tax is imposed on U.S. branch profits of a foreign corporation that are not reinvested in the U.S. trade or business and is in
addition to the tax on effectively connected income. The branch profits tax may be either reduced or eliminated by treaty. Federal income taxation of a non-U.S. unitholder is a highly complex matter
which may be affected by many considerations. Therefore, each non-U.S. unitholder is encouraged to consult with his own tax advisor with respect to its ownership of Trust units.
Pursuant
to the Foreign Account Tax Compliance Act (commonly referred to as "FATCA"), distributions from the Trust to "foreign financial institutions" and certain other "non-financial
foreign entities" may be subject to U.S. withholding taxes. Specifically, certain "withholdable payments" (including certain royalties, interest and other gains or income from U.S. sources) made to a
foreign financial institution or non-financial foreign entity will generally be subject to the withholding tax unless the foreign financial institution or non-financial foreign entity complies with
certain information reporting, withholding, identification, certification and related requirements imposed by FATCA. Foreign financial institutions located in jurisdictions that have an
intergovernmental agreement with the U.S. governing FATCA may be subject to different rules. Foreign unitholders are encouraged to consult their own tax advisors regarding the possible implications of
these withholding provisions on their investment in Trust units.
The Royalty and interest income should not be "unrelated business taxable income" (as defined in Code § 512(b)), so long as,
generally, a unitholder did not incur debt to acquire a unit or otherwise incur or maintain a debt that would not have been incurred or maintained if the unit had not been acquired. Legislative
proposals have been made from time to time which, if adopted, would result in the treatment of Royalty income as unrelated business taxable income. Each tax-exempt unitholder is encouraged to consult
its own advisor with respect to the treatment of Royalty income.
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DESCRIPTION OF ROYALTY PROPERTIES
Producing Acreage and Wells as of December 31, 2018:
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|
|
|
|
Producing Acres(1)
|
|
Producing
Gas
Wells(1)
|
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Hugoton Royalty Properties (Kansas)
|
|
|
99,654
|
|
|
99,413
|
|
|
476
|
|
|
413
|
|
San Juan Basin Royalty Properties (Northwestern New Mexico and Southwestern Colorado)
|
|
|
40,716
|
|
|
31,328
|
|
|
2,864
|
|
|
327
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
140,370
|
|
|
130,741
|
|
|
3,340
|
|
|
740
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
The
Trust does not have a working interest in the producing acres and producing gas wells. The gross and net amounts in the table above represent gross and net
amounts attributable to the Working Interest Owners and are the basis for the Gross Proceeds amounts discussed under "Description of the Trust".
Hugoton Royalty Properties
The principal property interest conveyed to the Trust accounts was carved out of Riviera's working interest in 104,437 net producing acres in
the Hugoton field of Kansas.
Because
the Hugoton field gas is sold in the intrastate and interstate markets, it is subject to state and federal laws and regulations. The Kansas Corporation Commission is the state
regulatory agency responsible for overseeing oil and gas operations in the state of Kansas. Hugoton field gas is also affected by the rules and regulations of the Federal Energy Regulatory Commission
(the "FERC"). See "Regulation and Prices".
San Juan Basin Royalty Properties
The Trust's interest in the San Juan Basin Royalty Properties was conveyed from PNR's working interest in 31,328 net producing acres in
Northwestern New Mexico and Southwestern Colorado. PNR completed the San Juan Basin Sale to ConocoPhillips on April 30, 1991. ConocoPhillips subsequently sold its underlying interest in
substantially all of the San Juan BasinColorado Properties to MarkWest Energy Partners, Ltd. (effective January 1, 1993) and Red Willow Production Company (effective
April 1, 1992). On October 26, 1994, MarkWest Energy Partners, Ltd. sold substantially all of its interest in the San Juan BasinColorado Properties to BP. Starting
from the date of the San Juan Basin Sale and ending on July 31, 2017, ConocoPhillips operated substantially all of the San Juan BasinNew Mexico Properties, except for an immaterial
number of properties assigned to XTO effective January 1, 2005. On July 31, 2017, ConocoPhillips sold its San Juan Basin assets to Hilcorp. On March 29, 2018, XTO sold to Hilcorp
an immaterial number of properties, which comprise certain portions of the San Juan BasinNew Mexico Properties.
Drilling
There were no exploratory wells drilled on any Royalty Properties during 2018, 2017 or 2016.
Reserves
A study of the proved oil and gas reserves covering the Hugoton Royalty Properties and San Juan Basin Royalty Properties (the "Reserve Report")
and attributable to the Trust has been made by DeGolyer and MacNaughton, independent petroleum engineering consultants, as of December 31, 2018. A copy of this Reserve Report has been filed as
Exhibit 99.1 to this Form 10-K. DeGolyer and
10
Table of Contents
MacNaughton
is a Delaware corporation with offices in Dallas, Houston, Atlanta, Moscow, Buenos Aires and Algiers. The firm's more than 150 professionals include engineers, geologists, geophysicists,
petrophysicists, and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies, and equity
studies related to the domestic and international energy industry. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own
operating interests in any oil, gas, or mineral properties, or securities or notes of clients. The firm subscribes to a code of professional conduct, and its employees actively support their related
technical and professional societies. In serving the petroleum industry and financial community, the firm's experienced staff provides knowledge, independent judgment, integrity, and confidential
service to its clients. The firm is a Texas Registered Engineering Firm, No. F-716.
The
Senior Vice President at DeGolyer and MacNaughton primarily responsible for overseeing the preparation of the Reserve Report is a Licensed Professional Engineer in the State of Texas
with more than 30 years of experience in the technical and commercial aspects of the global energy industry. He graduated from the University of Texas at Austin with a degree in Petroleum
Engineering in 1984 and he is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
The
Reserve Report reflects estimated production, reserve quantities and future net revenue based upon estimates of the future timing of actual production without regard to when received
in cash by the Trust, which differs from the manner in which the Trust recognizes and accounts for its Royalty income.
Estimates
of the gross and net proved reserves, as of December 31, 2018, of the Trust's ownership in the net overriding royalty interests in the Royalty Properties are presented
below. Total liquid reserves (condensate and natural gas liquids) are expressed in thousands of barrels (Mbbl) and gas reserves are expressed in thousands of cubic feet (Mcf).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BP
|
|
Hilcorp
|
|
Riviera
|
|
Total(1)
|
|
Proved Developed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Condensate
|
|
|
0
|
|
|
10
|
|
|
0
|
|
|
10
|
|
Natural Gas Liquids
|
|
|
0
|
|
|
398
|
|
|
35
|
|
|
433
|
|
Gas
|
|
|
1,143
|
|
|
5,482
|
|
|
667
|
|
|
7,292
|
|
Proved Undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Condensate
|
|
|
0
|
|
|
0
|
|
|
0
|
|
|
0
|
|
Natural Gas Liquids
|
|
|
0
|
|
|
0
|
|
|
0
|
|
|
0
|
|
Gas
|
|
|
0
|
|
|
0
|
|
|
0
|
|
|
0
|
|
Total, Proved
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Condensate
|
|
|
0
|
|
|
10
|
|
|
0
|
|
|
10
|
|
Natural Gas Liquids
|
|
|
0
|
|
|
398
|
|
|
35
|
|
|
433
|
|
Gas
|
|
|
1,143
|
|
|
5,482
|
|
|
667
|
|
|
7,292
|
|
-
(1)
-
Data
from Red Willow and properties formerly operated by XTO, currently operated by Hilcorp, was omitted in the Reserve Report, because each operates an immaterial
number of wells relative to the total number of wells currently producing from the Royalty Properties. Excess production costs related to Red Willow and properties formerly operated by XTO, currently
operated by Hilcorp, as of December 31, 2018 and 2017 are included in Net Proceeds paid to the Trust by Red Willow and Hilcorp.
The
estimated future net revenue and standardized measure of future net royalty income, discounted at 10 percent per annum attributable to the Trust's Royalty as of
December 31, 2018 is
11
Table of Contents
summarized
in the table below. These estimates are provided based upon the economic assumptions furnished by the Working Interest Owners, and are expressed in thousands of dollars:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BP
|
|
Hilcorp
|
|
Riviera
|
|
Total
|
|
Future Royalty income(1)
|
|
$
|
1,371
|
|
$
|
16,284
|
|
$
|
3,228
|
|
$
|
20,883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BP
|
|
Hilcorp
|
|
Riviera
|
|
Total
|
|
Standardized Measure of Future Net Royalty Income, discounted at 10% per annum(1)
|
|
$
|
821
|
|
$
|
7,606
|
|
$
|
2,213
|
|
$
|
10,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Future
income tax expenses were excluded in the preparation of these estimates.
Please
read "Summary Reserve Report from DeGolyer and MacNaughton" attached hereto as Exhibit 99.1 for more information.
The
Reserve Report was delivered to the Trustee on March 29, 2019. Net reserves of the Trust's Royalty are calculated at the aggregate level from the net revenue of each of the
Working Interest Owners. To estimate net gas reserves, the total net revenue of the Working Interest Owners is divided by the net value of 1 Mcf of gas. The net value of 1 Mcf of gas is the gas price
per Mcf, plus the condensate value per Mcf of gas, plus the NGL value per Mcf of gas. The net condensate and NGL reserves are calculated by multiplying their respective yields by the net gas reserves.
Revenue values used in the Reserve Report were estimated using the following prices: (1) condensate prices$33.93 per Bbl; (2) natural gas liquids prices$14.73
per Bbl for the San Juan Basin Royalty Properties and $25.98 per Bbl for Hugoton Royalty Properties; and (3) natural gas prices$1.84 per Mcf for San Juan Basin-New Mexico Royalty
Properties, $1.20 per Mcf for San Juan Basin-Colorado Royalty Properties and $3.46 per Mcf for Hugoton Royalty Properties, with the initial prices also used as weighted average prices held constant
thereafter over the lives of the properties. Estimates of operating expenses were based on current expenses and used for the life of the Royalty Properties with no increases in the future based on
inflation.
Preparation of Reserve Estimates
For further information regarding the Net Overriding Royalty Interest, the Basis of Accounting and Supplemental Reserve Information, see
Notes 1, 2 and 7, respectively, in the Notes to Financial Statements contained in Item 8 of this Form 10-K.
There
are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures, including
many factors beyond the control of the producer. Reserve data included above and in these reports represents estimates only and should not be construed as being exact. The discounted present values
shown by the Reserve Report should not be construed as the current market value of the estimated gas and oil reserves attributable to the Royalty Properties or the costs that would be incurred to
obtain equivalent reserves, since a market value determination would include many additional factors.
The
Trustee has been advised that each of the foregoing estimates were prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board
("FASB"). Accordingly, the estimates are based on existing economic and operating conditions in effect at December 31, 2018, with no provision for future increases or decreases except for
periodic price redeterminations in accordance with existing gas contracts. Actual future prices and costs may be materially greater or less than the assumed amounts in the reserve reports. Because
reserve reports are limited to proved reserves, future capital expenditures for recovery of reserves not classified as proved are not included in the calculation of estimated future net revenues.
Reserve assessment is a subjective
12
Table of Contents
process
of estimating the recovery from underground accumulations of gas and oil that cannot be measured in an exact way, and estimates of other persons might differ materially from those of DeGolyer
and MacNaughton. Accordingly, reserve estimates are often different from the quantities of hydrocarbons that are ultimately recovered.
The
Trustee relies on DeGolyer and MacNaughton to prepare the reserve estimates attributable to the Trust's interests in the Royalty Properties. Although the Trustee inquires with the
third-party reserve engineer about the information provided by the Working Interest Owners and the assumptions made and methodologies used by the third-party reserve engineer, the Trustee does not
control the information provided by the Working Interest Owners or the assumptions made or methodologies used by the third-party reserve engineer. Accordingly, such information is outside the scope of
the internal controls of the Trust and the Trustee. Any past practices not consistent with the Conveyance could also cause the basis for the reserve estimates included above to differ from actual
reserve quantities and future net revenues.
Income, Production and Production Prices and Production Costs
Sales and production data from the Royalty Properties for the last three fiscal years is included in the table below. For additional information
related to our Reserve Report, see "Note 7Supplemental Reserve Information" under Item 8 of this Form 10-K.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hugoton
|
|
San Juan BasinNew
Mexico(4)
|
|
San Juan BasinColorado
|
|
Total
|
|
|
|
Natural
Gas
|
|
Natural
Gas
Liquids
|
|
Oil and
Condensate
|
|
Natural
Gas
|
|
Natural
Gas
Liquids
|
|
Oil and
Condensate
|
|
Natural
Gas
|
|
Natural
Gas
Liquids
|
|
Oil and
Condensate
|
|
Natural
Gas
|
|
Natural
Gas
Liquids
|
|
Oil and
Condensate
|
|
Year ended December 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price
|
|
$
|
3.46
|
|
$
|
25.98
|
|
$
|
|
|
$
|
2.04
|
|
$
|
16.28
|
|
$
|
37.59
|
|
$
|
1.32
|
|
$
|
|
|
$
|
|
|
$
|
2.03
|
|
$
|
19.31
|
|
$
|
37.59
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Costs(1)
|
|
$
|
5.49
|
|
$
|
40.45
|
|
$
|
|
|
$
|
1.30
|
|
$
|
10.28
|
|
$
|
22.93
|
|
$
|
0.39
|
|
$
|
|
|
$
|
|
|
$
|
1.69
|
|
$
|
19.71
|
|
$
|
22.93
|
|
Net production volumes attributable to the
|
|
|
(Mcf
|
)
|
|
(Bbls
|
)
|
|
(Bbls
|
)
|
|
(Mcf
|
)
|
|
(Bbls
|
)
|
|
(Bbls
|
)
|
|
(Mcf
|
)
|
|
(Bbls
|
)
|
|
(Bbls
|
)
|
|
(Mcf
|
)
|
|
(Bbls
|
)
|
|
(Bbls
|
)
|
Royalty paid(2)
|
|
|
147,685
|
|
|
9,553
|
|
|
|
|
|
395,629
|
|
|
21,015
|
|
|
399
|
|
|
309,558
|
|
|
|
|
|
|
|
|
852,872
|
|
|
30,568
|
|
|
399
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price
|
|
$
|
3.66
|
|
$
|
22.87
|
|
$
|
|
|
$
|
2.20
|
|
$
|
16.17
|
|
$
|
37.91
|
|
$
|
1.61
|
|
$
|
|
|
$
|
|
|
$
|
2.36
|
|
$
|
19.24
|
|
$
|
37.91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Costs(1)
|
|
$
|
2.03
|
|
$
|
12.99
|
|
$
|
|
|
$
|
1.80
|
|
$
|
13.10
|
|
$
|
31.56
|
|
$
|
0.39
|
|
$
|
|
|
$
|
|
|
$
|
1.31
|
|
$
|
13.05
|
|
$
|
31.56
|
|
Net production volumes attributable to the
|
|
|
(Mcf
|
)
|
|
(Bbls
|
)
|
|
(Bbls
|
)
|
|
(Mcf
|
)
|
|
(Bbls
|
)
|
|
(Bbls
|
)
|
|
(Mcf
|
)
|
|
(Bbls
|
)
|
|
(Bbls
|
)
|
|
(Mcf
|
)
|
|
(Bbls
|
)
|
|
(Bbls
|
)
|
Royalty paid(2)
|
|
|
262,789
|
|
|
15,921
|
|
|
|
|
|
341,305
|
|
|
18,771
|
|
|
774
|
|
|
383,409
|
|
|
|
|
|
|
|
|
987,503
|
|
|
34,692
|
|
|
774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price
|
|
$
|
2.86
|
|
$
|
11.38
|
|
$
|
|
|
$
|
1.64
|
|
$
|
12.40
|
|
$
|
31.25
|
|
$
|
1.21
|
|
$
|
|
|
$
|
|
|
$
|
1.74
|
|
$
|
12.00
|
|
$
|
31.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Costs(1)
|
|
$
|
5.98
|
|
$
|
22.02
|
|
$
|
|
|
$
|
2.27
|
|
$
|
17.28
|
|
$
|
39.58
|
|
$
|
1.36
|
|
$
|
|
|
$
|
|
|
$
|
2.70
|
|
$
|
19.12
|
|
$
|
39.58
|
|
Net production volumes attributable to the
|
|
|
(Mcf
|
)
|
|
(Bbls
|
)
|
|
(Bbls
|
)
|
|
(Mcf
|
)
|
|
(Bbls
|
)
|
|
(Bbls
|
)
|
|
(Mcf
|
)
|
|
(Bbls
|
)
|
|
(Bbls
|
)
|
|
(Mcf
|
)
|
|
(Bbls
|
)
|
|
(Bbls
|
)
|
Royalty paid(2)(3)
|
|
|
121,662
|
|
|
9.608
|
|
|
|
|
|
267,253
|
|
|
15,142
|
|
|
829
|
|
|
210,532
|
|
|
|
|
|
|
|
|
599,447
|
|
|
24,750
|
|
|
829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Average
production costs attributable to the Royalty are calculated as stated capital costs plus operating costs, divided by stated net production volumes
attributable to the Royalty paid. Production costs may be incurred in one operating period and then recovered in a subsequent operating period, which may cause Royalty income paid to the Trust not to
agree to the Trust's Royalty interest in the Net Proceeds.
-
(2)
-
Net
production volumes attributable to the Royalty are determined by dividing Royalty income by the average sales price received. Any differences noted are due to
rounding.
-
(3)
-
In
order to more closely align the reporting and payment of Royalty income from the San Juan BasinColorado Properties operated by BP, the Trustee
elected to report BP's production from December 2016 for the year ended December 31, 2016. Historically, BP's December production month has correlated to the Trust's January accounting month.
However, such election did not impact Royalty income or cash in the Trust's financial statements for the year ended December 31, 2016, because the San Juan BasinColorado Properties
operated by BP generated excess production costs of $3,860 during the December 2016 production month and no payment was due to the Trust by BP. The effect of the Trustee's election to include the
December 2016 production month for the year ended December 31, 2016 is as follows: (i) the Summary of Royalty Income, Production, Prices and Costs include the Trust's proportionate share
of gross proceeds of $68,327, the Trust's proportionate share of operating costs of $72,187, and net production volumes attributable to the Royalty paid of 40,163 Mcf, and (ii) $3,860 of excess
production costs related to the San Juan BasinColorado Properties operated by BP as of December 31, 2016 were included in the Excess Production Costs footnote to the Trust's
financial statements for the year ended December 31, 2016.
-
(4)
-
Following
Hilcorp's acquisition of ConocoPhillips' and XTO's interests in the San JuanNew Mexico Properties, Hilcorp has made an estimated payment of
Net Proceeds to the Trust each month consistent with the monthly amounts previously paid by ConocoPhillips and XTO. As a result of the payment of estimated Net Proceeds, Hilcorp has informed the Trust
that it will reconcile estimated versus actual revenue figures once it finalizes installation of its revenue decks, although Hilcorp has not indicated when such reconciliation may occur. At the time
that Hilcorp reconciles estimated versus actual revenue numbers, such estimations and reconciliations by Hilcorp will be added to or subtracted from future Net Proceeds paid to the Trust in accordance
with the Trust's basis of financial presentation. Pursuant to the Trust Indenture, the Trust is not required to pay to Hilcorp any amounts that could be owed if the estimated revenue exceeded actual
revenue figures in past periods, plus any additional required costs. However, Hilcorp may recover such amounts by withholding a portion or all of Net Proceeds that would otherwise be payable to the
Trust in subsequent periods. This could result in a decrease in Net Proceeds paid to the Trust and could result in a future material reduction in distributions to the Trust's unitholders.
13
Table of Contents
CONTRACTS
Hugoton Royalty Properties
Natural gas and natural gas liquids produced by Riviera (formerly Linn) from the Hugoton Royalty Properties accounted for approximately 33% of
the Royalty income of the Trust for the year ended December 31, 2018. Riviera has advised the Trust that since June 1, 1995 natural gas produced from the Hugoton field has generally been
sold under short-term and multi-month contracts at market clearing prices to multiple purchasers. Riviera has advised the Trust that it expects to continue to market natural gas production from the
Hugoton field under short-term and multi-month contracts. Overall average daily market prices received for natural gas from Hugoton Royalty Properties were lower for the year ended December 31,
2018 as compared to the year ended December 31, 2017. For the year ended December 31, 2018, Riviera has provided and continues to provide Process (as defined in the Conveyance) services
for the Hugoton Royalty Properties, and such services are charged against the Royalty in accordance with the terms of the Conveyance.
San Juan Basin
Natural gas, oil, condensate and natural gas liquids produced from the San Juan Basin Royalty Properties accounted for approximately 67% of the
Royalty income of the Trust for the year ended December 31, 2018. The majority of the natural gas produced from the San Juan Basin Royalty Properties is now being sold on the spot market.
Market for Natural Gas
The amount of cash distributions by the Trust is dependent on, among other things, the sales prices realized for natural gas produced from the
Royalty Properties and the quantities of gas sold. According to the U.S. Energy Information Administration of the Department of Energy, the Henry Hub Natural Gas Spot Prices were $2.99 per MMBtu in
2017 and increased to $3.17 per MMBtu in 2018. Due to the seasonal nature of demand for natural gas and its effects on sales prices and production volumes, the amounts of cash distributions by the
Trust may vary substantially on a seasonal basis. Generally, production volumes and prices are higher during the first and fourth quarters of each calendar year due primarily to peak demand in those
periods. Because of the time lag between the date on which the Working Interest Owners receive payment for production from the Royalty Properties and the date on which distributions are made to
unitholders, the seasonality that generally affects production volumes and prices is generally reflected in distributions to unitholders in later periods. Henry Hub Natural Gas Spot Prices are quoted
in MMBtu, a commonly used energy measurement that has a conversion formula defined and published by the SEC for the purpose of estimating price per Mcf in the Reserve Report.
Competition
The production and sale of gas from the Royalty Properties are highly competitive, and the Working Interest Owners' competitors in these areas
include the major oil and gas companies, independent oil and gas companies, and individual producers and operators. There are numerous producers in the Hugoton field and the San Juan Basin. The
Working Interest Owners have advised the Trust that they believe that their competitive position in their respective areas is affected by price, contract terms and quality of service. Riviera has also
advised the Trust that it believes that its competitive position in the Hugoton field is enhanced by virtue of its substantial holdings and ownership and control of its wells, gathering systems and
processing plants. Market conditions in the San Juan Basin are negatively affected by the fact that most of the gas produced from such areas is
transported on one of only two major pipelines, and the transportation of such gas is generally controlled by a few distribution companies.
14
Table of Contents
REGULATION AND PRICES
General
The production and sale of natural gas from the Royalty Properties are affected from time to time in varying degrees by political developments
and federal, state and local laws and regulations. In particular, oil and gas production operations and economics are, or in the past have been, affected by price controls, taxes, conservation,
safety, environmental and other laws relating to the petroleum industry, by changes in such laws, and by constantly changing administrative regulations.
FERC Regulation
In general, the Federal Energy Regulatory Commission (the "FERC") regulates the sale of natural gas in interstate commerce for resale and the
transportation of natural gas in interstate commerce by pipelines, but does not regulate natural gas gathering facilities. The FERC adopted regulations resulting in a restructuring of the natural gas
industry. The principal elements of this restructuring were the requirement that interstate pipelines separate, or "unbundle," into individual components the various services offered on their systems,
with all transportation services to be provided on a non-discriminatory basis, and the prohibition against an interstate pipeline providing gas sales services except through separately-organized
affiliates. In various rulemaking proceedings following its initial unbundling requirement, the FERC has refined its regulatory program applicable to interstate pipelines in various respects, and it
has announced that it will continue to monitor these and other regulations to determine whether further changes are needed. In addition to rulemaking proceedings, the FERC establishes new policies and
regulations through policy statements and adjudications of individual pipeline matters. Further, additional changes to regulations may occur based on actions taken by Congress and/or the courts. As to
these various developments, the Working Interest Owners have advised the Trust that the on-going and evolving nature of these regulatory initiatives makes it impossible to predict their ultimate
impact on the prices, markets or terms of sale of natural gas related to the Trust.
In
the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress
could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act of 1978 and culminated in adoption of the Natural Gas
Wellhead Decontrol Act that removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.
Sales
of crude oil, condensate, and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls at any time in
the future. Sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is subject to rate and access regulation. The
FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be just and reasonable and may be derived in a number of
ways including, but not limited to, the FERC's indexing methodology.
As
to these various types of regulation, the on-going and evolving nature of these regulatory initiatives makes it impossible to predict their ultimate impact on the prices, markets or
terms of sale of natural gas related to the Trust.
State and Other Regulation
Each of the jurisdictions encompassing the Royalty Properties has statutory provisions regulating the production and sale of crude oil and
natural gas. The regulations often require permits for the drilling of wells and may specify rules related to the spacing of wells, the prevention of waste of oil and gas resources, the rate of
production, the prevention and clean-up of pollution, and other matters.
15
Table of Contents
State
regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take and common purchaser requirements, as well
as complaint-based rate regulation.
Natural
gas pipeline facilities used for the transportation of natural gas in interstate commerce are subject to federal minimum safety requirements. These requirements, however, are not
applicable to, among other things, onshore gathering of gas (i) through a pipeline that operates at less than 0 psig; (ii) through a pipeline that is not a regulated onshore gathering
line (as determined in 49 C.F.R. § 192.8); and (iii) within the inlets of the Gulf of Mexico, except for the requirements in 49 C.F.R. § 192.612. The
Royalty Properties are located in the Hugoton field of Kansas and the San Juan Basin of New Mexico and Colorado. Each of Colorado, Kansas and New Mexico has adopted the federal minimum safety
requirements for intrastate pipelines within their borders. The standards governing pipeline safety have undergone recent changes, and it is possible that future changes in applicable law may increase
the stringency of the standards or expand the applicability of the standards to facilities not currently covered.
Environmental Matters
The Working Interest Owners' operations are subject to numerous federal, state and local laws and regulations controlling the discharge and
release of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations, including their state counterparts, can impose liability upon the
owner, operator or lessee under a lease for the cost of
cleanup of discharged and released materials or damages to natural resources resulting from oil and gas operations. These laws and regulations may, among other
things:
-
-
restrict the types, quantities and concentration of various substances that can be discharged and released into the environment in connection
with oil and natural gas drilling and production activities;
-
-
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
-
-
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned
wells.
Violations
of environmental laws, regulations, or permits can result in civil and criminal penalties as well as potential injunctions curtailing operations in affected areas. The Working
Interest Owners have advised the Trust that they are not at this time involved in any administrative or judicial proceedings relating to the Royalty Properties arising under federal, state or local
environmental protection laws and regulations or which would have a material adverse effect on the Working Interest Owners' financial position or results of operations. The Working Interest Owners
have also advised the Trust that they maintain insurance for costs of cleanup obligations, but that they are not fully insured against all such risks.
The
following is a summary of certain material laws, rules and regulations to which the operations of the Royalty Properties may be subject.
Hazardous Substances.
The Comprehensive Environmental Response, Compensation and Liability Act, referred to as "CERCLA" or the Superfund
law, and
comparable state laws impose liability, potentially without regard to fault or legality of the activity at the time, on certain classes of persons that are considered to be responsible for the release
of a hazardous substance into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or
arranged for the disposal of hazardous substances that have been released at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of investigating and
cleaning up hazardous substances that have been released into
16
Table of Contents
the
environment, for damages to natural resources and for the costs of health studies. In addition, neighboring landowners and other third parties may file claims for personal injury and property
damage allegedly caused by hazardous substances or other pollutants released into the environment.
The
Royalty Properties have been used for oil and natural gas exploration and production for many years. Although the Working Interest Owners believe that they have utilized operating
and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties, or on or under other
locations, including off-site locations, where such substances have been taken for disposal. In addition, the Royalty Properties may have been operated by third parties or by previous owners or
operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under the Working Interest Owners' control. These properties and the substances disposed or released on
them may be subject to CERCLA, federal hazardous waste laws, and analogous state laws. Under such laws, the Working Interest Owners could be required to remove previously disposed substances and
wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination regardless of whether or not such Working Interest Owner directly or
indirectly caused the unpermitted discharge or release.
In
addition, in the course of the Working Interest Owners' operations, equipment may be exposed to naturally occurring radiation associated with oil and natural gas deposits, and this
exposure may result in the generation of wastes containing naturally occurring radioactive materials ("NORM"). NORM wastes exhibiting trace levels of naturally occurring radiation in excess of
established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration
requirements. Because some properties presently or previously comprising the Royalty Properties may have been used for oil and natural gas production operations for many years, it is possible that the
Working Interest Owners may incur costs or liabilities associated with elevated levels of NORM.
Waste Handling.
The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as
"RCRA," and
comparable state statutes, regulate the management and disposal of solid and hazardous waste. Some wastes associated with the exploration and production of oil and natural gas are exempted from the
most stringent regulation in certain circumstances, such as drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas.
However, these wastes and other wastes may be otherwise regulated by the Environmental Protection Agency (the "EPA") or state agencies. Moreover, in the ordinary course of oil and gas operations,
industrial wastes such as paint wastes and waste solvents may be regulated as hazardous waste under RCRA or considered hazardous substances under CERCLA. It is
possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future.
Water Discharges.
The Federal Water Pollution Control Act (the "Clean Water Act") and analogous state laws, impose restrictions and
strict controls
with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into regulated waters. The Oil Pollution Act of 1990 (the "OPA"), as amended, which amends the
Clean Water Act, imposes strict liability on owners and operators of facilities that are the site of a release of oil into regulated waters. The OPA and its associated regulations impose a variety of
requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. Spill prevention, control and countermeasure requirements under
federal or state law may require appropriate operating protocols, including containment berms and similar structures, to help prevent or respond to a petroleum hydrocarbon spill, rupture or leak. In
addition, the Clean Water Act and analogous state laws may require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities or during
construction activities.
17
Table of Contents
Hydraulic Fracturing.
It is customary to recover oil and natural gas from deep shale, tight sand and coal bed formations through the use
of hydraulic
fracturing, combined with sophisticated horizontal drilling. Conventional hydraulic fracturing techniques are used to increase production in vertical wells. Hydraulic fracturing involves the injection
of water, sand and chemical additives under pressure into rock formations to stimulate gas production. The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the
federal Safe Drinking Water Act to exclude certain hydraulic fracturing activities from the definition of "underground injection." At present, hydraulic fracturing is regulated at the state and local
level. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal, state and local level and in some
states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Repeal of the exemption would allow the EPA to promulgate
new regulations. Many states have adopted rules that required operators to disclose chemicals and water volumes associated with hydraulic fracturing. In addition, hydraulic fracturing requires large
amounts of water. This water, along with any produced water, is often sent to injection wells for disposal. This activity has been associated with earthquakes and some states, particularly Oklahoma,
have limited injection well activity. If states in which the Working Interest Owners' operate adopt limitations, it could have a negative impact on production.
Air Emissions.
The federal Clean Air Act, and comparable state laws, restrict the emission of air
pollutants from many sources, including drilling operations and related equipment, and as a result affect oil and natural gas operations. The EPA has also developed, and continues to give attention
to, stringent regulations governing emissions of toxic air pollutants at specified sources, including oil and gas operations. Air emissions permits may be required for some oil and gas production
operations.
Climate Change.
The EPA has promulgated certain regulations that require new and modified stationary source of greenhouse gases above
certain
thresholds to report, limit or control such emissions, including rules to control methane emissions. Although subject to legal challenge, the EPA rules promulgated thus far are currently final and
effective and will remain so unless overturned by a court, or unless Congress adopts legislation altering the EPA's regulatory authority. Recently, EPA proposed rules to stay certain portions of the
rules promulgated to control greenhouse gas emission related to oil and gas production. In addition, some states have taken or proposed legal measures to reduce emissions of greenhouse gases. For
example, a number of states, including states in which the Royalty Properties are located, have indicated an intent to reduce greenhouse gases through state action or regional partnerships.
Safety.
The Working Interest Owners are also subject to the requirements of the federal Occupational Safety and Health Act, known as
"OSHA," and
comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous
materials used or produced by oil and gas operations and that this information be provided to employees, state and local government authorities and the public.
Item 1A. Risk Factors.
Although risk factors are described elsewhere in this Form 10-K together with the Disclosures Regarding Forward-Looking Statements, the
following is a summary of the principal risks associated with an investment in the Trust's units.
Oil and natural gas prices fluctuate due to a number of factors, and lower prices will reduce net proceeds
available to the Trust and distributions to Trust unitholders.
Net proceeds and the Trust's quarterly distributions are highly dependent upon the prices realized from the sale of natural gas and a material
decrease in such prices could reduce the amount of Trust
18
Table of Contents
distributions.
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 the Working Interest Owners. Factors
that contribute to price fluctuation include, among others:
-
-
political conditions worldwide, in particular political disruption, war or other armed conflicts in oil producing regions;
-
-
worldwide economic conditions;
-
-
weather conditions;
-
-
the supply and price of foreign natural gas;
-
-
the level of 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, regulation of greenhouse gas and other emissions associated with fossil fuel combustion, and price
controls, can affect product prices in the long term.
Crude
oil prices have been volatile the last several years and, since the second half of 2014 have declined substantially from historic highs and may remain depressed for the foreseeable
future. In 2018, crude oil prices per Bbl ranged from a high of approximately $77.41 to a low of approximately $44.48. The NYMEX crude oil spot prices per Bbl were $45.15 and $60.46 as of
December 31, 2018 and 2017 respectively. The Trust cannot predict the timing or the duration of any economic cycle and, depending on the prices realized, the financial condition of the Trust
could be materially adversely affected. When natural gas prices decline, the Trust is affected in two ways. First, net royalties are reduced. Second, exploration and development activity on the
underlying properties may decline as some projects may become uneconomic and are either delayed or eliminated. The volatility of energy prices reduces the predictability of future cash distributions
to unitholders. Substantially all of the natural gas and natural gas liquids produced from the Royalty Properties are being sold under short-term or multi-month contracts at market clearing prices or
on the spot market.
Any additional decreases in prices of natural gas may materially and adversely affect our cash generated from
operations, results of operations and reduce net proceeds available to the Trust and distributions to Trust unitholders.
During the eight years prior to December 31, 2018, Henry Hub natural gas prices have ranged from a high of $8.15 per MMBtu in 2014 to a
low of $1.49 per MMBtu in 2016. On
December 31, 2018, the Henry Hub Natural Gas Spot Price was $3.25 per MMBtu. The reduction in prices has been caused by many factors, including increases in natural gas production and reserves
from unconventional (shale) reservoirs, without an offsetting increase in demand. The expected increase in natural gas production could cause the prices for natural gas to remain at current levels or
fall to lower levels. If prices for natural gas continue to remain depressed for lengthy periods, we may be required to write down the value of our oil and gas properties. In addition, sustained low
prices for gas will negatively impact the value of our estimated reserves and reduce net proceeds and the amount of cash we would otherwise have available to pay cash distributions to unitholders.
Increased production and development costs for the Royalty will result in decreased Trust distributions.
Production and development costs attributable to the Royalty are deducted in the calculation of the Trust's share of net proceeds. Production
and development costs are impacted by increases in
19
Table of Contents
commodity
prices both directly, through commodity-price dependent costs such as electricity, and indirectly, as a result of demand-driven increases in costs of oil field goods and services.
Accordingly, higher or lower production and development costs, without concurrent increases in revenues, directly decrease or increase the amount received by the Trust for the Royalty.
If
development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust will not receive net proceeds for those properties until
future proceeds from production 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. Accordingly, there may not be sufficient net proceeds to make a particular distribution.
The Trust has established a cash reserve for contingent liabilities and to pay expenses in accordance with
the Trust Indenture, which would reduce Net Proceeds available to the Trust and distributions to Trust unitholders.
The Trust's source of capital is the Royalty income received from its share of the net proceeds from the Royalty Properties. Pursuant to the
Trust Indenture, the Trust may establish a cash reserve through the withholding of cash for contingent liabilities and to pay expenses. In 2011, the
Trustee established a cash reserve for contingent liabilities and expenses in accordance with the Trust Indenture and withheld approximately $83,333 per monthly distribution amount, or up to $250,000
per quarter, until the cash reserve was $1.0 million, which reduced net proceeds available to the Trust and distributions to Trust unitholders. For more information, see "Trustee's Discussion
and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources" under Item 7 of this Form 10-K.
Trust reserve estimates depend on many assumptions that may prove to be inaccurate, which could cause both
estimated reserves and estimated future revenues to be too high or too low.
The value of the units of beneficial interest of the Trust depends upon, among other things, the amount of reserves attributable to the Royalty
and the estimated future value of the reserves. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from
estimates and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating reserves. Those factors and assumptions
include:
-
-
historical production from the area compared with production rates from similar producing areas;
-
-
the assumed effect of governmental regulation;
-
-
assumptions about future commodity prices, production and development costs, severance and excise taxes, and capital expenditures;
-
-
the availability of enhanced recovery techniques; and
-
-
relationships with landowners, working interest partners, pipeline companies and others.
Changes
in these factors and assumptions can materially change reserve estimates and future net revenue estimates.
The
reserve quantities attributable to the Royalty and revenues are based on estimates of reserves and revenues for the underlying properties. The method of allocating a portion of those
reserves to the Trust is further complicated because the Trust holds an interest in the Royalty and does not own a specific percentage of the natural gas reserves. Ultimately, actual production,
revenues and expenditures for the underlying properties, and therefore actual net proceeds payable to the Trust, will
20
Table of Contents
vary
from estimates and those variations could be material. Results of drilling, testing and production after the date of those estimates may require substantial downward revisions or write-off of
reserves.
Operating risks for the Working Interest Owners' interests in the Royalty Properties can adversely affect
Trust distributions.
There are operational risks and hazards associated with the production and transportation of natural gas, including without limitation natural
disasters, blowouts, explosions, fires, leakage of 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, or damage to the environment or natural resources, and
associated cleanup obligations. The occurrence of drilling, production or transportation accidents and other natural disasters at any of the Royalty Properties will reduce Trust distributions by the
amount of uninsured costs. These occurrences include blowouts, cratering, explosives and other environmental damage that may result in personal injuries, property damage, and damage to productive
formations or equipment and environmental damages. Any uninsured costs would be deducted as a production cost in calculating net proceeds payable to the Trust.
Most
of the gas produced in the San Juan Basin is transported on one of only two major pipelines in the area, and transportation of this gas is generally controlled by a small number of
distribution
companies. Accordingly, any disruptions to transportation lines or increases in transportation costs for production from these properties could also affect the Trust.
Further,
the present value of future net cash flows from proved reserves may not be the current market value of estimated natural gas and oil reserves attributable to the Royalty. In
accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on the 12-month average oil and gas index prices, calculated as the un-weighted arithmetic
average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future
prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the
current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the FASB in Accounting Standards
Codification 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.
Terrorism and continued hostilities in the Middle East could decrease Trust distributions or the market price
of the units of beneficial interest of the Trust.
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 sustained military campaigns could adversely affect Trust distributions or the market price of the units in unpredictable
ways, including through the disruption of fuel supplies and markets, increased volatility in natural gas prices, or the possibility that the infrastructure on which the operators developing the
underlying properties rely could be a direct target or an indirect casualty of an act of terror.
The Working Interest Owners are subject to extensive governmental regulation.
Oil and gas operations have been, and in the future will be, affected by federal, state and local laws and regulations and other political
developments, such as price or gathering rate controls and environmental protection regulations. These regulations and changes in regulations could have a material adverse effect on Royalty income
payable to the Trust.
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The Working Interest Owners' operations are subject to environmental, health and safety laws and regulations
that may expose the Working Interest Owners to penalties, damages or costs of remediation or compliance which could adversely affect Trust distributions.
The Working Interest Owners' operations are subject to federal, regional, state and local laws and regulations relating to protection of natural
resources and the environment, health and safety aspects of oil and gas operations and waste management, including the transportation and disposal of waste and other materials. These laws and
regulations may impose numerous obligations on such operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to mitigate or prevent
releases of materials from facilities, the imposition of substantial liabilities for pollution resulting from operations and the application of specific health and safety criteria addressing worker
protection. Failure to comply with these laws and regulations could result in restrictions or orders suspending well operations, the assessment of administrative, civil and criminal penalties, the
revocation of permits and the issuance of corrective action orders.
There
is inherent risk of environmental costs and liabilities in the oil and gas business as a result of the handling of petroleum hydrocarbons and oilfield and industrial wastes, air
emissions and wastewater discharges related to current operations as well as historical industry operations and waste disposal practices. Some environmental laws and regulations may impose strict
liability, which means that in some situations, the Working Interest Owners could be exposed to liability as a result of conduct that was without fault or lawful at the time it occurred or as a result
of the conduct of, or conditions caused by, prior operators or other third parties. Clean-up costs and other damages arising as a result of environmental laws and costs associated with changes in
environmental laws and regulations could be substantial and could have a material adverse effect on Trust distributions.
Laws
protecting the environment generally have become more stringent over time and are expected to continue to do so, which could lead to material increases in costs for future
environmental compliance and remediation. The modification or interpretation of existing laws or regulations, or the adoption of new laws or regulations, could curtail exploratory or developmental
drilling for oil and natural gas. The Working Interest Owners may not be able to recover some or any of such costs of compliance with these laws and regulations from insurance.
Please
read "BusinessRegulation and PricesEnvironmental Matters" under Item 1 of this Form 10-K for more information on the environmental laws and
government regulations that may be applicable to the Working Interest Owners' operations.
Physical effects of climatic change have the potential to damage the facilities of the Working Interest
Owners, disrupt production activities on the Royalty Properties, and cause the Working Interest Owners to incur significant costs in preparing for or responding to those effects and can adversely
affect Trust distributions as a result.
Scientific studies and government reports, such as those published by the Intergovernmental Panel on Climate Change established by the United
Nations and World Meteorological Organization indicate that climate change could have global, regional or local effects on the severity of weather (including hurricanes, floods and droughts), sea
levels, arability of farmland, and water availability and quality, including predicted effects on areas in which the Royalty Properties are located. If such effects were to occur, exploration and
production operations of the Royalty Properties have the potential to be adversely affected. Potential adverse effects could include damages to the facilities of the Working Interest Owners or
disruption of production activities associated with weather related events, scale-backs in operations on the Royalty Properties due to the threat of such climatic effects, and increases in costs of
operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climatic effects or increased costs for insurance coverage. The Working
Interest Owners may not be able to recover through insurance some or any of the damages,
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losses
or costs that may result from potential physical effects of climate change and can adversely affect Trust distributions as a result.
The
Trustee relies entirely on reserve estimates and related information prepared by DeGolyer and McNaughton based on information provided by the Working Interest Owners. While the
Trustee has no reason to believe the reserve estimates included in this report are not accurate, to the extent additional information exists that could affect their reserve estimates, the estimated
reserves in these reports could also be too low.
Climate change legislation or regulations restricting or regulating emissions of greenhouse gases could
result in increased operating costs and could adversely affect Trust distributions.
The EPA has adopted various regulations under the federal Clean Air Act addressing emissions of greenhouse gases that may affect the oil and gas
industry, including mandatory reporting and emission reduction. Such changes will affect state air permitting programs in states that administer the federal Clean Air Act under a delegation of
authority, including states in which the Royalty Properties are located. Some states have also indicated an intent to regulate or impose restrictions or costs on greenhouse gas emissions or fossil
fuels. The adoption and implementation of any international treaty or of any federal or state legislation or regulations imposing restrictions on emissions of greenhouse gases could require the
Working Interest Owners to incur costs to comply with such requirements and possibly require the reduction or limitation of emissions of greenhouse gases associated with the Working Interest Owners'
operations or could impose costs on other sources of emissions within the industrial or energy sectors. Such legislation or regulations could adversely affect demand for the production of oil and
natural gas and increase operating costs by requiring additional expenditures to operate and maintain equipment and facilities, inventory emissions, install emissions controls, acquire allowances or
pay taxes and fees relating to emissions, which could adversely affect Trust distributions. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse
gases may produce changes in climate or weather, such as increased frequency and severity of storms, floods, drought and other climatic events, which if any such effects were to occur, could have
adverse physical effects on the Working Interest Owners' operations or physical assets.
Please
read "BusinessRegulation and PricesEnvironmental Matters" under Item 1 of this Form 10-K for more information on the environmental laws and
government regulations that may be applicable to the Working Interest Owners' operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in
increased costs and additional operating restrictions or delays on the Royalty properties in which the Trust holds an interest.
Hydraulic fracturing is an important and commonly used process in the completion of unconventional natural gas wells in shale and coal
formations, as well as tight conventional formations including many of those Royalty properties in which the Trust holds an interest. This process involves the injection of water, sand and chemicals
under pressure into rock formations to stimulate natural gas production. Some states have adopted and others are considering legislation to restrict hydraulic fracturing. Several states including
those where Royalty properties are located have adopted legislation requiring the public disclosure of hydraulic fracturing chemicals, which could make it easier for third parties opposing the
hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, hydraulic
fracturing requires large amounts of water. This water, along with any produced water, is often sent to injection wells for disposal. This activity has been associated with earthquakes and some
states, particularly Oklahoma, have limited injection well activity. Any additional level of regulation could lead to operational delays or increased operating costs and could result in additional
regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of
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compliance
and doing business and required disclosure without protection for trade secret or proprietary products could discourage service companies from using such products and as a result impact the
degree to which some oil and gas wells may be efficiently and economically completed or brought into production.
Trust unitholders and the Trustee have no control over the operation or development of the Royalty Properties
and have little influence over operation or development.
Neither the Trustee nor the unitholders can influence or control the operation or future development of the underlying properties. The Royalty
Properties are owned by the Working Interest Owners, who are independent from the Trust. The Working Interest Owners manage the underlying properties and handle receipt and payment of funds relating
to the Royalty Properties and payments to the Trust for the Royalty. The failure of an operator to conduct its operations, discharge its obligations, deal with regulatory agencies or comply with laws,
rules and regulations, including environmental laws and regulations, in a proper manner could have an adverse effect on the net proceeds payable to the Trust.
The
Working Interest Owners are under no obligation to continue operating the properties. Neither the Trustee nor the unitholders have the right to replace an operator.
The Trustee relies upon the working interests owners for information regarding the Royalty Properties.
The Trustee relies on the Working Interest Owners for information regarding the Royalty Properties. The Working Interest Owners control
(i) historical operating data and estimates, including production volumes, marketing of products, operating and capital expenditures, environmental and other liabilities, effects of regulatory
changes and the number of producing wells and acreage, (ii) plans for future operating and capital expenditures, (iii) geological data relating to reserves, as well as related
projections regarding production, operating expenses and capital expenses used in connection with the preparation of the reserve report, (iv) forward-looking information and estimates relating
to production and drilling plans and (v) information regarding the Royalty Properties responsive to litigation claims. While the Trustee requests material information for use in periodic
reports as part of its disclosure controls and procedures, the Trustee does not control this information and relies entirely on the Working Interest Owners to provide accurate and timely information
when requested for use in the Trust's periodic reports. Information regarding operations has been subject to errors and adjustments in the past. Accordingly, the Trustee cannot assure unitholders that
other errors or adjustments by the Working Interest Owners, whether historical or future, will not affect Royalty income and distributions by the Trust.
Under
the terms of the Trust Indenture, the Trustee is entitled to rely, and in fact relies, on certain experts in good faith. This reliance includes the use of an independent petroleum
engineering consultant to prepare estimates of net proved reserves attributable to the Trust. This independent petroleum engineering consultant in turn relies on information provided to it by the
Working Interest Owners. While the Trustee has no reason to believe its reliance on experts is unreasonable, this reliance on experts and limited access to information may be viewed as a weakness as
compared to the management and oversight of entity forms other than trusts.
The owner of any Royalty Property may abandon any property, terminating the related Royalty.
The Working Interest Owners may at any time transfer all or part of the Royalty Property to another unrelated third party. Unitholders are not
entitled to vote on any transfer, and the Trust will not receive any proceeds of any such transfer. Following any transfer, the Royalty Properties will continue to be subject to the Royalty, but the
net proceeds from the transferred property would be calculated separately and paid by the transferee. The transferee would be responsible for all of the
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obligations
relating to calculating, reporting and paying to the Trust the Royalty on the transferred portion of the Royalty Properties, and the current owner of the Royalty Properties would have no
continuing obligation to the Trust for those properties.
The
Working Interest Owners or any transferee may abandon any well or property if it reasonably believes that the well or property can no longer produce in commercially economic
quantities. This could result in termination of the Royalty relating to the abandoned well.
The Royalty can be sold and the Trust can be terminated.
The Trust will be terminated and the Trustee must sell the Royalty if holders of a majority of the units of beneficial interest of the Trust
approve the sale or vote to terminate the Trust, or if the Trust's royalty income for each of two successive years is less than $250,000 per year. Following any such termination and liquidation, the
net proceeds of any sale will be distributed to the unitholders and unitholders will receive no further distributions from the Trust. We cannot assure you that any such sale will be on terms
acceptable to all unitholders.
Trust assets are depleting assets and, if the Working Interest Owners or other operators of the Royalty
Properties do not perform additional development projects, the assets may deplete faster than expected.
The net proceeds payable to the Trust are derived from the sale of depleting assets. Accordingly, the portion of the distributions to
unitholders attributable to depletion may be considered a return of capital. The reduction in proved reserve quantities is a common measure of depletion. Future maintenance and development projects on
the Royalty Properties will affect the quantity of proved reserves. The timing and size of these projects will depend on the market prices of natural gas. If operators of the Royalty 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. For federal income tax
purposes, depletion is reflected as a deduction. Please see the section entitled "BusinessDescription of the UnitsFederal Income Tax Matters" under Item 1 of this
Form 10-K.
Because
the net proceeds payable to the Trust are derived from the sale of depleting assets, the portion of distributions to unitholders attributable to depletion may be considered a
return of 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 Trust unitholders, which could reduce the market
value of the Trust units over time. Eventually, properties underlying the Trust's Royalty will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any
distributions of net proceeds therefrom.
Unitholders have limited voting rights.
Voting rights as a unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for
annual meetings of unitholders or for an annual or other periodic re-election of the Trustee. Additionally, Trust unitholders have no voting rights in any of the Working Interest Owners. Unlike
corporations which are generally governed by boards of directors elected by their equity holders, the Trust is administered by a corporate Trustee in accordance with the Trust Indenture and other
organizational documents. The Trustee has extremely limited discretion in its administration of the Trust.
Unitholders have limited ability to enforce the Trust's rights against the current or future owners of the
Royalty Properties.
The Trust Indenture and related trust law permit the Trustees and the Trust to sue the Working Interest Owners to compel them to fulfill the
terms of the Conveyance of the Royalty. If the Trustee
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does
not take appropriate action to enforce provisions of the Conveyance, the recourse of a unitholder would likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take
specified actions. Unitholders probably would not be able to sue the Working Interest Owners directly.
The limited liability of the 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 a limited partnership which would provide further
limited liability protection to Trust unitholders. While the Trustee is liable for any excess liabilities incurred if the Trustee fails to insure that such liabilities are to be satisfied only out of
Trust assets, under the laws of Texas, which are unsettled on this point, a holder of units 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 future financial condition of Working Interest Owners or other operators of the underlying properties
could impede the operation of wells.
The value of the Royalty and the Trust's ultimate cash available for distribution is highly dependent on the financial condition of the
operators of the wells. The ability to operate the underlying properties depends on all operators' current and future financial condition and economic performance and access to capital, which in turn
will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of such operators.
In
the event of the bankruptcy of any operator of the underlying properties, the Working Interest Owners in the affected properties, creditors or the debtor-in-possession may have to
seek a new party to perform the operations of the affected wells. The creditors or debtor-in-possession may not be able to find a replacement operator, and they may not be able to enter into a new
agreement with such replacement party on favorable terms or within a reasonable period of time.
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 ("
U.S. GAAP
"). Although this basis of accounting is permitted for royalty trusts by the SEC,
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.
Due to the transition from ConocoPhillips and XTO to Hilcorp, Hilcorp has estimated the revenue component of
Net Proceeds, which may adversely affect future distributions to unitholders.
The sale of San Juan Basin assets, including the San Juan BasinNew Mexico Properties, by ConocoPhillips to Hilcorp closed on
July 31, 2017, and by XTO to Hilcorp closed on March 29, 2018. Thereafter, Hilcorp assumed responsibility for monthly production from the San Juan BasinNew Mexico
Properties.
Hilcorp
has informed the Trust that, due to the transition from ConocoPhillips and XTO, Hilcorp did not have all of the revenue decks installed and did not have the appropriate detail to
provide actual revenue figures for the San Juan BasinNew Mexico Properties. Therefore, since October 2017, Hilcorp has paid the Trust estimated amounts as the Net Proceeds from the San
Juan BasinNew
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Mexico
Properties based on the July 2017 production month previously provided and paid by ConocoPhillips. Additionally, since July 2018, Hilcorp has paid to the Trust estimated amounts as the Net
Proceeds from the San Juan BasinNew Mexico Properties based on the March 2018 accounting month previously provided and paid by XTO. Hilcorp has not indicated whether it will change any
estimates for subsequent payments of Net Proceeds to the Trust in 2019.
As
a result of the payment of estimated Net Proceeds, Hilcorp has informed the Trust that in the future, it will reconcile estimated versus actual revenue figures once it finalizes
installation of its revenue decks, although Hilcorp has not indicated when such reconciliation may occur. At the time that Hilcorp reconciles estimated versus actual revenue numbers, such estimations
and reconciliations by Hilcorp will be added to or subtracted from future Net Proceeds paid to the Trust. Pursuant to the Trust Indenture, the Trust is not required to pay to Hilcorp any amounts that
could be owed if the estimated revenue exceeded actual revenue figures in past period. However, Hilcorp may recover such amounts by withholding a portion or all of Net Proceeds that would otherwise be
payable to the Trust. Accordingly, to the extent that Hilcorp determines that estimated revenue exceeded actual revenue figures in past periods such that Hilcorp overpaid Net Proceeds to the Trust,
Hilcorp may reduce future payments of Royalty income to the Trust by the amount of the overestimation, plus any additional required costs. If this is the case, the Trust may not receive a portion or
all of the Net Proceeds from the San Juan BasinNew Mexico Properties that would otherwise be paid to the Trust
until the future Net Proceeds from such properties exceed the amount of the overestimation, plus any additional required costs. This decrease in Net Proceeds paid to the Trust could result in a
material future reduction in distributions to the Trust's unitholders. Net Proceeds from the San Juan BasinNew Mexico Properties for the years ended December 31, 2018 and 2017 were
$1,165,797 and $1,085,082, respectively, which revenue accounted for approximately 50% and 36%, respectively, of the total Royalty income realized by the Trust.