STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
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December 31,
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2019
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2018
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ASSETS
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Cash and short-term investments
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$
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1,233,060
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$
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1,604,884
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Net overriding royalty interests in oil and gas properties
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42,498,034
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42,498,034
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Accumulated amortization
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(40,890,724
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)
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(40,744,388
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)
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Total assets
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$
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2,840,370
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$
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3,358,530
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LIABILITIES AND TRUST CORPUS
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Distributions payable
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$
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255,848
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$
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566,518
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Trust corpus (1,863,590 units of beneficial interest, issued and outstanding)
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2,584,522
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2,792,012
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Total liabilities and trust corpus
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$
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2,840,370
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$
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3,358,530
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(The accompanying notes are an integral part of these financial statements.)
39
Table of Contents
STATEMENTS OF CHANGES IN TRUST CORPUS
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Years Ended December 31,
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2019
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2018
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Trust corpus, beginning of year
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$
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2,792,012
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$
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3,097,932
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Distributable income
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1,635,046
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2,138,132
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Distributions to unitholders
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(1,696,197
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)
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(2,219,438
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)
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Amortization of net overriding royalty interests
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(146,339
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)
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(224,614
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)
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Trust corpus, end of year
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$
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2,584,522
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$
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2,792,012
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(The accompanying notes are an integral part of these financial statements.)
40
Table of Contents
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
Note 1Trust Organization and Provisions
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 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:
-
-
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 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.,
its wholly owned subsidiary. 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
41
Table of Contents
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1Trust Organization and Provisions (Continued)
are
described below, Linn Energy, Inc. (together with its subsidiaries, "Linn") 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 operated the Hugoton Royalty Properties. On November 22, 2019, Riviera completed the sale of its interest in its remaining
properties located in the Hugoton Basin under the Purchase and Sale Agreement, dated August 28, 2019 (the "Purchase Agreement"), by and between the Riviera Upstream, LLC, Riviera
Operating, LLC and Scout Energy Group V, LP ("Scout"). Pursuant to the Purchase Agreement, Riviera divested all of its interest in its oil and gas assets and contracts in the Hugoton
Royalty Properties. Since November 23, 2019, Scout 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"). 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 Juan BasinNew Mexico Properties, there was a transition period to transfer historical
information, knowledge and processes from one owner to the other. During this transition period, Hilcorp recorded estimates of revenues and expenses and made payments to the Trust based on historical
amounts previously paid by ConocoPhillips, and the Trust recognized such amounts in accordance with its modified cash basis of accounting. Accordingly, Hilcorp made an estimated monthly payment of
$97,150 in Net Proceeds to the Trust from September 2017 to March 2019 based upon the July 2017 production month previously paid by ConocoPhillips. In April 2019, Hilcorp began to generate actual
(instead of estimated) Net Proceeds due to the Trust on a monthly basis. Hilcorp has informed the Trust that it will utilize actual revenue and expense amounts and either add or subtract reconciled
historical amounts on a month by month basis, which will be recognized over time by the Trust in accordance with the Trust's modified cash basis of accounting. In December 2019, Hilcorp made the first
payment to the Trust reconciling historical amounts, which was in the amount of $29,698 for the accounting month of September 2017 and was the only reconciliation payment made by Hilcorp during 2019.
Until all estimated historical
42
Table of Contents
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1Trust Organization and Provisions (Continued)
monthly
amounts received by the Trust from September 2017 to March 2019 are fully reconciled and adjusted, Net Proceeds from the San JuanNew Mexico Properties will reflect adjustments to
actual current production and costs to account for historical monthly reconciliations as they are completed. Because of anticipated future adjustments, the amounts of Net Proceeds reported for the San
Juan BasinNew Mexico Properties during the year ended December 31, 2019 may not be representative of Net Proceeds that will be received in future years.
Hilcorp
has informed the Trust that significant incremental costs of approximately $1.1 million attributable to the Trust were incurred in 2018 with respect to a newly drilled
well in the San Juan BasinNew Mexico Properties. Incremental costs attributable to the Trust will reduce the Trust's future Net Proceeds over a period of time as adjustments are made by
Hilcorp after taking into account actual revenues as well as costs for these properties during the applicable time period. The potential impact to Net Proceeds depends upon the results of all of the
reconciliation work currently being conducted by Hilcorp and is therefore uncertain. The Trust will undertake a review of the reconciliation calculations by Hilcorp and the amount of Net Proceeds
calculated and paid and intends to engage third party consultants when appropriate to assist in the Trust's review.
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 amounts or estimated expenses
were less than actual expense amounts in past periods. However, Hilcorp may recover such amounts by withholding a portion or all of the 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 future material reductions in distributions to the Trust's unitholders.
Net
Proceeds from the San Juan BasinNew Mexico Properties for years ended December 31, 2019 and 2018 were $871,096 and $1,165,797, respectively, which revenue
accounted for approximately 49% and 50%, respectively, of the total Royalty income reported by the Trust during those periods.
As
used in this report, Scout 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 refer to the current co-operators of certain tracts of land included in the San Juan BasinColorado Properties, unless otherwise indicated. Scout, 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 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. In addition, the Trust does not undertake or control any capital projects or make capital
expenditures related to any of the Royalty Properties.
Trustee and Terms of Trust Indenture. Effective October 2, 2006, the Trustee succeeded JP Morgan Chase Bank, N.A. as Trustee of the
Trust.
JPMorgan Chase Bank, N.A. is the successor by mergers to the originally named Trustee, Texas Commerce Bank National Association. The Trust is a passive entity
43
Table of Contents
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1Trust Organization and Provisions (Continued)
whose
purposes are limited to: (1) converting the Royalties to cash, either by retaining them and collecting the proceeds of production (until production has ceased or the Royalties are
otherwise terminated) or by selling or otherwise disposing of the Royalties; 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 Royalties 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;
(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) Scout,
Hilcorp and BP will reimburse the Trust for 59.34%, 27.45% and 1.77%, respectively, for general and administrative expenses of the Trust.
Trustee's Fees. Pursuant to the Trust Indenture, the Trust pays the Trustee fees for its services each quarter and the Working Interest
Owners
partially reimburse the Trust for the fees paid in connection with the Trustee's services. The net amount of these reimbursements is included in the general and administrative expenses of the Trust.
For the year ended December 31, 2019, the Trustee was due $475,000 for its services. The Trust paid $433,153 of this amount to the Trustee, and $41,847 was allocated to offset against interest
due to the Trust under the Trust Indenture. The Trust Indenture requires that cash being held by the Trustee earn interest at 1.5% below the prime rate, which would have yielded the Trust a 4.00%
annualized return from January 1, 2019 through July 31, 2019, a 3.75% annualized return from August 1, 2019 to September 18, 2019, a 3.50% annualized return from
September 19, 2019 through October 30, 2019, a 3.25% annualized return from October 31, 2019 through December 31, 2019. However, due to the current interest rate
environment, the Trustee was unable to obtain an account in which such an interest rate was available. In the event such an interest rate is unavailable in the future, the Trustee intends to allocate
certain of its fees due to the Trust to meet the minimum interest rate payable under the Trust Indenture.
The
Working Interest Owners partially reimburse the Trust each quarter for amounts paid in connection with the Trustee's services. For the year ended December 31, 2019, the
Trustee's fees were $433,153 and the Working Interest Owners reimbursed a sum of $383,588 to the Trustee, which was the same amount reimbursed for the year ended December 31, 2018.
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
44
Table of Contents
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1Trust Organization and Provisions (Continued)
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.
Note 2Basis of Presentation
The accompanying audited financial information has been prepared by the Trustee in accordance with the instructions to Form 10-K. The preparation of the financial statements
requires estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts
of income and expenses during the reporting period. Actual results could differ from those estimates. The Trustee believes such information includes all the disclosures necessary to make the
information presented not misleading. The information furnished reflects all adjustments which are, in the opinion of the Trustee, necessary for a fair presentation of the results for the years
presented. The Trust considers all highly liquid investments with a maturity of three months or less to be cash equivalents. Subsequent events were evaluated through the issuance date of the financial
statements.
In
accordance with the Conveyance, the Working Interest Owners are obligated to calculate and pay the Trust each month an amount equal to 90% of the Net Proceeds attributable to the
month.
45
Table of Contents
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 2Basis of Presentation (Continued)
The
net overriding royalty interest is reviewed for impairment whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. If circumstances
require the net overriding royalty interest to be tested for possible impairment, the Trust first compares undiscounted cash flows expected to be generated by the net overriding royalty interest to
its carrying value. If the carrying value of the net overriding royalty interest is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying
value exceeds its fair value. The fair value of the net overriding royalty interest is measured using valuation techniques consistent with the income approach, converting future cash flows to a single
discounted amount.
The
financial statements of the Trust are prepared on the following basis:
(a) Royalty
income recorded for a month is the amount computed and paid by the Working Interest Owners to the Trustee for such month rather than either the value of a
portion of the oil and gas produced by the Working Interest Owners for such month or the amount subsequently determined to be the Trust's proportionate share of the net proceeds for such month;
(b) Interest
income, interest receivable and distributions payable to unitholders include interest to be earned on short-term investments from the financial statement date
through the next date of distribution;
(c) Trust
general and administrative expenses, net of reimbursements, are recorded in the month they are included in the calculation of the monthly distribution amount;
(d) Amortization
of the Royalty is computed on a unit-of-production basis and is charged directly to trust corpus because such amount does not affect distributable income;
and
(e) Distributions
payable are determined on a monthly basis and are payable to unitholders of record as of the last business day of each month or such later date as the
Trustee determines is required to comply with applicable law or stock exchange requirements. However, cash distributions are made quarterly in January, April, July and October, and include interest
earned from the monthly record dates to the date of distribution.
This
basis for reporting distributable income is considered to be the most meaningful because distributions to the unitholders for a month are based on net cash receipts for such month.
However, these statements differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America because, under such principles, royalty
income for a month would be based on Net Proceeds from production for such month without regard to when calculated or received, general and administrative expenses would be recorded in the month they
accrue, and interest income for a month would be calculated only through the end of such month.
Note 3Legal Proceedings
There are no pending legal proceedings to which the Trust is a named party. The Trustee has been advised by the Working Interest Owners that it may be subject to litigation in the
ordinary course of business for certain matters that include the Royalty Properties. While each of the Working Interest Owners has advised the Trustee that it does not currently believe any of the
pending litigation will have a material adverse effect net to the Trust, in the event such matters were adjudicated or settled in a material amount and charges are made against Royalty income, such
charges could have a material impact on future Royalty income.
46
Table of Contents
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 4Income Tax Matters
In a technical advice memorandum dated February 26, 1982, 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 the unitholder's pro rata share
of the income and expense of the Trust as if the 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.
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.
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. 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 U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT.
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.
Note 5Excess Production Costs
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As of December 31, 2019
|
|
As of December 31, 2018
|
|
San Juan BasinColorado PropertiesRed Willow
|
|
$
|
29,597
|
|
$
|
2,957
|
|
San Juan BasinNew Mexico PropertiesHilcorp
|
|
|
5,321
|
|
|
4,948
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
34,918
|
|
$
|
7,905
|
|
|
|
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Excess
production costs result when costs, charges, and expenses attributable to a working interest property exceed the revenue received from the sale of oil, gas, and other hydrocarbons
produced from such property. The excess production costs must be recovered by the Working Interest Owners before any distribution of Royalty income from the Royalty Properties which are operated by
such Working Interest Owners will be made to the Trust.
47
Table of Contents
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 6Distributable Income Per Unit
During 2011, the Trustee, acting pursuant to the Trust Indenture, withheld $1.0 million for future unknown contingent liabilities and expenses (such cumulative withholding being
the "Contingent Reserve"). The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any reimbursement expenses. At any given time, the
Contingent Reserve is included in cash and short-term investments.
For
the year ended December 31, 2019, the Trustee increased the Contingent Reserve by (1) $56,793 of Royalty income received from BP in March 2019 after the distribution to
unitholders had been announced for the month of March 2019, which Royalty income was included in the April 2018 distribution to unitholders, (2) $434 for a duplicated general and administrative
expense paid in error by the Trust in February 2019 and not refunded to the Trust until April 2019, (3) $317 underpaid by Riviera in June 2019 due to a 2018 Ad Valorem tax under accrual but
included in the June 2019 distribution to unitholders, which amount was then excluded from the July 2019 distribution to unitholders, (4) $812 due to a refund received from a vendor in
September 2019 and (5) $843 due to an overpayment received in error from BP in December 2019 that was deducted from BP's January 2020 payment to the Trust.
For
the year ended December 31, 2019, the Trustee decreased the Contingent Reserve by (1) $434 for a duplicated general and administrative expense paid in error by the
Trust in February 2019 and not refunded to the Trust until April 2019, (2) $38,364 for a cash refund of a duplicate payment from a vendor received in November 2018 and distributed to
unitholders in February 2019, (3) $56,794 of Royalty income received from BP in March 2019 after the distribution to unitholders had been announced for the month of March 2019, which Royalty
income was included in the April 2019 distribution to unitholders, (4) $317 underpaid by Riviera in June 2019 due to a 2018 Ad Valorem tax under accrual but included in the June 2019
distribution to unitholders, which amount was then excluded from the July 2019 distribution to unitholders, (5) $812 due to a refund received from a vendor in September 2019 which refund was
included in the distribution to unitholders in November 2019 and (6) $23,629 for a reimbursement not received from Scout but included in the December 2019 distribution to unitholders. The net
effects of the foregoing adjustments for the year ended December 31, 2019 resulted in the balance of the Contingent Reserve being equal to $977,212 as of December 31, 2019.
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 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.
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
48
Table of Contents
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 6Distributable Income Per Unit (Continued)
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 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.
The
effect on distributable income per unit of adjustments to the Contingent Reserve for the years ended December 31 are as follows:
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
Distributable Income
|
|
$
|
1,635,046
|
|
$
|
2,138,132
|
|
Increase in the Contingent Reserve
|
|
|
(59,199
|
)
|
|
(115,217
|
)
|
Withdrawal from the Contingent Reserve
|
|
|
120,350
|
|
|
196,523
|
|
|
|
|
|
|
|
|
|
Distributable Income Available for Distribution
|
|
$
|
1,696,197
|
|
$
|
2,219,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Income Available for Distribution per unit
|
|
$
|
0.910
|
|
$
|
1.191
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units outstanding
|
|
|
1,863,590
|
|
|
1,863,590
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 7Supplemental Reserve Information (Unaudited)
Estimates of the proved oil and gas reserves attributable to the Hugoton and San Juan Basin Royalty Properties as of December 31, 2019 are based on the reserve report prepared by
Miller and Lents, independent petroleum engineering consultants. Prior to Miller and Lents, the Trust used DeGolyer and MacNaughton as its independent pertroleum engineering consultants. The estimates
were prepared in accordance with guidelines established by the SEC. Accordingly, the estimates were based on existing economic and operating conditions. The reserve volumes and revenue values for the
Trust's Royalty were estimated by allocating to the Trust a portion of the estimated combined net reserve volumes of the Hugoton Royalty Properties and San Juan Basin Royalty Properties based on
future net revenue. Production volumes are allocated based solely on royalty income. Because the net reserve volumes attributable to the Trust's Royalty are estimated using an allocation of reserve
volumes based on estimates of future net revenue, a change in prices or costs will result in changes in the estimated net reserve volumes. Therefore, the estimated net reserve volumes attributable to
the Trust's Royalty will vary if different future price and cost assumptions are used. Only costs necessary to develop and produce existing proved reserve volumes were assumed in the allocation of
reserve volumes to the Royalty.
In
accordance with revised SEC regulations, reserves for natural gas and oil, condensate and natural gas liquids at December 31, 2019 were based on the average price during the
12-month period,
49
Table of Contents
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 7Supplemental Reserve Information (Unaudited) (Continued)
determined
as an unweighted average of the first-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Operating
costs, production and ad valorem taxes and future development and abandonment costs were based on current costs as of each year end, with no escalation.
There
are numerous uncertainties inherent in estimating the quantities and value of proved reserves and in projecting the future rates of production and timing of expenditures. The
reserve data below represent estimates only and should not be construed as being exact. Moreover, the discounted values should not be construed as representative of the current market value of the
Royalty. A market value determination would include many additional factors including: (i) anticipated future oil and gas prices; (ii) the effect of federal income taxes, if any, on
future Royalty income; (iii) an allowance for return on investment; (iv) the effect of governmental legislation; (v) the value of additional reserves, not considered proved at
present, which may be recovered as a result of further exploration and development activities; and (vi) other business risks.
Estimates
of reserve volumes attributable to the Royalty are shown in order to comply with requirements of the SEC. There is no precise method of allocating estimates of physical
quantities of reserve volumes between the Working Interest Owners and the Trust, since the Royalty is not a working interest and the Trust does not own and is not entitled to receive any specific
volume of reserves from the Royalty. The quantities of reserves attributable to the Trust have been and will be affected by changes in various economic factors utilized in estimating net revenues from
the Royalty Properties. Therefore, the estimates of reserve volumes set forth below are to a large extent hypothetical and differ in significant respects from estimates of reserves attributable to a
working interest.
The
following schedules set forth (i) the estimated net quantities of proved, proved developed, and proved undeveloped oil, condensate and natural gas liquids and natural gas
reserves attributable to the Royalty, and (ii) the standardized measure of the discounted future Royalty income and the nature of changes in such standardized measure between years. These
schedules are prepared on the accrual basis, which is the basis on which the Working Interest Owners maintain their production records and is different from the basis on which the Royalty is computed.
50
Table of Contents
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 7Supplemental Reserve Information (Unaudited) (Continued)
ESTIMATED QUANTITIES OF PROVED, PROVED DEVELOPED,
AND PROVED UNDEVELOPED RESERVES
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
Condensate
|
|
Natural
Gas
Liquids
|
|
Natural
Gas
|
|
|
|
(Bbls)
|
|
(Bbls)
|
|
(Mcf)
|
|
Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
6,295
|
|
|
287,019
|
|
|
5,249,794
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions to previous estimates
|
|
|
(228
|
)
|
|
(29,399
|
)
|
|
(566,548
|
)
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(829
|
)
|
|
(24,750
|
)
|
|
(599,447
|
)
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
5,238
|
|
|
232,870
|
|
|
4,083,799
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions to previous estimates
|
|
|
3,713
|
|
|
161,831
|
|
|
3,214,039
|
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(774
|
)
|
|
(34,692
|
)
|
|
(987,502
|
)
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
|
8,177
|
|
|
360,009
|
|
|
6,310,336
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions to previous estimates
|
|
|
2,219
|
|
|
103,606
|
|
|
1,834,431
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(399
|
)
|
|
(30,568
|
)
|
|
(852,872
|
)
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
9,997
|
|
|
433,047
|
|
|
7,291,895
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions to previous estimates
|
|
|
3,358
|
|
|
(1,488
|
)
|
|
1,826,202
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(2,355
|
)
|
|
(51,559
|
)
|
|
(1,412,097
|
)
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
|
11,000
|
|
|
380,000
|
|
|
7,706,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
6,295
|
|
|
287,019
|
|
|
5,249,794
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
5,238
|
|
|
232,870
|
|
|
4,083,799
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
|
8,177
|
|
|
360,009
|
|
|
6,310,336
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
9,997
|
|
|
433,047
|
|
|
7,291,895
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
|
11,000
|
|
|
380,000
|
|
|
7,706,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
-
The Hugoton Royalty represents 1%, 8% and 20% of the estimated proved natural gas liquids reserves and
1%, 9% and 21% of the estimated proved natural gas reserves as of December 31, 2019, 2018 and 2017, respectively.
51
Table of Contents
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 7Supplemental Reserve Information (Unaudited) (Continued)
-
-
The December 31, 2019, 2018, 2017, 2016 and 2015 reserve estimates for the Hugoton Royalty
Properties were prepared by a third-party reservoir engineering firm.
STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM PROVED
OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM
(Unaudited Estimates)
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
|
|
(In thousands)
|
|
The Trust's proportionate share of future Gross Proceeds
|
|
$
|
35,252
|
|
$
|
41,480
|
|
$
|
49,439
|
|
The Trust's proportionate share of future operating costs
|
|
|
(12,649
|
)
|
|
(20,596
|
)
|
|
(25,507
|
)
|
Future capital costs
|
|
|
(1,214
|
)
|
|
(1
|
)
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Future Royalty income
|
|
$
|
21,389
|
|
$
|
20,883
|
|
$
|
23,931
|
|
Discount at 10% per annum
|
|
|
(10,896
|
)
|
|
(10,243
|
)
|
|
(10,585
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of future Royalty income from proved oil and gas reserves
|
|
$
|
10,493
|
|
$
|
10,640
|
|
$
|
13,346
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHANGES IN THE STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM
PROVED OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM
(Unaudited Estimates)
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
|
|
(In thousands)
|
|
Standardized measure of future Royalty income from proved oil and gas reserves at beginning of year
|
|
$
|
10,640
|
|
$
|
13,346
|
|
$
|
7,057
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
(3,273
|
)
|
|
757
|
|
|
549
|
|
Net changes in price and production costs
|
|
|
4,072
|
|
|
(2,209
|
)
|
|
7,115
|
|
Royalty income
|
|
|
(1,808
|
)
|
|
(2,332
|
)
|
|
(3,029
|
)
|
Accretion of discount
|
|
|
862
|
|
|
1,078
|
|
|
1,654
|
|
|
|
|
|
|
|
|
|
|
|
|
Net changes in standardized measure
|
|
$
|
(147
|
)
|
$
|
(2,706
|
)
|
$
|
6,289
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of future Royalty income from proved oil and gas reserves at end of year
|
|
$
|
10,493
|
|
$
|
10,640
|
|
$
|
13,346
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
-
The Hugoton Royalty represents approximately 3% and 21% of the standardized measure of future royalty income for 2019 and 2018, respectively.
-
-
Standardized measure at December 31, 2019 was calculated using natural gas prices of $2.68 per thousands of cubic feet (Mcf) for Hugoton
Royalty Properties, $2.35 per Mcf for San Juan BasinNew Mexico Royalty Properties and $1.52 per Mcf for the San Juan Basin-Colorado Royalty Properties, natural gas liquids prices of
$12.71 per barrel ("Bbl") for Hugoton Royalty Properties and $13.10 per Bbl for the San Juan Basin Royalty Properties, and oil and condensate prices of $41.57 per Bbl for the San Juan Basin Royalty
Properties.
52
Table of Contents
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 8Selected Quarterly Financial Data (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summarized Results for the Quarters Ended
|
|
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty income
|
|
$
|
726,869
|
|
$
|
588,481
|
|
$
|
203,160
|
|
$
|
289,868
|
|
Distributable income
|
|
$
|
687,295
|
|
$
|
547,327
|
|
$
|
168,176
|
|
$
|
232,248
|
|
Distributable income per unit
|
|
$
|
0.3688
|
|
$
|
0.2937
|
|
$
|
0.0902
|
|
$
|
0.1247
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty income
|
|
$
|
747,618
|
|
$
|
530,259
|
|
$
|
449,556
|
|
$
|
604,886
|
|
Distributable income
|
|
$
|
635,418
|
|
$
|
484,006
|
|
$
|
410,827
|
|
$
|
607,881
|
|
Distributable income per unit
|
|
$
|
0.3410
|
|
$
|
0.2597
|
|
$
|
0.2204
|
|
$
|
0.3262
|
|
53
Table of Contents