Three Months Ended June 30, 2017 and 2016
Financial Review
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Three Months Ended
June 30,
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2017
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2016
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Royalty income
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717,229
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$
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182,988
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Interest income
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2,289
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450
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General and administrative expense
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(49,822
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(38,303
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Distributable income
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$
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669,696
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$
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145,135
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Distributable income per unit
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$
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0.3594
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$
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0.0779
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Units outstanding
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1,863,590
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1,863,590
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The
Trust's Royalty income was $717,229 in the second quarter of 2017, an increase of approximately 292% as compared to $182,988 in the second quarter of 2016, primarily as a result of
higher natural gas, natural gas liquids and oil and condensate prices, increased net production of natural gas, natural gas liquids and oil and condensate and a reduction in capital expenditures and
operating expenses in the second quarter of 2017 as compared to the second in quarter of 2016. General and administrative expense was $49,822 in the second quarter of 2017 compared with $38,303 in the
second quarter of 2016, primarily due to increased legal, administrative and audit fees paid in the current period.
The
distributable income available for distribution of the Trust for each period includes the Royalty income received from the Working Interest Owners during such period, plus interest
income earned to the date of distribution (if any) and increases or withdrawals from the reserve for contingent liabilities and expenses (if any). Trust administration expenses are deducted in the
computation of distributable income available for distribution. Distributable income available for distribution for the quarter ended June 30, 2017 was $704,100, representing $0.3778 per unit,
compared to $145,846, representing $0.0783, for the quarter ended June 30, 2016. Based on 1,863,590 units outstanding for the quarters ended June 2017 and 2016, respectively, the per unit
distributions were as follows:
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2017
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2016
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April
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$
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0.1674
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$
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0.0203
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May
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0.1122
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0.0221
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June
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0.0982
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0.0359
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$
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0.3778
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$
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0.0783
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12
As
of June 30, 2017, there were $0 of unreimbursed expenses. 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 currently reserved for such future unknown contingent liabilities and expenses is included in cash and short-term investments. For
the three months ended June 30, 2017, the Trustee increased the reserve for future unknown contingent liabilities and expenses by $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. Such royalty income was included in the July 2017 distribution to unitholders. For the three months ended June 30,
2017, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by $82,244 of royalty income received from BP, such that as of June 30, 2017, the reserve for
unknown contingent liabilities and expenses was $1,047,840 and is included in cash and short-term investments. The Trustee reserves the right to determine whether or not to release cash reserves in
future periods with respect to any unreimbursed expenses.
The
Trustee was due $118,750 for its services for the quarter ended June 30, 2017. The Trust paid $108,288 of this amount to the Trustee, and $10,462 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 2.50% return from March 16, 2017 through June 14, 2017 and a 2.75% return from June 15, 2017 through June 30, 2017. 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 Trustee will continue to allocate a portion of the fees earned for its services to the
Trust until the remaining $23,037 of interest due to the Trust is fully offset, and it may do so in future periods in which unpaid interest is due to the Trust. The Working Interest Owners partially
reimburse the Trust each quarter for amounts paid in connection with the Trustee's services. For the quarter ended June 30, 2017, such reimbursements totaled $95,897. For the quarter ended
June 30, 2016, trustee fees were $108,288. Reimbursements received for the quarter ended June 30, 2016 were $95,897.
Operational Review
Hugoton Field
Natural gas and natural gas liquids production attributable to the Royalty from the Hugoton field accounted for approximately 49% of the Royalty
income of the Trust during the second quarter of 2017.
Linn
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. During the second quarter of 2017, the primary purchasers were Kansas Gas Service, Continuum Energy Service, LLC and Enterprise Products
Operating, LLC. Linn has advised the Trust that it expects to continue to market gas production from the Hugoton field under short-term and multi-month contracts. Overall market prices received
for natural gas from Hugoton Royalty Properties were higher for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016.
13
Royalty
income attributable to the Hugoton Royalty Properties increased to $349,915 in the second quarter of 2017 from $65,948 in the second quarter of 2016 primarily due to increases in
natural gas and natural gas liquids prices, increased net natural gas and natural gas liquids production volumes and a decrease in capital expenditures and operating costs from the Hugoton Royalty
Properties in the second quarter of 2017 compared to the second quarter of 2016. The average price received in the second quarter of 2017 for natural gas and natural gas liquids sold from the Hugoton
Royalty Properties was $3.93 per Mcf and $24.60 per barrel, respectively, as compared to 2.60 per Mcf and
$9.83 per barrel, respectively, in the second quarter of 2016. Net production of natural gas attributable to the Hugoton Royalty Properties increased to 65,357 Mcf in the second quarter of 2017 from
19,291 Mcf in the second quarter of 2016. Net production of natural gas liquids attributable to the Hugoton Royalty Properties increased to 3,787 barrels in the second quarter of 2017 from 1,606
barrels in the second quarter of 2016. Actual production volumes from the Hugoton properties increased to 103,985 Mcf of natural gas and decreased to 6,120 barrels of natural gas liquids in the second
quarter of 2017 as compared to 90,178 Mcf of natural gas and to 7,514 barrels of natural gas liquids in the second quarter of 2016.
Capital
expenditures attributable to the Hugoton Royalty Properties were $1,023 in the second quarter of 2017, as compared to $2,539 in the second quarter of 2016. Operating costs were
$207,824 in the second quarter of 2017, a decrease of approximately 13% as compared to $239,298 in the second quarter of 2016 primarily due to ad valorem taxes.
On
May 11, 2016, Linn Energy, LLC ("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 Energy, Inc. (or a subsidiary thereof), and LinnCo, LLC and Linn Energy, LLC were wound down and liquidated. Subsequent to the effectiveness of the Plan, Linn
Energy, Inc. is now 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. 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.
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San Juan Basin
Royalty income from the San Juan Basin Royalty Properties is calculated and paid to the Trust on a state-by-state basis. A majority of the
royalty income from the San Juan Basin Royalty Properties is attributable to the Royalty Properties located in the State of New Mexico.
Royalty
income from the San Juan BasinNew Mexico was $228,136 during the second quarter of 2017 as compared with Royalty income of $86,981 during the second quarter of 2016.
This increase in Royalty income was due primarily to an increase in natural gas, natural gas liquids and oil and condensate prices, increased net production volumes of natural gas, natural gas liquids
and oil and condensate and reduced capital expenditures for the second quarter of 2017 compared to the second quarter of 2016, offset in part by an increase in operating costs during the second
quarter of 2017 compared to the second quarter of 2016. Net production attributable to the San Juan Basin Royalty Properties located in New Mexico was 73,918 Mcf of natural gas, 4,044 barrels of
natural gas liquids and 245 barrels of oil and condensate in the second quarter of 2017, as compared to 43,356 Mcf of natural gas, 2,848 barrels of natural gas liquids and 139 barrels of oil and
condensate in the second quarter of 2016. The average price received in the second quarter of 2017 for natural gas, natural gas liquids and oil and condensate sold from the San Juan Basin Royalty
Properties located in the State of New Mexico was $2.02 per Mcf, $17.31 per barrel and $38.21 per barrel, respectively, compared to $1.19 per Mcf, $11.03 per barrel and $24.29 per barrel during the
same period in 2016. Actual production volumes of natural gas attributable to the San Juan Basin Royalty Properties located in the State of New Mexico decreased to 144,833 Mcf in the second quarter of
2017 from 157,586 Mcf of natural gas for the same period in 2016. Actual production volumes of natural gas liquids attributable to the San Juan Basin Royalty Properties located in the State of New
Mexico decreased to 10,636 barrels in the second quarter of 2017 from 11,907 barrels for the same period in 2016. Actual production volumes of oil and condensate attributable to the San Juan Basin
Royalty Properties located in the State of New Mexico increased to 471 barrels in the second quarter of 2017 from 421 barrels for the same period in 2016.
Capital
expenditures on these properties were $3,210 in the second quarter of 2017, a decrease of approximately 39% as compared to $5,252 in the second quarter of 2016. Operating costs
were $214,518 in the second quarter of 2017, an increase of approximately 8% as compared to $198,586 in
the second quarter of 2016. The Trust's interest in the San Juan Basin was conveyed from PNR's working interest in 31,328 net producing acres in northwestern New Mexico and southwestern Colorado.
Substantially all of the natural gas produced from the San Juan Basin is currently being sold on the spot market.
Royalty
income from the San Juan BasinColorado Royalty Properties was $139,176 during the second quarter of 2017, compared to $30,060 during the second quarter of 2016. This
increase in Royalty income was due primarily to higher prices and net production volumes for natural gas, offset in part by an increase in operating expenses in the second quarter of 2017 compared to
the second quarter of 2016. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 104,754 Mcf of natural gas during the second quarter of 2017 with 28,629 Mcf of
natural gas attributable to the Trust during the second quarter of 2016. The average price received in the second quarter of 2017 for natural gas sold from the San Juan Basin Colorado Properties was
$1.32 per Mcf, as compared to average price of $1.02 per Mcf for the second quarter of 2016. Actual production volumes attributable to the San Juan Basin Colorado Properties increased to 126,751 Mcf
of natural gas in the second quarter of 2017 from 75,401 Mcf of natural gas for the same period in 2016.
15
Operating
costs on these properties were $31,890 in the second quarter of 2017 as compared to $30,505 in the second quarter of 2016.
Six Months Ended June 30, 2017 and 2016
Financial Review
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Six Months Ended June 30,
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2017
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2016
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Royalty income
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$
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1,635,768
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$
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387,633
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Interest income
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3,646
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707
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General and administrative expense
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(98,072
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(86,983
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Distributable income
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$
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1,541,342
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$
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301,357
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Distributable income per unit
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$
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0.8271
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$
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0.1617
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Units outstanding
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1,863,590
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1,863,590
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The
Trust's Royalty income was $1,635,768 for the six months ended June 30, 2017, an increase of approximately 322% as compared to $387,633 for the six months ended
June 30, 2016, primarily as a result of increased natural gas, natural gas liquids and oil and condensate prices and net production volumes, reduced capital expenditures and lower operating
costs in the first six months of 2017 as compared to the first six months of 2016.
The
distributable income available for distribution of the Trust for each period includes the Royalty income received from the Working Interest Owners during such period, plus interest
income earned to the date of distribution (if any) and increases or withdrawals from the reserve for contingent liabilities and expenses (if any). Trust administration expenses are deducted in the
computation of distributable income available for distribution. Distributable income available for distribution for the six months ended June 30, 2017 was $1,493,502, representing $0.8014 per
unit, compared to $295,330, representing $0.1585 per unit, for the six months ended June 30, 2016.
As
of June 30, 2017, there were $0 of unreimbursed expenses. 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 currently reserved for such future unknown contingent liabilities and expenses is included in cash and short-term investments. For
the six months ended June 30, 2017, the Trustee increased the reserve for future unknown contingent liabilities and expenses 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, and (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. For the six months ended June 30, 2017, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by $82,244 of royalty income received from BP, such
that as of June 30, 2017, the reserve for unknown contingent liabilities and expenses was $1,047,840 and is included in cash and short-term investments. The Trustee reserves the right to
determine whether or not to release cash reserves in future periods with respect to any unreimbursed expenses.
16
The
Trustee was due $237,500 for its services for the six months ended June 30, 2017. The Trust paid $216,576 of this amount to the Trustee, and $20,924 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 a 2.25% return from January 1, 2017 through March 15, 2017, a 2.50% return from March 16, 2017 through June 14, 2017 and a 2.75% return from June 15, 2017
through June 30, 2017. 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 Trustee will
continue to allocate a portion of the fees earned for its services to the Trust until the remaining $23,037 of interest due to the Trust is fully offset, and it may do so in future periods in which
unpaid interest is due to the Trust. The Working Interest Owners partially reimburse the Trust each quarter for amounts paid in connection with the Trustee's services. For the six months ended
June 30, 2017, the Trustee's fees were $216,576 and such reimbursements totaled $191,794. For year to date June 30, 2016, the Trustee's fees were $216,576 and such reimbursements totaled
$191,794.
As
of June 30, 2016, there were $812 of unreimbursed expenses. The Trust anticipated receipt of these expense reimbursements by month-end when it published its June distribution
press releases on June 18, 2016, and included these amounts in distributions payable and distributable income per unit as of June 30, 2016. During 2011, the Trustee withheld
$1.0 million for future unknown contingent liabilities and expenses in accordance with the Trust Indenture. For the six months ended June 30, 2016, the Trustee increased the reserve for
future unknown contingent liabilities and expenses by (i) the amounts received during the first quarter of 2016 related to expense reimbursement cash receipts for previous periods totaling
$6,738 and (ii) a prior period expense refund received from a vendor in the amount of $101 during the second quarter of 2016. The Trustee decreased the reserve for future unknown contingent
liabilities and expenses by the amount of expected expense reimbursement cash receipts of $812. As of June 30, 2016, the reserve for unknown contingent liabilities and expenses was $999,289 and
is included in cash and short-term investments. The Trust has subsequently received $812 of the expected expense reimbursement cash receipts as of July 5, 2016, which has increased the reserve
for unknown contingent liabilities and expenses.
Operational Review
Hugoton Field
Natural gas and natural gas liquids revenue from the Hugoton field attributable to the Royalty accounted for approximately 46% of the Royalty
income of the Trust during the six months ended June 30, 2017.
Royalty
income attributable to the Hugoton Royalty Properties increased to $759,585 for the six months ended June 30, 2017 from $145,073 for the same period in 2016 primarily due
to higher prices for natural gas and natural gas liquids, an increase in net natural gas and natural gas liquids production volumes, reduced capital expenditures and decreased operating costs from the
Hugoton Royalty Properties in the first six months of 2017 compared to the first six months of 2016. The average price received in the first six months of 2017 for natural gas and natural gas liquids
sold from the Hugoton field was $3.79 per Mcf and $23.53 per barrel, respectively, compared to $2.77 per Mcf and $9.95 per barrel, respectively, during the same period in 2016. Net production
attributable to the Hugoton Royalty Properties increased to 147,095 Mcf of natural gas and 8,562 barrels of natural gas liquids for
17
the
six months ended June 30, 2017 as compared to 40,616 Mcf of natural gas and 3,273 barrels of natural gas liquids for the six months ended June 30, 2016. Actual production volumes
attributable to the Hugoton Royalty Properties increased to 200,638 Mcf of natural gas and decreased to 11,687 barrels of natural gas liquids in the six months ended June 30, 2017 as compared
to 185,769 Mcf of natural gas and 14,836 barrels of natural gas liquids for the same period in 2016.
Capital
expenditures on these properties were $2,276 during the six months ended June 30, 2017 as compared to $2,630 during the six months ended June 30, 2016. Operating
costs were $273,851 during the six months ended June 30, 2017, a decrease of approximately 47% as compared to $514,386 during the six months ended June 30, 2016. The decrease in
operating costs was due primarily to ad valorem taxes.
San Juan Basin
Royalty income from the San Juan BasinNew Mexico was $532,161 for the first six months of 2017 compared to $212,501 for the first
six months of 2016. The increase in Royalty income was due primarily to higher natural gas, natural gas natural gas liquids and oil and condensate prices, higher net production volumes for natural
gas, natural gas liquids and oil and condensate and reduced capital expenditures, offset in part by an increase in operating costs in the first six months of 2017 from the San Juan Basin properties
compared to the same period in 2016. The average price received in the first six months of 2017 for natural gas, natural gas liquids and oil and condensate sold from the San Juan Basin Royalty
Properties located in the State of New Mexico was $2.31 per Mcf, $16.85 per barrel and $37.87 per barrel, respectively, compared to $1.39 per Mcf, $11.01 per barrel and $25.30 per barrel during the
same period in 2016. Net production attributable to the San Juan Basin Royalty located in New Mexico was 159,173 Mcf of natural gas 8,779 barrels of natural gas liquids and 418 barrels of oil and
condensate for the six months ended June 30, 2017 as compared to 98,766 Mcf of natural gas, 6,057 barrels of natural gas liquids and 283 barrels of oil and condensate for the six months ended
June 30, 2016. Actual production volumes attributable to the San Juan Basin Royalty Properties decreased to 296,766 Mcf of natural gas, 22,236 barrels of natural gas liquids and 777 barrels of
oil and condensate in the six months ended June 30, 2017 as compared to 316,105 Mcf of natural gas, 24,430 barrels of natural gas liquids and 809 barrels of oil and condensate for the same
period in 2016.
San
Juan BasinNew Mexico capital expenditures were $7,415 during the six months ended June 30, 2017, a decrease of approximately 62% as compared to $19,737 during the
six months ended June 30, 2016. Operating costs were $452,407 during the six months ended June 30, 2017, an increase of approximately 6% as compared to $425,285 during the six months
ended June 30, 2016.
Royalty
income from the San Juan BasinColorado Royalty Properties was $344,021 for the six months ended June 30, 2017, compared to $30,060 during the same period in
2016. The increase in Royalty income was primarily the result of higher prices for natural gas, lower operating costs and increased net natural gas production in the six months ended June 30,
2017 compared to the same period in 2016. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 207,242 Mcf of natural gas during the six months ended
June 30, 2017 with 28,432 Mcf of
natural gas attributable to the Trust during the same period in 2016. The average price received for the six months ended June 30, 2017 for natural gas sold from the San Juan Basin Colorado
Properties was $1.66 per Mcf, compared to $1.05 per Mcf received during the same period in 2016. Actual production volumes attributable to the San Juan BasinColorado Royalty Properties
increased to
18
248,616
Mcf of natural gas for the six months ended June 30, 2017 as compared to 186,547 Mcf of natural gas for the same period in 2016.
Operating
costs on these properties were $67,302 for the six months ended June 30, 2017 a decrease of approximately 32% as compared to $98,400 in the same period in 2016 due
primarily to repairs and recompletions in 2016 compared with 2017.