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NDRO > SEC Filings for NDRO > Form 10-Q on 12-Nov-2013All Recent SEC Filings

Show all filings for ENDURO ROYALTY TRUST

Form 10-Q for ENDURO ROYALTY TRUST


12-Nov-2013

Quarterly Report


Item 2. Trustee's Discussion and Analysis of Financial Condition and Results of Operations.

References to the "Trust" in this document refer to Enduro Royalty Trust while references to "Enduro" in this document refer to Enduro Resource Partners LLC.

The following review of the Trust's financial condition and results of operations should be read in conjunction with the financial statements and notes thereto, as well as Management's Discussion and Analysis of Financial Condition and Results of Operations contained in the Trust's 2012 Annual Report on Form 10-K. The Trust's Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all other filings with the SEC are available on the SEC's website at www.sec.gov.

Forward-Looking Statements

This Form 10-Q includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this Form 10-Q, including without limitation the statements under "Trustee's Discussion and Analysis of Financial Condition and Results of Operations" are forward-looking statements. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. No assurance can be given that such expectations will prove to have been correct. When used in this document, the words "believes," "expects," "anticipates," "intends" or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this Form 10-Q, could affect the future results of the energy industry in general, and Enduro and the Trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:

risks associated with the drilling and operation of oil and natural gas wells;

the amount of future direct operating expenses and development expenses;

the effect of existing and future laws and regulatory actions;

the effect of changes in commodity prices or alternative fuel prices;

the impact of hedge contracts;

conditions in the capital markets;

competition in the energy industry;

uncertainty of estimates of oil and natural gas reserves and production; and

cost inflation.

You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this Form 10-Q. The Trust does not undertake any obligation to release publicly any revisions to the forward-looking statements to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events, unless the securities laws require us to do so.

This Form 10-Q describes other important factors that could cause actual results to differ materially from expectations of Enduro and the Trust, including under the caption "Risk Factors." All subsequent written and oral forward-looking statements attributable to Enduro or the Trust or persons acting on behalf of Enduro or the Trust are expressly qualified in their entirety by such factors. The Trust assumes no obligation, and disclaims any duty, to update these forward-looking statements.

Overview

The Trust is a statutory trust created under the Delaware Statutory Trust Act in May 2011. The business and affairs of the Trust are administered by the Trustee. The Trustee has no authority over or responsibility for, and no involvement with, any aspect of the oil and gas operations or other activities on the Underlying Properties. The Delaware Trustee has only minimal rights and duties that are necessary to satisfy the requirements of the Delaware Statutory Trust Act.

In connection with the closing of the Trust's initial public offering, on November 8, 2011, Enduro contributed the Net Profits Interest to the Trust in exchange for 33,000,000 newly issued Trust Units. The Net Profits Interest entitles the Trust to receive 80% of the net profits from the sale and production of oil and natural gas attributable to the Underlying Properties that are produced during the term of the Conveyance, which commenced on July 1, 2011.

The Trust is not subject to any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time. The Trust will dissolve upon the earliest to occur of the following: (1) the Trust, upon approval of the holders of at least 75% of the outstanding Trust Units, sells the Net Profits Interest, (2) the annual cash proceeds received by the Trust attributable to the Net Profits Interest are less than $2 million for each of any two consecutive years, (3) the holders of at least 75% of the outstanding Trust Units vote in favor of dissolution or (4) the Trust is judicially dissolved.


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The Trust is required to make monthly cash distributions of substantially all of its monthly cash receipts, after deducting the Trust's administrative expenses, to holders of record (generally the last business day of each calendar month) on or before the 10th business day after the record date.

The amount of Trust revenues and cash distributions to Trust unitholders depends on, among other things:

oil and natural gas sales prices;

volumes of oil and natural gas produced and sold attributable to the Underlying Properties;

production and development costs;

price differentials;

potential reductions or suspensions of production; and

the amount and timing of Trust administrative expenses.

Generally, cash payment is received by Enduro for oil production 30 to 60 days after it is produced and for natural gas production 60 to 90 days after it is produced.

Results of Operations

Three Months Ended September 30, 2013 Compared to Three Months Ended
September 30, 2012

The Trust's net profits income consists of monthly net profits attributable to
the Net Profits Interest. Net profits income for the three months ended
September 30, 2013 and 2012 was determined as shown in the following table:



                                              Three Months Ended September 30,             Increase
                                                 2013                   2012              (Decrease)
Gross profits:
Oil sales                                  $     19,682,589         $  23,038,103                 (15 %)
Natural gas sales                                 7,614,233             6,038,434                  26 %

Total                                            27,296,822            29,076,537                  (6 %)

Costs:
Direct operating expenses:
Lease operating expenses                          7,105,000             7,590,000                  (6 %)
Compression, gathering and
transportation                                      930,000             1,150,000                 (19 %)
Production, ad valorem and other taxes            1,900,000             2,125,000                 (11 %)
Development expenses                              1,100,000             3,542,694                 (69 %)

Total                                            11,035,000            14,407,694                 (23 %)

Settlement of hedge contracts                     1,492,668             3,405,109                 (56 %)

Net profits                                $     17,754,490         $  18,073,952                  (2 %)
Percentage allocable to Net Profits
Interest                                                 80 %                  80 %

Income from Net Profits Interest           $     14,203,592         $  14,459,162                  (2 %)
Trust general and administrative
expenses and cash withheld for
expenses                                            174,962               124,985                  40 %

Distributable income                       $     14,028,630         $  14,334,177                  (2 %)


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The following table displays oil and natural gas sales volumes and average prices (excluding the effects of the hedging arrangements discussed in Note 4 of the Notes to Financial Statements) from the Underlying Properties, representing the amounts included in the Net Profits Interest calculation for distributions paid during the three months ended September 30, 2013 and 2012:

                                              Three Months Ended September 30,                Increase
                                               2013                      2012                (Decrease)
Underlying Properties Production
Volumes:
Oil (Bbls)                                        221,096                   238,641                   (7 %)
Natural Gas (Mcf)                               2,111,895                 2,182,131                   (3 %)
Combined (BOE)                                    573,079                   602,330                   (5 %)
Average Prices:
Oil-NYMEX (March-May) ($/Bbl)            $          93.35          $         101.39                   (8 %)
Differential                             $          (4.33 )        $          (4.85 )                (11 %)

Oil prices realized ($/Bbl)              $          89.02          $          96.54                   (8 %)
Natural gas-NYMEX (February-April)
($/Mcf)                                  $           3.55          $           2.44                   45 %
Differential                             $           0.06          $           0.33                  (82 %)

Natural gas prices realized ($/Mcf)      $           3.61          $           2.77                   30 %

Net profits income received by the Trust amounted to $14.2 million for the quarter ended September 30, 2013, a decrease of $0.3 million, or 2%, from the $14.5 million for the third quarter of 2012. The decrease was due to a reduction in oil revenues and cash receipts from hedge settlements, partially offset by lower capital expenditures in the third quarter of 2013 as compared to the third quarter of 2012.

Oil sales included in the third quarter 2013 net profits interest calculation primarily relate to oil produced from the Underlying Properties from March to May 2013. As compared to the third quarter of 2012, oil sales decreased 15% as a result of a decline in oil volumes and a decrease in NYMEX oil prices. Oil volumes were 7% lower for the third quarter of 2013 compared to the third quarter of 2012 as a result of production declines on producing wells. Due to delays in completing wells in the Permian Basin that were drilled in the first quarter of 2013, the decline in producing wells was not offset by oil volumes from new wells. During the months represented by the third quarter of 2013 net profits interest calculation, wellhead prices received for oil volumes decreased by $7.52 per Bbl as a result of a decrease in the NYMEX price of oil from $101.39 per Bbl to $93.35 per Bbl.

Natural gas sales included in the third quarter 2013 net profits interest calculation primarily relate to natural gas produced from the Underlying Properties from February to April 2013. Natural gas sales increased 26% from the net profits interest calculation for the quarter ended September 30, 2012 to the quarter ended September 30, 2013 due to a 45% increase in NYMEX natural gas prices, partially offset by reduced natural gas volumes. Natural gas volumes reported during the third quarter of 2013 were slightly lower as a result of the natural decline of wells located in north Louisiana, partially offset by additional revenues received during the 2013 period as a result of the timing of cash receipts. As natural gas sales volumes reported represent volumes for which Enduro was paid during the applicable period, reported volumes can fluctuate due to the timing of cash receipts from operators. During the third quarter of 2013, natural gas volumes reported included approximately 258,000 Mcf that was paid by an operator for 23 months of production from a well in north Louisiana. These volumes represent past production months for which Enduro was not paid on a timely basis.

Direct operating expenses included in the third quarter 2013 net profits interest calculation relate to expenses incurred from April to June 2013. Direct operating expenses decreased 23% from the third quarter of 2012 to the third quarter of 2013 primarily due to a $2.4 million decrease in capital expenditures. In addition, lower sales volumes for both oil and natural gas led to decreased lease operating expenses as well as lower production tax expenses. Production, ad valorem and other taxes decreased 11% from the quarter ended September 30, 2012 to the quarter ended September 30, 2013 primarily due to lower oil revenues received. Capital development expenses decreased $2.4 million to $1.1 million in the third quarter of 2013 as compared to the third quarter of 2012 due to a decrease in natural gas drilling projects. Capital development expenses for the three months ended September 30, 2012 primarily related to 6 gross (1.0 net) natural gas wells drilled in north Louisiana.

General and administrative expenses and cash withheld for expenses increased $50,000 from the third quarter 2012 to the third quarter 2013. General and administrative expenses for the three months ended September 30, 2013 were higher primarily due to a progress payment for the Trust's 2013 quarterly reviews and year-end financial statement audit, which during 2012 was paid during the fourth quarter.


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Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Net profits income for the nine months ended September 30, 2013 and 2012 was determined as shown in the following table:

                                              Nine Months Ended September 30,             Increase
                                                 2013                   2012             (Decrease)
Gross profits:
Oil sales                                  $     56,960,258         $ 70,254,594                 (19 %)
Natural gas sales                                22,962,787           25,389,307                 (10 %)

Total                                            79,923,045           95,643,901                 (16 %)

Costs:
Direct operating expenses:
Lease operating expenses                         22,955,000           24,053,716                  (5 %)
Compression, gathering and
transportation                                    2,805,000            3,378,270                 (17 %)
Production, ad valorem and other taxes            5,400,000            7,334,989                 (26 %)
Development expenses                             11,950,000           13,834,354                 (14 %)

Total                                            43,110,000           48,601,329                 (11 %)

Settlement of hedge contracts                     6,576,861            8,158,043                 (19 )%

Net profits                                $     43,389,906         $ 55,200,615                 (21 %)
Percentage allocable to Net Profits
Interest                                                 80 %                 80 %

Income from Net Profits Interest           $     34,711,925         $ 44,160,492                 (21 %)
Trust general and administrative
expenses and cash withheld for
expenses                                            450,005              749,982                 (40 %)

Distributable income                       $     34,261,920         $ 43,410,510                 (21 %)

The following table displays oil and natural gas sales volumes and average prices (excluding the effects of the hedging arrangements discussed in Note 4 of the Notes to Financial Statements) from the Underlying Properties, representing the amounts included in the net profits calculation for distributions paid during the nine months ended September 30, 2013 and 2012:

                                                  Nine Months Ended September 30,               Increase
                                                     2013                    2012              (Decrease)
Underlying Properties Production Volumes:
Oil (Bbls)                                              673,199               754,596                  (11 %)
Natural Gas (Mcf)                                     6,820,364             7,168,434                   (5 %)
Combined (BOE)                                        1,809,926             1,949,335                   (7 %)
Average Prices:
Oil-NYMEX (September-May) ($/Bbl)              $          92.17          $      97.10                   (5 %)
Differential                                   $          (7.56 )        $      (4.00 )                 89 %

Oil prices realized ($/Bbl)                    $          84.61          $      93.10                   (9 %)
Natural gas-NYMEX (August-April) ($/Mcf)       $           3.31          $       3.25                    2 %
Differential                                   $           0.06          $       0.29                  (79 %)

Natural gas prices realized ($/Mcf)            $           3.37          $       3.54                   (5 %)

Net profits income received by the Trust amounted to $34.7 million for the nine months ended September 30, 2013, a decrease of $9.4 million, or 21%, from the $44.2 million for the nine months ended September 30, 2012. The decrease was primarily due to a reduction in oil and natural gas revenues and cash receipts from hedge settlements, partially offset by lower capital expenditures during the 2013 period. In addition to NYMEX oil prices that were 5% lower for the relevant production periods compared to the same periods in 2012, average oil prices received during the periods represented by the nine months ended September 30, 2013 distribution were impacted by wider than historical basis differentials in the Permian Basin for several production months early in 2013. As a result, realized oil prices declined by 9%.


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Oil sales included in the nine months ended September 30, 2013 net profits interest calculation primarily relate to oil produced from the Underlying Properties from September 2012 to May 2013. As compared to the nine months ended September 30, 2012, oil sales decreased 19% as a result of a decline in oil volumes and NYMEX prices as well as an increase in the oil differential. Oil volumes declined as a result of production declines on producing wells and reductions in volumes due to the timing of payments received from third parties for the Underlying Properties. Due to delays in completing wells in the Permian Basin that were drilled in the first quarter of 2013, the decline in producing wells was not offset by oil volumes from new wells. During the 2012 period, Enduro was continuing to receive payments for oil production from the effective date of the Trust of June 1, 2011, resulting in higher oil volumes reported for that period. Oil volumes were 673.2 MBbls for the nine months ended September 30, 2013, a decrease of 81.4 MBbls from 754.6 MBbls for the same period of 2012. Of the volumes reported for the 2012 period, 24.0 MBbls related to June to August 2011 oil produced, for which payments generally would have been received in the fourth quarter 2011. In addition to reduced volumes, the wellhead price received for oil volumes declined from the 2012 period. During the months represented by the net profits interest calculation for the nine months ended September 30, 2013, average oil prices decreased by $8.49 per Bbl as a result of lower NYMEX oil prices and wider differentials. For the nine months ended September 30, 2013, differentials widened to 8% below NYMEX as compared to 4% below NYMEX for the same period of 2012. Basis differentials in the Permian Basin were wider than historical levels through February 2013 production but tightened to return to normal levels in March 2013.

Natural gas sales included in the nine months ended September 30, 2013 net profits interest calculation primarily relate to natural gas produced from the Underlying Properties from August 2012 to April 2013. Natural gas sales decreased 10% from the net profits interest calculation for the nine months ended September 30, 2012 to the nine months ended September 30, 2013 due to a 5% reduction in natural gas volumes and a $0.17 per Mcf decrease in realized prices. Natural gas volumes reported during the nine months ended September 30, 2013 were lower as a result of the natural decline of wells located in north Louisiana, partially offset by additional revenues received during the 2013 period as a result of the timing of cash receipts. As natural gas sales volumes reported represent volumes for which Enduro was paid during the applicable period, reported volumes can fluctuate due to the timing of cash receipts from operators. During the nine month ended September 30, 2013, natural gas volumes reported included approximately 258,000 Mcf that was paid by an operator for 23 months of production from a well in north Louisiana. Although NYMEX natural gas prices increased by 2%, the differential to realized prices widened resulting in a lower wellhead price for the nine months ended September 30, 2013.

Direct operating expenses decreased 11% from the nine months ended September 30, 2012 net profits interest distribution calculation to the same period of 2013, primarily due to lower sales volumes, which decreased lease operating, production tax and transportation expenses incurred. Production, ad valorem and other taxes decreased 26% from the nine months ended September 30, 2012 to the nine months ended September 30, 2013 mainly due to lower sales prices received. In addition, during the nine months ended September 30, 2012, additional expenses were recorded to production, ad valorem and other taxes as a result of higher than estimated actual expenses during prior periods. Capital development expenses decreased $1.9 million to $12.0 million in the nine months ended September 30, 2013 as compared to the same period of 2012. Although there was an increase in oil drilling projects in which Enduro owns higher interests during the first six months of 2013, the third quarter was significantly lower resulting in a 14% decrease in total capital development expenses. The net profits interest calculation for the nine months ended September 30, 2012 included capital for several wells being drilled in the Haynesville Shale. Capital development expenses for the nine months ended September 30, 2013 primarily relate to two Permian oil wells being drilled in the Lost Tank field in southeastern New Mexico in which Enduro owns a 50% working interest. Capital development expenses for the nine months ended September 30, 2013 noted above represent expenses incurred from October 2012 to June 2013. Enduro expects capital expenditures incurred during the year ending December 31, 2013 to range from $14 million to $16 million attributable to the properties in which the Trust has an interest, or $11 million to $13 million net to the Trust's 80% net profits interest. For 2014, Enduro expects capital expenditures to remain consistent with 2013 and range from $14 million to $16 million attributable to the properties in which the Trust has an interest.

General and administrative expenses and cash withheld for expenses decreased $0.3 million from the nine months ended September 30, 2012 net profits interest calculation to the nine months ended September 30, 2013 calculation. General and administrative expenses for the nine months ended September 30, 2012 were higher primarily due to payment for the initial listing fee and 2012 annual listing fees for the Trust on the NYSE.

Liquidity and Capital Resources

The Trust's principal sources of liquidity are cash flow generated from the Net Profits Interest and borrowing capacity under the letter of credit described below. Other than Trust administrative expenses, including any reserves established by the Trustee for future liabilities, the Trust's only use of cash is for distributions to Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the Net Profits Interest and other sources (such as interest earned on any amounts reserved by the Trustee) in that month, over the Trust's expenses paid for that month. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future expenses.

The Trustee may create a cash reserve to pay for future liabilities of the Trust. If the Trustee determines that the cash on hand and the cash to be received are, or will be, insufficient to cover the Trust's liabilities, the Trustee may authorize the Trust to borrow money to pay administrative or incidental expenses of the Trust that exceed cash held by the Trust. The Trustee may authorize the


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Trust to borrow from any person, including the Trustee or the Delaware Trustee or an affiliate thereof, although none of the Trustee, the Delaware Trustee or any affiliate of either of them intends to lend funds to the Trust. The Trustee may also cause the Trust to mortgage its assets to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were loaned by the entity serving as Trustee or Delaware Trustee or an affiliate thereof, would be similar to the terms which such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. In addition, Enduro provided the Trust with a $1 million letter of credit to be used by the Trust in the event that its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative expenses. Further, if the Trust requires more than the $1 million under the letter of credit to pay administrative expenses, Enduro has agreed to loan funds to the Trust necessary to pay such expenses. Any loan made by Enduro to the Trust would be evidenced by a written promissory note, be on an unsecured basis, and have terms that are no less favorable to Enduro as those that would be obtained in an arm's length transaction between Enduro and an unaffiliated third party. If the Trust borrows funds, draws on the letter of credit or Enduro loans funds to the Trust, no further distributions will be made to Trust unitholders until such amounts borrowed or drawn are repaid. Except for the foregoing, the Trust has no source of liquidity or capital resources. The Trustee has no current plans to authorize the Trust to borrow money. Since the Trust's formation, it has not borrowed any funds and no amounts have been drawn on the letter of credit.

Any amounts received by Enduro from the hedge contract counterparties upon settlement of the hedge contracts will reduce the operating expenses related to the Underlying Properties in calculating the net profits. However, if the hedge payments received by Enduro under the hedge contracts and other non-production revenue exceed operating expenses during a period, the ability to use such excess amounts to offset operating expenses will be deferred, with interest accruing on such amounts at the prevailing prime rate, until the next period where the hedge payments and the other non-production revenue are less than such expenses. Any amounts paid by Enduro on settlement of the hedge contracts will reduce the amount of net profits paid to the Trust.

The Trust pays the Trustee an administrative fee of $200,000 per year. The Trust pays the Delaware Trustee a fee of $2,000 per year. The Trust also incurs, either directly or as a reimbursement to the Trustee, legal, accounting, tax and . . .

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