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Washington, D.C. 20549
Enduro Royalty Trust | Enduro Resource Partners LLC | |
(Exact Name of co-registrant as specified in its charter) | (Exact Name of co-registrant as specified in its charter) | |
Delaware | Delaware | |
(State or other jurisdiction of incorporation or organization) | (State or other jurisdiction of incorporation or organization) | |
1311 | 1311 | |
(Primary Standard Industrial Classification Code Number) | (Primary Standard Industrial Classification Code Number) | |
45-6259461 | 27-2036288 | |
(I.R.S. Employer Identification No.) | (I.R.S. Employer Identification No.) | |
919 Congress Avenue, Suite 500 Austin, Texas 78701 (512) 236-6599 | 777 Main Street, Suite 800 Fort Worth, Texas 76102 (817) 744-8200 Attention: John W. Arms | |
(Address, including zip code, and telephone number, including area code, of co-registrant’s Principal Executive Offices) | (Address, including zip code, and telephone number, including area code, of co-registrant’s Principal Executive Offices) |
The Bank of New York Mellon Trust Company, N.A., Trustee 919 Congress Avenue, Suite 500 Austin, Texas 78701 (512) 236-6599 Attention: Michael J. Ulrich (Name, address, including zip code, and telephone number, including area code, of agent for service) | Jon S. Brumley 777 Main Street, Suite 800 Fort Worth, Texas 76102 (817) 744-8200 (Name, address, including zip code, and telephone number, including area code, of agent for service) |
Sean T. Wheeler Latham & Watkins LLP 717 Texas Avenue, Suite 1600 Houston, Texas 77002 (713) 546-5400 | Joshua Davidson Gerald M. Spedale Baker Botts L.L.P. 910 Louisiana, Suite 3200 Houston, Texas 77002 (713) 229-1234 |
Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o |
Proposed Maximum | Amount of | |||||
Title of Each Class of | Aggregate | Registration | ||||
Securities to be Registered | Offering Price(1)(2) | Fee | ||||
Units of Beneficial Interest in Enduro Royalty Trust | $375,000,000 | $43,538 | ||||
(1) | Includes trust units issuable upon exercise of the underwriters’ option to purchase additional trust units. | |
(2) | Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o). |
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The information in this prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted. |
Per Trust Unit | Total | |||||||
Price to the public | $ | $ | ||||||
Underwriting discounts and commissions(1) | $ | $ | ||||||
Proceeds, before expenses, to Enduro Sponsor | $ | $ |
(1) | Excludes a structuring fee of % of the gross proceeds of the offering payable to Barclays Capital Inc. by Enduro Sponsor for the evaluation, analysis and structuring of the trust. |
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ENDURO-1 | ||||||||
ENDURO F-1 | ||||||||
ANNEX A-1-1 | ||||||||
ANNEX A-2-1 | ||||||||
ANNEX A-3-1 | ||||||||
ANNEX B-1 | ||||||||
ANNEX C-1 | ||||||||
EX-3.1 | ||||||||
EX-3.3 | ||||||||
EX-3.4 | ||||||||
EX-21.1 | ||||||||
EX-23.1 | ||||||||
EX-23.2 | ||||||||
EX-23.5 |
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Underlying Properties | ||||||||||||||||||||||||
Average Daily Net | ||||||||||||||||||||||||
As of December 31, 2010 | Production For Year | |||||||||||||||||||||||
Proved Reserves(1) | Ended December 31, | As of December 31, | ||||||||||||||||||||||
PV-10 | Total | % Proved Developed | 2010 | 2010 | ||||||||||||||||||||
Operating Area | Value(2) | (MBoe)(3) | % Oil | Reserves | (Boe per day) | R/P Ratio(4) | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Permian Basin | $ | 279,975 | 16,321 | 78 | % | 96 | % | 3,526 | 13 | |||||||||||||||
East Texas/North Louisiana | 69,557 | 10,743 | 0 | % | 48 | % | 2,321 | 13 | ||||||||||||||||
Total | $ | 349,532 | 27,064 | 47 | % | 76 | % | 5,847 | 13 | |||||||||||||||
(1) | In accordance with the rules and regulations promulgated by the SEC, the proved reserves presented above were determined using the twelve month unweighted arithmetic average of thefirst-day-of-the-month price for the period from January 1, 2010 through December 31, 2010, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $79.43 per Bbl and a price for natural gas of $4.37 per MMBtu. | |
(2) | PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10%, calculated without deducting future income taxes. Standardized measure of discounted future net cash flows is calculated the same asPV-10 except that it deducts future income taxes and future abandonment costs. Because Enduro Sponsor bears no federal income tax expense and taxable income is passed through to the unitholders of the trust, no provision for federal or state income taxes is included in the reserve reports.PV-10 may not be considered a generally accepted accounting principle (“GAAP”) financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. The pre-taxPV-10 value and the standardized measure of discounted future net cash flows do not purport to present the fair value of the oil and natural gas reserves attributable to Underlying Properties. | |
(3) | Oil equivalents in the table are the sum of the Bbls of oil and the Boe of the stated Mcfs of natural gas, calculated on the basis that six Mcfs of natural gas is the energy equivalent of one Bbl of oil. | |
(4) | The R/P ratio, or thereserves-to-production ratio, is a measure of the number of years that a specified reserve base could support a fixed amount of production. This ratio is calculated by dividing total estimated proved reserves of the subject properties at the end of a period by annual total production for the prior 12 months. Because production rates naturally decline over time, the R/P ratio is not a useful estimate of how long properties should economically produce. Based on the reserve report, economic production from the Underlying Properties is expected for at least 50 more years. |
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% of Total | ||||||||||
PV-10 at | PV-10 at | |||||||||
Field Name | Operator | December 31, 2010 | December 31, 2010 | |||||||
(In thousands) | ||||||||||
Elm Grove Field | Petrohawk Energy Corporation, J-W Operating, Questar Corporation | $ | 54,591 | 16 | % | |||||
North Monument Grayburg Unit | Apache Corporation | 42,989 | 12 | % | ||||||
North Central Levelland Unit | Apache Corporation | 39,208 | 11 | % | ||||||
North Cowden Unit | Occidental Permian Ltd. | 32,563 | 9 | % | ||||||
Yates Field Unit | Kinder Morgan Inc. | 18,052 | 5 | % | ||||||
Total | $ | 187,403 | 53 | % |
• | Stable oil base combined with significant production and inventories of low risk natural gas locations. The Underlying Properties in the Permian Basin region include multiple mature oil fields currently using secondary and tertiary recovery methods. These fields typically are characterized by stable production profiles. Many of the Underlying Properties |
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in the Permian Basin currently under waterflood have CO2 recovery potential, which could increase the ultimate oil recovered from these fields. The Underlying Properties located in the East Texas/North Louisiana region have significant natural gas production and near-term growth potential stemming primarily from the development of the Haynesville Shale and the Horizontal Cotton Valley plays. Future increases in natural gas prices could accelerate development activity in this region, thereby increasing cash flows. |
• | Substantial proved developed reserves. Proved developed reserves are the most valuable and lowest risk category of reserves because their production requires no significant future development expenses. As of December 31, 2010, approximately 75% of the volumes and 91% of thePV-10 value of the proved reserves associated with the Underlying Properties were attributed to proved developed reserves. | |
• | Additional development opportunities. Enduro Sponsor believes that the Underlying Properties are likely to offer economic development opportunities in the future that are not reflected in existing proved reserves and that could significantly increase future reserves and production. In the Permian Basin region, future increases in estimated oil recovery factors may increase reserves and production. Such increases in recovery factors may occur through, among other means, the implementation of additional enhanced recovery techniques, infill drilling, and production outperformance. Examples of potential development opportunities not included in proved reserves in the East Texas/North Louisiana region include increased density drilling, refracs, and development of prospective formations such as the Bossier Shale and Smackover, among others. | |
• | Location in areas with significant histories of oil and natural gas production. Long producing histories in the Permian Basin and East Texas/North Louisiana regions provide for well established production profiles and increased certainty of production estimates. These regions also have significant access to oilfield services and pipeline takeaway infrastructure. In addition, we believe that operating risk is generally lower in regions accustomed to oil and natural gas production. | |
• | Leading third party operators. In the Permian Basin region, approximately 70% of thePV-10 value of the proved reserves is operated by Occidental Petroleum, Apache Corporation or Kinder Morgan, all of which are among the top 10 producers in the basin by volume. These operators also have many years of experience in maximizing production response from mature oil and natural gas fields through enhanced recovery techniques. In the East Texas/North Louisiana region, approximately 85% of thePV-10 value of proved reserves is operated by Petrohawk Energy Corporation or EXCO Resources, Inc. These companies are two of the most active operators in the Haynesville Shale play and have significant operating experience in the region. | |
• | Downside commodity price protection. To mitigate the negative effects of a possible decline in oil and natural gas prices on distributable income to the trust, Enduro Sponsor has entered into hedging contracts through December 31, 2013. These hedging contracts include a combination of fixed price swaps, collars, and floors to protect the trust’s downside, while still allowing the trust to participate in increasing oil and natural gas markets. After December 31, 2013, none of the production attributable to the Underlying Properties will be hedged. | |
• | High Operating Margins. The Underlying Properties have historically generated substantial operating margins. Lease operating expenses and property and other taxes on the Underlying Properties averaged $15.93 per Boe during the past three years. During the same period, the sales price for oil and natural gas averaged $52.65 per Boe, providing an operating margin of $36.72 per Boe, or 70%. |
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• | Aligned interests of sponsor. Following the closing of this offering, Enduro Sponsor will have an effective ownership of approximately % of the net profits attributable to the sale of oil and natural gas produced from the Underlying Properties, including its retained 20% direct interest in the Underlying Properties and its ownership of approximately % of the trust units. |
• | Enduro Sponsor will convey to the trust the Net Profits Interest effective as of April 1, 2011 in exchange for trust units in the aggregate, representing all of the outstanding trust units of the trust. | |
• | Enduro Sponsor will sell trust units offered hereby, representing an % interest in the trust. Enduro Sponsor will also make available during the30-day option period up to trust units for the underwriters to purchase at the initial offering price to cover over-allotments. Enduro Sponsor intends to use the proceeds of the offering as disclosed under “Use of Proceeds.” | |
• | Enduro Sponsor and the trust will enter into an administrative services agreement which will define the services Enduro Sponsor will provide to the trust on an ongoing basis as well as its compensation therefor. Please read “The Trust.” |
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• | Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to unitholders. | |
• | Estimates of future cash distributions to unitholders are based on assumptions that are inherently subjective. | |
• | Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units. | |
• | The Third Party Operators are the operators of substantially all of the wells on the Underlying Properties and, therefore, Enduro Sponsor is not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties. | |
• | Developing oil and natural gas wells and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect future production from the Underlying Properties. Any delays, reductions or cancellations in development and producing activities could decrease revenues that are available for distribution to unitholders. | |
• | The trust is passive in nature and neither the trust nor the trust unitholders will have any ability to influence Enduro Sponsor or control the operations or development of the Underlying Properties. | |
• | Shortages of equipment, services and qualified personnel could increase costs of developing and operating the Underlying Properties and result in a reduction in the amount of cash available for distribution to the trust unitholders. | |
• | The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties. | |
• | Enduro Sponsor may transfer all or a portion of the Underlying Properties at any time without trust unitholder consent, subject to specified limitations. | |
• | The reserves attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the trust and cash distributions to unitholders will decrease over time. | |
• | An increase in the differential between the price realized by Enduro Sponsor for oil or natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the proceeds to the trust and, therefore, the cash distributions by the trust and the value of trust units. | |
• | The amount of cash available for distribution by the trust will be reduced by the amount of any costs and expenses related to the Underlying Properties and other costs and expenses incurred by the trust. | |
• | The generation of proceeds for distribution by the trust depends in part on access to and operation of gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil and natural gas production form the Underlying Properties. | |
• | The trustee must, under certain circumstances, sell the Net Profits Interest and dissolve the trust prior to the expected termination of the trust. As a result, trust unitholders may not recover their investment. | |
• | Enduro Sponsor may sell trust units in the public or private markets, and such sales could have an adverse impact on the trading price of the trust units. |
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• | There has been no public market for the trust units. | |
• | The trading price for the trust units may not reflect the value of the Net Profits Interest held by the trust. | |
• | Conflicts of interest could arise between Enduro Sponsor and its affiliates, on the one hand, and the trust and the trust unitholders, on the other hand. | |
• | The trust is managed by a trustee who cannot be replaced except by a majority vote of the unitholders at a special meeting, which may make it difficult for unitholders to remove or replace the trustee. | |
• | Trust unitholders have limited ability to enforce provisions of the Net Profits Interest, and Enduro Sponsor’s liability to the trust is limited. | |
• | Courts outside of Delaware may not recognize the limited liability of the trust unitholders provided under Delaware law. | |
• | The operations of the Underlying Properties are subject to environmental laws and regulations that may result in significant costs and liabilities, which could reduce the amount of cash available for distribution to trust unitholders. | |
• | The operations of the Underlying Properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting its operations or expose the operator to significant liabilities, which could reduce the amount of cash available for distribution to trust unitholders. | |
• | Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that the operators produce while the physical effects of climate change could disrupt their production and cause them to incur significant costs in preparing for or responding to those effects. | |
• | Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect the services of the operators of the Underlying Properties. | |
• | The bankruptcy of Enduro Sponsor or any of the Third Party Operators could impede the operation of the wells and the development of the proved undeveloped reserves. | |
• | In the event of the bankruptcy of Enduro Sponsor, if a court held that the Net Profits Interest was part of the bankruptcy estate, the trust may be treated as an unsecured creditor with respect to the Net Profits Interest attributable to properties in Louisiana. | |
• | Adverse developments in Texas, Louisiana or New Mexico could adversely impact the results of operations and cash flows of the Underlying Properties and reduce the amount of cash available for distributions to trust unitholders. | |
• | The receipt of payments by Enduro Sponsor based on the hedge contracts depends upon the financial position of the hedge contract counterparties. A default by any of the hedge contract counterparties could reduce the amount of cash available for distribution to the trust unitholders. | |
• | The tax treatment of an investment in trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis. | |
• | The trust has not requested a ruling from the IRS regarding the tax treatment of the trust. If the IRS were to determine (and be sustained in that determination) that the trust is not a “grantor trust” for federal income tax purposes, the trust could be subject to |
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more complex and costly tax reporting requirements that could reduce the amount of cash available for distribution to trust unitholders. |
• | Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation. |
Year Ended | ||||
December 31, 2010 | ||||
(In thousands) | ||||
(Unaudited) | ||||
Revenues: | ||||
Oil | $ | 70,033 | ||
Natural gas | 33,787 | |||
Total | 103,820 | |||
Direct operating expenses: | ||||
Lease operating expenses | 24,579 | |||
Gathering and processing | 1,977 | |||
Production and other taxes | 8,069 | |||
Total direct operating expenses | 34,625 | |||
Excess of revenues over direct operating expenses | $ | 69,195 | ||
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Year Ended | ||||
December 31, 2010 | ||||
(In thousands, except per unit data) | ||||
(Unaudited) | ||||
Excess of revenues over direct operating expenses | $ | 69,195 | ||
Less development expenses | 37,036 | |||
Excess of revenues over direct operating expenses and development expenses | 32,159 | |||
Times Net Profits Interest | 80 | % | ||
Income from Net Profits Interest | 25,727 | |||
Pro forma adjustments: | ||||
Less estimated trust general and administrative expenses | 5,068 | |||
Distributable income | $ | 20,659 | ||
Distributable income per trust unit | ||||
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(Unaudited) | ||||||||||||
Operating Data: | ||||||||||||
Sales volumes: | ||||||||||||
Oil (MBbls) | 939 | 1,016 | 1,084 | |||||||||
Natural gas (MMcf) | 7,171 | 8,455 | 8,868 | |||||||||
Total sales (MBoe) | 2,134 | 2,425 | 2,562 | |||||||||
Average sales prices: | ||||||||||||
Oil (per Bbl) | $ | 74.58 | $ | 54.44 | $ | 98.52 | ||||||
Natural gas (per Mcf) | $ | 4.71 | $ | 3.91 | $ | 8.57 | ||||||
Average costs per Boe: | ||||||||||||
Lease operating expense | $ | 11.52 | $ | 10.65 | $ | 11.45 | ||||||
Gathering and processing | $ | 0.93 | $ | 0.78 | $ | 1.18 | ||||||
Production and other taxes | $ | 3.78 | $ | 3.10 | $ | 4.38 | ||||||
Capital expenditures (in thousands): | ||||||||||||
Property development costs | $ | 37,036 | $ | 18,532 | $ | 65,571 |
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Enduro | ||||||||||||||||||||||
Sponsor | ||||||||||||||||||||||
Pro Forma | ||||||||||||||||||||||
Enduro | As Adjusted | |||||||||||||||||||||
Sponsor | for the Offering | |||||||||||||||||||||
Pro Forma for the | (including the | |||||||||||||||||||||
Acquisition of the | conveyance of the | Predecessor-DNR | Predecessor-EAC | |||||||||||||||||||
Acquired Properties | Net Profits Interest) | Enduro Sponsor | March 9, 2010 | January 1, 2010 | ||||||||||||||||||
Year Ended | Year Ended | Inception Through | Through | Through | ||||||||||||||||||
December 31, 2010 | December 31, 2010 | December 31, 2010 | November 30, 2010 | March 8, 2010 | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||||
(Unaudited) | ||||||||||||||||||||||
Revenues | $ | 137,712 | $ | 96,184 | $ | 3,975 | $ | 40,210 | $ | 12,164 | ||||||||||||
Net income (loss) | $ | (2,063 | ) | $ | 587 | $ | (8,222 | ) | $ | (19,515 | ) | $ | (17,821 | ) | ||||||||
Total assets (at period end) | $ | 745,441 | $ | 637,732 | $ | 361,832 | $ | 397,314 | $ | 313,106 | ||||||||||||
Long-term liabilities, excluding current maturities (at period end) | $ | 216,500 | $ | — | $ | 66,211 | $ | 587 | $ | 1,412 | ||||||||||||
Members’ capital/owners’ equity | $ | 456,619 | $ | 565,410 | $ | 273,939 | $ | 374,731 | $ | 290,073 | ||||||||||||
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• | the oil and natural gas production estimates for the twelve months ending April 30, 2012 contained in the reserve reports; | |
• | estimated direct operating expenses and development expenses for the twelve months ending April 30, 2012 contained in the reserve reports; | |
• | projected payments made or received pursuant to the hedge contracts for the twelve months ending April 30, 2012; and | |
• | estimated general and administrative expenses of $5.0 million for the twelve months ending April 30, 2012. |
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Projections for the Twelve | ||||
Month Period Ending | ||||
Projected Cash Distributions to Unitholders | August 31, 2012 | |||
(Dollars in thousands | ||||
except per unit data) | ||||
Underlying Properties sales volumes: | ||||
Oil (MBbl)(1) | 911 | |||
Natural gas (MMcf) | 7,119 | |||
Total sales (MBoe) | 2,097 | |||
Assumed NYMEX price(2): | ||||
Oil (per Bbl) | $ | 100.00 | ||
Natural gas (per MMBtu) | 4.50 | |||
Assumed realized sales price(3): | ||||
Oil (per Bbl) | $ | 96.54 | ||
Natural gas (per Mcf) | 4.63 | |||
Calculation of net profits: | ||||
Gross profits: | ||||
Oil sales | $ | 87,940 | ||
Natural gas sales | 32,979 | |||
Total | 120,919 | |||
Costs: | ||||
Direct operating expenses: | ||||
Lease operating expenses | $ | 23,489 | ||
Production and other taxes | 9,225 | |||
Development expenses | 14,000 | |||
Total | 46,714 | |||
Settlement of hedge contracts(4) | — | |||
Net profits | 74,205 | |||
Percentage allocable to Net Profits Interest | 80% | |||
Net profits to trust from Net Profits Interest | $ | 59,364 | ||
Trust general and administrative expenses(5) | 5,037 | |||
Cash available for distribution by the trust | $ | 54,327 | ||
Cash distribution per trust unit (assumes units) | ||||
(1) | Sales volumes for oil include 9 MBbls of NGLs. | |
(2) | For a description of the effect of lower NYMEX prices on projected cash distributions, please read “Projected Cash Distributions — Sensitivity of Projected Cash Distributions to Oil and Natural Gas Production and Prices.” | |
(3) | Sales price net of forecasted gravity, quality, transportation, and marketing costs. For more information about the estimates and hypothetical assumptions made in preparing the table above, |
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please read “Projected Cash Distributions — Significant Assumptions Used to Prepare the Projected Cash Distributions.” | ||
(4) | Reflects net cash impact of settlements of hedge contracts relating to production. See “The Underlying Properties — Hedge Contracts.” | |
(5) | Total general and administrative expenses of the trust on an annualized basis for the twelve months ending April 30, 2012 are expected to be $5.0 million and will include an administrative services fee to Enduro Sponsor, the annual fees to the trustees, accounting fees, engineering fees, legal fees, printing costs and other expenses properly chargeable to the trust. The administrative services fee to Enduro Sponsor will be paid monthly in an amount equal to $2.50 per Boe of production, subject to an annual increase beginning in January 2012 of 3.0% per annum up to a maximum monthly administrative services fee of $3.00 per Boe of production. For purposes of calculating the monthly administrative services fee, production for the monthly period will be equal to the production attributable to the Underlying Properties multiplied by the Net Profits Interest percentage (80%). |
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Trust units offered by Enduro Sponsor | trust units, or trust units if the underwriters exercise their option to purchase additional trust units in full | |
Trust units owned by Enduro Sponsor after the offering | trust units, or trust units if the underwriters exercise their option to purchase additional trust units in full | |
Trust units outstanding after the offering | trust units | |
Use of proceeds | Enduro Sponsor is offering all of the trust units to be sold in this offering, including the trust units to be sold upon any exercise of the underwriters’ option to purchase additional trust units. The estimated net proceeds of this offering to be received by Enduro Sponsor will be approximately $ million, after deducting underwriting discounts and commissions, structuring fees and expenses, and $ million if the underwriters exercise their option to purchase additional trust units in full. Enduro Sponsor intends to use the net proceeds from this offering, including any proceeds from the exercise of the underwriters’ option to purchase additional trust units, to repay amounts outstanding under its senior secured credit agreement and for general limited liability company purposes. Enduro Sponsor is deemed to be an underwriter with respect to the trust units offered hereby. Please read “Use of Proceeds.” | |
Proposed NYSE symbol | “NDRO” | |
Monthly cash distributions | The trust will pay monthly distributions to the holders of trust units as of the applicable record date (generally the 15th day of each calendar month) on or before the 10th business day after the record date. The first distribution from the trust to the trust unitholders will be made on or about September 29, 2011 to trust unitholders owning trust units on or about September 15, 2011. | |
Actual cash distributions to the trust unitholders will fluctuate monthly based upon the quantity of oil and natural gas produced from the Underlying Properties, the prices received for oil and natural gas production and other factors. Because payments to the trust will be generated by depleting assets with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent, in effect, a return of your original investment. Oil and natural gas production from proved reserves attributable to the Underlying Properties is expected to decline over time. Please read “Risk Factors.” | ||
Dissolution of the trust | 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 available for distribution to the trust is less than $2 million for each of any two consecutive |
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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. | ||
Estimated ratio of taxable income to distributions | We estimate that a trust unitholder who owns the trust units purchased in this offering through the record date for distribution for the period ending December 31, 20 , will recognize, on a cumulative basis, an amount of federal taxable income for that period of approximately % of the cash distributed to such trust unitholder with respect to that period. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” for the basis of this estimate. | |
Summary of income tax consequences | Trust unitholders will be taxed directly on the income from assets of the trust. Enduro Sponsor and the trust intend to treat the Net Profits Interest, which will be granted to the trust on a perpetual basis, as a mineral royalty interest that generates ordinary income subject to depletion for U.S. federal income tax purposes. Please read “Federal Income Tax Consequences.” |
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• | regional, domestic and foreign supply and perceptions of supply of oil and natural gas; | |
• | the level of demand and perceptions of demand for oil and natural gas; | |
• | political conditions or hostilities in oil and natural gas producing countries; | |
• | anticipated future prices of oil and natural gas and other commodities; | |
• | weather conditions and seasonal trends; | |
• | technological advances affecting energy consumption and energy supply; | |
• | U.S. and worldwide economic conditions; | |
• | the price and availability of alternative fuels; | |
• | the proximity, capacity, cost and availability of gathering and transportation facilities; | |
• | the volatility and uncertainty of regional pricing differentials; | |
• | governmental regulations and taxation; | |
• | energy conservation and environmental measures; and | |
• | acts of force majeure. |
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• | historical production from the area compared with production rates from other producing areas; | |
• | oil and natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and development expenses; and | |
• | the assumed effect of expected governmental regulation and future tax rates. |
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• | the timing and amount of capital expenditures; | |
• | the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel; | |
• | the Third Party Operator’s expertise, operating efficiency and financial resources; | |
• | approval of other participants in drilling wells; | |
• | the selection of technology; | |
• | the selection of counterparties for the sale of production; and | |
• | the rate of production of the reserves. |
• | delays imposed by or resulting from compliance with regulatory requirements, including permitting; | |
• | unusual or unexpected geological formations; | |
• | shortages of or delays in obtaining equipment and qualified personnel; | |
• | lack of available gathering facilities or delays in construction of gathering facilities; | |
• | lack of available capacity on interconnecting transmission pipelines; |
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• | equipment malfunctions, failures or accidents; | |
• | unexpected operational events and drilling conditions; | |
• | reductions in oil or natural gas prices; | |
• | market limitations for oil or natural gas; | |
• | pipe or cement failures; | |
• | casing collapses; | |
• | lost or damaged drilling and service tools; | |
• | loss of drilling fluid circulation; | |
• | uncontrollable flows of oil and natural gas, insert gas, water or drilling fluids; | |
• | fires and natural disasters; | |
• | environmental hazards, such as oil and natural gas leaks, pipeline ruptures and discharges of toxic gases; | |
• | adverse weather conditions; and | |
• | oil or natural gas property title problems. |
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• | Enduro Sponsor’s interests may conflict with those of the trust and the trust unitholders in situations involving the development, maintenance, operation or abandonment of certain wells on the Underlying Properties for which Enduro Sponsor acts as the operator. Enduro Sponsor may also make decisions with respect to development expenses that adversely affect the Underlying Properties. These decisions include reducing development expenses on properties for which Enduro Sponsor acts as the operator, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the trust in the future. | |
• | Enduro Sponsor may sell some or all of the Underlying Properties without taking into consideration the interests of the trust unitholders. Such sales may not be in the best |
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interests of the trust unitholders. These purchasers may lack Enduro Sponsor’s experience or its credit worthiness. Enduro Sponsor also has the right, under certain circumstances, to cause the trust to release all or a portion of the Net Profits Interest in connection with a sale of a portion of the Underlying Properties to which such Net Profits Interest relates. In such an event, the trust is entitled to receive the fair value (net of sales costs) of the Net Profits Interest released. Please read “The Underlying Properties — Sale and Abandonment of Underlying Properties.” |
• | Enduro Sponsor has registration rights and can sell its units without considering the effects such sale may have on trust unit prices or on the trust itself. Additionally, Enduro Sponsor can vote its trust units in its sole discretion without considering the interests of the other trust unitholders. Enduro Sponsor is not a fiduciary with respect to the trust unitholders or the trust and will not owe any fiduciary duties or liabilities to the trust unitholders or the trust. |
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• | 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 in alternative fuel prices; | |
• | the impact of hedging contracts; | |
• | conditions in the capital markets; | |
• | competition from others in the energy industry; | |
• | uncertainty of estimates of oil and natural gas reserves and production; and | |
• | cost inflation. |
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Enduro | ||||||||||||||||||||||||||||||
Sponsor | ||||||||||||||||||||||||||||||
Pro Forma As | ||||||||||||||||||||||||||||||
Adjusted for | ||||||||||||||||||||||||||||||
Enduro | the Offering | |||||||||||||||||||||||||||||
Sponsor | (Including the | |||||||||||||||||||||||||||||
Pro Forma | Conveyance | |||||||||||||||||||||||||||||
for the | of the | |||||||||||||||||||||||||||||
Acquisition | Net Profits | |||||||||||||||||||||||||||||
of the | Interest) | |||||||||||||||||||||||||||||
Acquired | Enduro | Predecessor-EAC | ||||||||||||||||||||||||||||
Properties | Sponsor | Predecessor-DNR | January 1, | |||||||||||||||||||||||||||
Year | Year | Inception | March 9 | 2010 | ||||||||||||||||||||||||||
Ended | Ended | Through | Through | Through | ||||||||||||||||||||||||||
December 31, | December 31, | December 31, | November 30, | March 8, | Year Ended December 31, | |||||||||||||||||||||||||
2010 | 2010 | 2010 | 2010 | 2010 | 2009 | 2008 | ||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||
(Unaudited) | ||||||||||||||||||||||||||||||
Revenues | $ | 137,712 | $ | 96,184 | $ | 3,975 | $ | 40,210 | $ | 12,164 | $ | 33,907 | $ | 62,370 | ||||||||||||||||
Net income (loss) | $ | (2,063 | ) | $ | 587 | $ | (8,222 | ) | $ | (19,515 | ) | $ | (17,821 | ) | $ | (25,853 | ) | $ | 19,540 | |||||||||||
Total assets (at period end) | $ | 745,441 | $ | 637,732 | $ | 361,832 | $ | 397,314 | $ | 313,106 | $ | 301,127 | $ | 256,783 | ||||||||||||||||
Long-term liabilities, excluding current maturities (at period end) | $ | 216,500 | $ | — | $ | 66,211 | $ | 587 | $ | 1,412 | $ | 1,404 | $ | 1,322 | ||||||||||||||||
Members’ capital/owners’ equity | $ | 456,619 | $ | 565,410 | $ | 273,939 | $ | 374,731 | $ | 290,073 | $ | 281,439 | $ | 234,433 | ||||||||||||||||
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Enduro | ||||||||||||||||||||||
Sponsor | Predecessor-DNR | Predecessor - EAC | ||||||||||||||||||||
Inception | March 9, 2010 | January 1 | ||||||||||||||||||||
Through | Through | Through | Year Ended | |||||||||||||||||||
December 31, | November 30, | March 8, | December 31, | |||||||||||||||||||
2010 | 2010 | 2010 | 2009 | 2008 | ||||||||||||||||||
Production (MBoe) | 143 | 1,505 | 329 | 1,463 | 1,194 | |||||||||||||||||
Net proved reserves (MBoe) (at period end) | 16,432 | 18,059 | 17,936 | 18,265 | 10,357 | |||||||||||||||||
Net proved developed reserves (MBoe) (at period end) | 10,667 | 9,679 | 8,685 | 9,014 | 7,836 |
Name | Age | Title | ||
Jon S. Brumley | 40 | President, Chief Executive Officer and Manager | ||
John W. Arms | 44 | Executive Vice President, Chief Operating Officer and Manager | ||
Kimberly A. Weimer | 32 | Vice President, Chief Financial Officer |
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• | each person who beneficially owns 5% or more of the outstanding membership interests in Enduro Sponsor; | |
• | each member of the executive management team of Enduro Resource Holdings LLC who will perform management functions on behalf of Enduro Sponsor; and | |
• | all members of the executive management team of Enduro Resource Holdings LLC who will perform management functions on behalf of Enduro Sponsor as a group. |
Percentage of | ||||
Membership | ||||
Interests | ||||
Beneficially | ||||
Name of Beneficial Owner | Owned | |||
Enduro Resource Holdings LLC | 100 | % | ||
Jon S. Brumley | 0 | % | ||
John W. Arms | 0 | % | ||
Kimberly A. Weimer | 0 | % | ||
Executive management as a group | 0 | % |
Class of | Percentage of | |||||
Name of Beneficial Owner | Securities | Ownership | ||||
Enduro Sponsor | Trust Units | % |
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• | oil and natural gas sales prices; | |
• | the volume of oil and natural gas produced and sold attributable to the Underlying Properties; | |
• | the payments made or received by Enduro Sponsor pursuant to the hedge contracts; | |
• | direct operating expenses; | |
• | development expenses; and | |
• | administrative expenses of the trust. |
• | the oil and natural gas production estimates for the twelve months ending April 30, 2012 contained in the reserve reports; | |
• | estimated direct operating expenses and development expenses for the twelve months ending April 30, 2012 contained in the reserve reports; and | |
• | projected payments made or received pursuant to the hedge contracts for the twelve months ending April 30, 2012; and |
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• | estimated general and administrative expenses of $5.0 million for the twelve months ending April 30, 2012. |
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Projections for the | ||||
Twelve Month Period | ||||
Ending August 31, | ||||
Projected Cash Distributions to Unitholders | 2012 | |||
(dollars in thousands) | ||||
Underlying Properties sales volumes: | ||||
Oil (MBbl)(1) | 911 | |||
Natural gas (MMcf) | 7,119 | |||
Total sales (MBoe) | 2,097 | |||
Assumed NYMEX price(2): | ||||
Oil (per Bbl) | $ | 100.00 | ||
Natural gas (per MMBtu) | 4.50 | |||
Assumed realized sales price(3): | ||||
Oil (per Bbl) | $ | 96.54 | ||
Natural gas (per Mcf) | 4.63 | |||
Calculation of net profits: | ||||
Gross profits: | ||||
Oil sales | $ | 87,940 | ||
Natural gas sales | 32,979 | |||
Total | $ | 120,919 | ||
Costs: | ||||
Direct operating expenses: | ||||
Lease operating expenses | $ | 23,489 | ||
Production and other taxes | 9,225 | |||
Development expenses | 14,000 | |||
Total | 46,714 | |||
Settlement of hedge contracts(4) | — | |||
Net profits | 74,205 | |||
Percentage allocable to Net Profits Interest | 80% | |||
Net profits to trust from Net Profits Interest | $ | 59,364 | ||
Trust general and administrative expenses(5) | 5,037 | |||
Cash available for distribution by the trust | 54,327 | |||
Cash distribution per trust unit (assumes million units) | ||||
(1) | Sales volumes for oil include 9 MBbls of NGLs. | |
(2) | For a description of the effect of lower NYMEX prices on projected cash distributions, please read “— Sensitivity of Projected Cash Distributions to Oil and Natural Gas Production and Prices.” | |
(3) | Sales price net of forecasted gravity, quality, transportation, and marketing costs. For more information about the estimates and hypothetical assumptions made in preparing the table above, see “— Significant Assumptions Used to Prepare the Projected Cash Distributions.” | |
(4) | Reflects net cash impact of hedge settlements relating to production. See “The Underlying Properties — Hedge Contracts.” | |
(5) | Total general and administrative expenses of the trust on an annualized basis for the twelve months ending April 30, 2012 are expected to be $5.0 million and will include an administrative services fee to Enduro Sponsor, the annual fee to the trustees, accounting fees, engineering fees, printing costs and other expenses properly chargeable to the trust. The administrative services fee to Enduro Sponsor will be paid monthly in an amount equal to $2.50 per Boe of production, |
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subject to an annual increase beginning in January 2012 of 3.0% per annum up to a maximum monthly administrative services fee of $3.00 per Boe of production. For purposes of calculating the monthly administrative services fee, production for the monthly period will be equal to the production attributable to the Underlying Properties multiplied by the Net Profits Interest percentage (80%). |
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to Changes in NYMEX Futures Pricing
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80% of the | Net | |||||||||||
Underlying | Underlying | Profits | ||||||||||
Properties(1) | Properties(2) | Interest | ||||||||||
(dollars in thousands) | ||||||||||||
Proved Reserves | ||||||||||||
Oil (MBbls)(3) | 12,766 | 10,213 | 5,642 | |||||||||
Natural Gas (MMcf) | 85,787 | 68,630 | 43,058 | |||||||||
Oil Equivalents (Mboe)(4) | 27,064 | 21,651 | 12,818 | |||||||||
Future Net Revenues | $ | 1,344,718 | $ | 1,075,774 | $ | 616,091 | ||||||
Future Production Cost | $ | 578,014 | $ | 462,411 | $ | 48,895 | (6) | |||||
Future Development Cost | $ | 57,674 | $ | 46,139 | $ | — | ||||||
Future Net Income | $ | 709,030 | $ | 567,196 | $ | 567,196 | ||||||
Present Value at 10% Discount Rate(5) | $ | 349,532 | $ | 279,688 | $ | 279,688 | ||||||
Standardized Measure of Discounted Future Net Cash Flows | $ | 349,532 | $ | 279,688 | $ | 279,688 |
(1) | Reserve volumes and estimated future net revenues for Underlying Properties reflect volumes and revenues attributable to Enduro Sponsor’s net interests in the properties comprising the Underlying Properties. | |
(2) | Reflects 80% of the proved reserves and future net revenues, production and development cost, net income and present value attributable to the Underlying Properties expected to be produced based on the reserve report. | |
(3) | Proved reserves for oil include volumes for NGLs (MBbls) of 183 MBbls, 146 MBbls and 101 MBbls attributable to the Underlying Properties, 80% of the Underlying Properties and the Net Profits Interest, respectively. | |
(4) | The proved reserves for 80% of the Underlying Properties and the Net Profits Interest of 21,651 Mboe and 12,818 Mboe differ by 8,833 Mboe. Proceeds from the sale of the 8,833 Mboe will be used to cover 80% of the future production and development costs attributable to the Underlying Properties for the benefit of the trust. |
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(5) | The present values of the future net revenues for the Underlying Properties and the Net Profits Interest were determined using a discount rate of 10% per annum. As of December 31, 2010, Enduro Sponsor was structured as a limited liability company. Accordingly, no provision for federal or state income taxes has been provided because taxable income was passed through to the members of Enduro Sponsor. | |
(6) | Future production costs for the Net Profits Interest consist solely of severance taxes and ad valorem taxes attributable to the trust. |
Year Ended December 31 | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Revenues: | ||||||||||||
Oil | $ | 70,033 | $ | 55,309 | $ | 106,801 | ||||||
Natural gas | 33,787 | 33,053 | 76,001 | |||||||||
Total | 103,820 | 88,362 | 182,802 | |||||||||
Direct operating expenses: | ||||||||||||
Lease operating expenses | 24,579 | 25,822 | 29,331 | |||||||||
Gathering and processing | 1,977 | 1,885 | 3,035 | |||||||||
Production and other taxes | 8,069 | 7,512 | 11,217 | |||||||||
Total direct operating expenses | 34,625 | 35,219 | 43,583 | |||||||||
Excess of revenues over direct operating expenses | $ | 69,195 | $ | 53,143 | $ | 139,219 | ||||||
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Year Ended December 31 | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(Unaudited) | ||||||||||||
Operating data: | ||||||||||||
Sales volumes: | ||||||||||||
Oil (MBbls) | 939 | 1,016 | 1,084 | |||||||||
Natural gas (MMcf) | 7,171 | 8,455 | 8,868 | |||||||||
Total sales (MBoe) | 2,134 | 2,425 | 2,562 | |||||||||
Average sales prices: | ||||||||||||
Oil (per Bbl) | $ | 74.58 | $ | 54.44 | $ | 98.52 | ||||||
Natural gas (per Mcf) | $ | 4.71 | $ | 3.91 | $ | 8.57 | ||||||
Average costs per Boe: | ||||||||||||
Lease operating expense | $ | 11.52 | $ | 10.65 | $ | 11.45 | ||||||
Gathering and processing | $ | 0.93 | $ | 0.78 | $ | 1.18 | ||||||
Production and other taxes | $ | 3.78 | $ | 3.10 | $ | 4.38 | ||||||
Capital expenditures (in thousands): | ||||||||||||
Property development costs | $ | 37,036 | $ | 18,532 | $ | 65,571 |
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Hedged | ||||||||||||||||
Term | Commodity | Structure | OilBbl/d | Floor Price | Cap Price | |||||||||||
April — December 2011 | Oil | Floor | ||||||||||||||
April — December 2011 | Oil | Fixed Price Swap | ||||||||||||||
April — December 2011 | Oil | Collar | ||||||||||||||
2012 | Oil | Floor | ||||||||||||||
2012 | Oil | Fixed Price Swap | ||||||||||||||
2012 | Oil | Collar | ||||||||||||||
2013 | Oil | Fixed Price Swap | ||||||||||||||
2013 | Oil | Collar |
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Hedged | ||||||||||||||||
Term | Commodity | Structure | MMBtu/d | Floor Price | Cap Price | |||||||||||
April — December 2011 | Natural Gas | Floor | ||||||||||||||
April — December 2011 | Natural Gas | Fixed Price Swap | ||||||||||||||
2012 | Natural Gas | Floor | ||||||||||||||
2012 | Natural Gas | Fixed Price Swap | ||||||||||||||
2013 | Natural Gas | Floor | ||||||||||||||
2013 | Natural Gas | Fixed Price Swap |
Acres | ||||||||
Gross | Net | |||||||
Permian Basin | 278,612 | 30,350 | ||||||
East Texas/North Louisiana | 15,440 | 4,113 | ||||||
Total | 294,052 | 34,463 | ||||||
Oil | Natural Gas | |||||||||||||||
Gross Wells(1) | Net Wells | Gross Wells(1) | Net Wells | |||||||||||||
Permian Basin | 4,161 | 753.5 | 130 | 23.5 | ||||||||||||
East Texas/North Louisiana | — | — | 385 | 100.7 | ||||||||||||
Total | 4,161 | 753.5 | 515 | 124.2 | ||||||||||||
(1) | Enduro Sponsor’s total wells include 34 operated wells and 4,642 non-operated wells. At December 31, 2010, 64 of Enduro Sponsor’s wells had multiple completions. |
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Year Ended December 31, | ||||||||||||||||||||||||
2010 | 2009 | 2008 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Development Wells: | ||||||||||||||||||||||||
Productive | 53 | 9.8 | 42 | 7.0 | 145 | 31.9 | ||||||||||||||||||
Dry holes | — | — | — | — | — | — | ||||||||||||||||||
53 | 9.8 | 42 | 7.0 | 145 | 31.9 | |||||||||||||||||||
Exploratory Wells: | ||||||||||||||||||||||||
Productive | 13 | 4.7 | 23 | 7.6 | 22 | 7.3 | ||||||||||||||||||
Dry holes | — | — | 3 | 0.6 | — | — | ||||||||||||||||||
13 | 4.7 | 26 | 8.2 | 22 | 7.3 | |||||||||||||||||||
Total: | ||||||||||||||||||||||||
Productive | 66 | 14.5 | 65 | 14.6 | 167 | 39.2 | ||||||||||||||||||
Dry holes | — | — | 3 | 0.6 | — | — | ||||||||||||||||||
Total | 66 | 14.5 | 68 | 15.2 | 167 | 39.2 | ||||||||||||||||||
Proved Reserves(1) | ||||||||||||||||||||||||
% of | ||||||||||||||||||||||||
Natural | % of | Total | ||||||||||||||||||||||
Oil | Gas | Total | Total | PV-10 | PV-10 | |||||||||||||||||||
Operating Area | (MBbls) | (MMcf) | (MBoe) | Reserves | Value(2) | Value | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Permian Basin | ||||||||||||||||||||||||
North Monument | ||||||||||||||||||||||||
Grayburg Unit | 2,028 | 1,471 | 2,273 | 15 | % | $ | 42,989 | 15 | % | |||||||||||||||
North Central Levelland Unit | 2,330 | 265 | 2,374 | 14 | % | $ | 39,208 | 14 | % | |||||||||||||||
North Cowden Unit | 2,403 | 993 | 2,569 | 16 | % | $ | 32,563 | 12 | % | |||||||||||||||
Yates Field Unit | 633 | — | 633 | 4 | % | $ | 18,052 | 6 | % | |||||||||||||||
Other | 5,347 | 18,752 | 8,472 | 51 | % | $ | 147,163 | 53 | % | |||||||||||||||
Permian Basin Total | 12,741 | 21,481 | 16,321 | 100 | % | $ | 279,975 | 100 | % | |||||||||||||||
East Texas/North Louisiana | ||||||||||||||||||||||||
Elm Grove Field | 2 | 55,442 | 9,238 | 86 | % | $ | 54,591 | 79 | % | |||||||||||||||
Kingston Field | — | 6,570 | 1,100 | 10 | % | $ | 10,027 | 14 | % | |||||||||||||||
Stockman Field | 23 | 2,294 | 405 | 4 | % | $ | 4,939 | 7 | % | |||||||||||||||
East Texas/North Louisiana | ||||||||||||||||||||||||
Total | 25 | 64,306 | 10,743 | 100 | % | $ | 69,557 | 100 | % | |||||||||||||||
Total | 12,766 | 85,787 | 27,064 | 100 | % | $ | 349,532 | 100 | % | |||||||||||||||
(1) | In accordance with the rules and regulations promulgated by the SEC, the proved reserves presented above were determined using the twelve month unweighted arithmetic average of the |
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first-day-of-the-month price for the period from January 1, 2010 through December 1, 2010, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $79.43 per Bbl and a price for natural gas of $4.37 per MMBtu. | ||
(2) | PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10%, calculated without deducting future income taxes and future abandonment costs. Standardized measure of discounted future net cash flows is calculated the same asPV-10 except that it deducts future income taxes and future abandonment costs. Because the trust bears no federal tax expense and taxable income is passed through to the unitholders of the trust, no provision for federal or state income taxes is included in the summary reserve reports.PV-10 may not be considered a GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. The pre-taxPV-10 value and the standardized measure of discounted future net cash flows do not purport to present the fair value of the oil and natural gas reserves attributable to Underlying Properties. |
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• | Our largest field in the Permian Basin region is the Apache operated North Monument Grayburg Unit discovered in 1929. This unit produces 325 Boe per day net to Enduro Sponsor’s interest from the Grayburg and San Andres formations of which 90% is oil. Proved reserves attributable to the Underlying Properties in the North Monument Grayburg Unit are 2.4 MMBoe as of December 31, 2010. | |
• | Our second largest field in the Permian Basin region is the Apache operated North Central Levelland Unit discovered in 1937. This unit produces from the San Andres formation at a depth of approximately 4,900 feet. The North Central Levelland Unit is a waterflood property and produces 365 Boe per day net to Enduro Sponsor’s interest of which 98% is oil. Proved reserves attributable to the Underlying Properties in the North Central Levelland Unit are 2.4 MMBoe as of December 31, 2010. | |
• | Our third largest field in the Permian Basin region is the North Cowden Unit discovered in 1930. The North Cowden Unit is undergoing both waterflood and CO2 recovery processes. The field produces 490 Boe per day net to Enduro Sponsor’s interest of which 94% is oil. This production is produced from the Grayburg formation at a depth of 4,500 feet. Proved reserves attributable to the Underlying Properties in the North Cowden field are 2.6 MMBoe as of December 31, 2010. The operator of the North Cowden field is Occidental, the largest oil and gas operator in the Permian Basin. | |
• | Our fourth largest field in the Permian Basin region is the Yates Field discovered in 1926. Kinder Morgan is the operator of the field and is producing oil through the implementation of both waterflood and CO2 processes. The Yates Field produced 165 Boe per day net to Enduro Sponsor’s interest of which 100% is oil. Proved reserves attributable to the Underlying Properties in the Yates Field are 630 MBoe as of December 31, 2010. |
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Original | ||||||||||||||||||||||||
Oil in | Cumulative | |||||||||||||||||||||||
Recovery | Working | Net Revenue | Place | Production | PV-10 | |||||||||||||||||||
Unit Name | Operator | Method | Interest (%) | Interest (%) | (MMBO)(1) | (MMBO) | (Millions) | |||||||||||||||||
North Monument Grayburg Unit | Apache | Waterflood | 11.2 | 9.9 | 580 | (2) | 152 | $ | 43 | |||||||||||||||
North Central Levelland Unit | Apache | Waterflood | 30.9 | 23.3 | 142 | (3) | 56 | $ | 39 | |||||||||||||||
North Cowden Unit | Occidental | Waterflood/CO2 | 8.5 | 7.6 | 1,266 | (4) | 270 | $ | 33 | |||||||||||||||
Yates Field Unit | Kinder Morgan | Waterflood/CO2 | 0.8 | 0.7 | 4,000 | (5) | 1,235 | $ | 18 | |||||||||||||||
South Foster Unit | Occidental | Waterflood | 12.7 | 11.1 | 163 | (6) | 45 | $ | 10 | |||||||||||||||
Eunice Monument South Unit A | XTO | Waterflood | 9.4 | 8.1 | 672 | (7) | 110 | $ | 7 | |||||||||||||||
Jo-Mill Unit | Chevron | Waterflood | 1.2 | 1.1 | 326 | (8) | 76 | $ | 4 | |||||||||||||||
West Spraberry Unit | Chevron | Waterflood | 22.7 | 19.7 | 60 | (9) | 14 | $ | 4 | |||||||||||||||
Spraberry Driver Unit | Pioneer | Waterflood | 1.0 | 0.8 | 600 | (10) | 88 | $ | 3 | |||||||||||||||
Eunice Monument South Unit B | XTO | Waterflood | 14.1 | 11.7 | 136 | (11) | 22 | $ | 3 | |||||||||||||||
Corrigan Cowden Unit | Occidental | Waterflood | 12.2 | 10.7 | 44 | (12) | 18 | $ | 2 |
(1) | Original oil in place is not an indication of the quantity of oil that is likely to be produced, but rather an indication of the estimated size of a reservoir. | |
(2) | New Mexico Oil Conservation Division Case No: 10253 Navigational Message Generation Unit Application Hearing dated April 4, 1991 filed by Amerada Hess Corporation as operator. | |
(3) | Texas Railroad Commission April 20, 2001Form H-1 filing by Mobil Producing TX & NM Inc. as operator. | |
(4) | Texas Railroad Commission January 16, 2001Form H-1 filing by Occidental Permian Ltd as operator. | |
(5) | Texas Railroad Commission December 30, 1999Form H-1 filing by Marathon Oil Company as operator. | |
(6) | Texas Railroad Commission September 11, 2001Form H-1 filing by Occidental Permian Ltd as operator. | |
(7) | New Mexico Oil Conservation Division April, 1983 Technical Committee Report for Unitization filing by the Eunice Monument South Unit Working Interest owners. | |
(8) | Texas Railroad Commission September 18, 1968Form H-1 filing by Texaco Inc. as operator. | |
(9) | Texas Railroad Commission April 21, 2000Form H-1 filing by Texaco E&P Inc. as operator. | |
(10) | Texas Railroad Commission February 24, 1993Form H-1 filing by Texaco E&P Inc. as operator. | |
(11) | New Mexico Oil Conservation Division April, 1983 Technical Committee Report for Unitization filing by the Eunice Monument South Unit Working Interest owners. | |
(12) | Texas Railroad Commission June 4, 1990Form H-1 filing by ARCO Oil and Gas Company as operator. |
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• | In the East Texas/North Louisiana region, Enduro Sponsor’s capital budget is expected to be $10 million in 2012. Investments in this region will mainly flow into Haynesville drilling projects in Caddo and De Soto Parishes in Louisiana. Enduro Sponsor’s acreage in the Haynesville Shale area has significant upside potential. Over 90% of the 640 acre sections owned by Enduro Sponsor have only one producing well, which leaves 7 additional |
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locations per section (assuming80-acre spacing) to drive growth in this area for years to come. |
• | In the Permian Basin, Enduro Sponsor’s capital budget is expected to be $2 million in 2012, excluding the North Cowden CO2 projects. Past projects have typically targeted the Wolfcamp, Wolfberry, Cherry Canyon and San Andres zones. | |
• | Enduro Sponsor also anticipates investing $1 million in the North Cowden CO2 project in the Permian Basin in 2012. Also, Enduro Sponsor owns an interest in other prospective CO2 units in the Permian Basin, with neighboring units being successfully flooded or expanded into units owned by Enduro Sponsor. The operators of these producing units have extensive experience in implementing CO2 floods, which increase production. |
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80% of the | ||||||||||||
Underlying | Underlying | Net Profit | ||||||||||
Properties(1) | Properties(2) | Interests | ||||||||||
(Dollars in thousands) | ||||||||||||
Proved Reserves | ||||||||||||
Oil (MBbls)(3) | 12,766 | 10,213 | 5,642 | |||||||||
Natural Gas (MMcf) | 85,787 | 68,630 | 43,058 | |||||||||
Oil Equivalents (Mboe)(4) | 27,064 | 21,651 | 12,818 | |||||||||
Future Net Revenue | $ | 1,344,718 | $ | 1,075,774 | $ | 616,091 | ||||||
Future Production Cost | $ | 578,014 | $ | 462,411 | $ | 48,895 | (6) | |||||
Future Development Cost | $ | 57,674 | $ | 46,139 | $ | — | ||||||
Future Net Income | $ | 709,030 | $ | 567,196 | $ | 567,196 | ||||||
Present Value at 10% Discount Rate(5) | $ | 349,532 | $ | 279,688 | $ | 279,688 | ||||||
Standardized Measure of Discounted Future Net Cash Flows | $ | 349,532 | $ | 279,688 | $ | 279,688 |
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(1) | Reserve volumes and estimated future net revenues for Underlying Properties reflect volumes and revenues attributable to Enduro Sponsor’s net interests in the properties comprising the Underlying Properties. | |
(2) | Reflects 80% of the proved reserves and future net revenues, production and development costs, net income and present value attributable to the Underlying Properties expected to be produced based on the reserve report. | |
(3) | Proved reserves for oil include volumes for NGLs (MBbls) of 183 MBbls, 146 MBbls and 101 MBbls attributable to the Underlying Properties, 80% of the Underlying Properties and the Net Profits Interest, respectively. | |
(4) | The proved reserves for 80% of the Underlying Properties and the Net Profits Interest of 21,651 Mboe and 12,818 Mboe differ by 8,833 Mboe. Proceeds from the sale of the 8,833 Mboe will be used to cover 80% of the future production and development costs attributable to the Underlying Properties for the benefit of the trust. | |
(5) | The present values of the future net revenues for the Underlying Properties and the Net Profits Interest were determined using a discount rate of 10% per annum. As of December 31, 2010, Enduro Sponsor was structured as a limited liability company. Accordingly, no provision for federal or state income taxes has been provided because taxable income was passed through to the members of Enduro Sponsor. | |
(6) | Future production costs for the Net Profits Interest consist solely of severance taxes and ad valorem taxes attributable to the trust. |
Oil | ||||||||||||
Oil | Natural Gas | Equivalents | ||||||||||
(MBbls) | (MMcf) | (MBoe) | ||||||||||
Proved Reserves: | ||||||||||||
Balance, January 1, 2008 | 16,177 | 67,009 | 27,345 | |||||||||
Revisions, extensions, discoveries and additions | (4,374 | ) | 23,731 | (419 | ) | |||||||
Production | (1,084 | ) | (8,868 | ) | (2,562 | ) | ||||||
Balance, December 31, 2008 | 10,719 | 81,872 | 24,364 | |||||||||
Revisions, extensions, discoveries and additions | 2,466 | 2,705 | 2,917 | |||||||||
Production | (1,016 | ) | (8,455 | ) | (2,425 | ) | ||||||
Balance, December 31, 2009 | 12,169 | 76,122 | 24,856 | |||||||||
Revisions, extensions, discoveries and additions | 1,536 | 16,836 | 4,342 | |||||||||
Production | (939 | ) | (7,171 | ) | (2,134 | ) | ||||||
Balance, December 31, 2010 | 12,766 | 85,787 | 27,064 | |||||||||
Proved Developed Reserves: | ||||||||||||
Balance, December 31, 2008 | 10,674 | 67,164 | 21,868 | |||||||||
Balance, December 31, 2009 | 12,124 | 57,010 | 21,626 | |||||||||
Balance, December 31, 2010 | 12,387 | 51,293 | 20,935 | |||||||||
Proved Undeveloped Reserves: | ||||||||||||
Balance, December 31, 2008 | 45 | 14,708 | 2,496 | |||||||||
Balance, December 31, 2009 | 45 | 19,112 | 3,230 | |||||||||
Balance, December 31, 2010 | 379 | 34,494 | 6,129 |
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• | royalties and other burdens, express and implied, under oil and natural gas leases and other arrangements; | |
• | overriding royalties, production payments and similar interests and other burdens created by Enduro Sponsor’s predecessors in title; | |
• | a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the Underlying Properties or their title; | |
• | liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings; | |
• | pooling, unitization and communitization agreements, declarations and orders; | |
• | easements, restrictions,rights-of-way and other matters that commonly affect property; | |
• | conventional rights of reassignment that obligate Enduro Sponsor to reassign all or part of a property to a third party if Enduro Sponsor intends to release or abandon such property; | |
• | preferential rights to purchase or similar agreements and required third party consents to assignments or similar agreements; | |
• | obligations or duties affecting the Underlying Properties to any municipality or public authority with respect to any franchise, grant, license or permit, and all applicable laws, rules, regulations and orders of any governmental authority; and | |
• | rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties and also the interests held therein, including Enduro Sponsor’s interests and the Net Profits Interest. |
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• | obtain permits to conduct regulated activities; | |
• | limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; |
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• | restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling and production activities; | |
• | initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells; | |
• | apply specific health and safety criteria addressing worker protection; and | |
• | impose substantial liabilities on Enduro Sponsor for pollution resulting from Enduro Sponsor’s operations. |
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• | all costs for (i) drilling, development, production and abandonment operations, (ii) all direct labor and other services necessary for drilling, operating, producing and maintaining the Underlying Properties and workovers of any wells located on the Underlying Properties, (iii) treatment, dehydration, compression, separation and transportation, (iv) all materials purchased for use on, or in connection with, any of the Underlying Properties and (v) any other operations with respect to the exploration, development or operation of hydrocarbons from the Underlying Properties; | |
• | all losses, costs, expenses, liabilities and damages with respect to the operation or maintenance of the Underlying Properties for (i) defending, prosecuting, handling, investigating or settling litigation, administrative proceedings, claims, damages, judgments, fines, penalties and other liabilities, (ii) the payment of certain judgments, penalties and other liabilities, (iii) the payment or restitution of any proceeds of hydrocarbons from the Underlying Properties, (iv) complying with applicable local, state and federal statutes, ordinances, rules and regulations, (v) tax or royalty audits and (vi) any other loss, cost, expense, liability or damage with respect to the Underlying Properties not paid or reimbursed under insurance; |
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• | all taxes, charges and assessments (excluding federal and state income, transfer, mortgage, inheritance, estate, franchise and like taxes) with respect to the ownership of, or production of hydrocarbons from, the Underlying Properties; | |
• | all insurance premiums attributable to the ownership or operation of the Underlying Properties for insurance actually carried with respect to the Underlying Properties, or any equipment located on any of the Underlying Properties, or incident to the operation or maintenance of the Underlying Properties; | |
• | all amounts and other consideration for (i) rent and the use of or damage to the surface, (ii) delay rentals, shut-in well payments and similar payments and (iii) fees for renewal, extension, modification, amendment, replacement or supplementation of the leases included in the Underlying Properties; | |
• | all amounts charged by the relevant operator as overhead, administrative or indirect charges specified in the applicable operating agreements or other arrangements covering the Underlying Properties or Enduro Sponsor’s operations with respect thereto; | |
• | to the extent that Enduro Sponsor is the operator of certain of the Underlying Properties and there is no operating agreement covering such portion of the Underlying Properties, those overhead, administrative or indirect charges that are allocated by Enduro Sponsor to such portion of the Underlying Properties; | |
• | if, as a result of the occurrence of the bankruptcy or insolvency or similar occurrence of any purchaser of hydrocarbons produced from the Underlying Properties, any amounts previously credited to the determination of the net profits are reclaimed from Enduro Sponsor, then the amounts reclaimed; | |
• | all costs and expenses for recording the conveyance and, at the applicable times, terminationsand/or releases thereof; | |
• | all administrative hedge costs (in respect of hedges existing prior to the date of the conveyance, as further described in the conveyance); | |
• | all hedge settlement costs paid (in respect of hedges existing prior to the date of the conveyance, as further described in the conveyance); | |
• | amounts previously included in gross profits but subsequently paid as a refund, interest or penalty; and | |
• | at the option of Enduro Sponsor (or any subsequent owner of the Underlying Properties), amounts reserved for approved development expenditure projects, including well drilling, recompletion and workover costs, which amounts will at no time exceed $2.0 million in the aggregate, and will be subject to the limitations described below (provided that such costs shall not be debited from gross profits when actually incurred). |
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• | any proceeds that are withheld for any reason (other than at the request of Enduro Sponsor) are not considered received until such time that the proceeds are actually collected; | |
• | amounts received and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and | |
• | amounts received and not deposited with an escrow agent will be considered to have been received. |
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• | increase the power of the trustee or the Delaware trustee to engage in business or investment activities; or | |
• | alter the rights of the trust unitholders as among themselves. |
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• | collecting cash attributable to the Net Profits Interest; | |
• | paying expenses, charges and obligations of the trust from the trust’s assets; | |
• | distributing distributable cash to the trust unitholders; | |
• | causing to be prepared and distributed a tax information report for each trust unitholder and to prepare and file tax returns on behalf of the trust; | |
• | causing to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934 and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading; | |
• | causing to be prepared and filed a reserve report by or for the trust by independent reserve engineers as of December 31 of each year in accordance with criteria established by the SEC; | |
• | establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002; | |
• | enforcing the rights under certain agreements entered into in connection with this offering; and | |
• | taking any action it deems necessary and advisable to best achieve the purposes of the trust. |
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• | interest bearing obligations of the United States government; | |
• | money market funds that invest only in United States government securities; | |
• | repurchase agreements secured by interest-bearing obligations of the United States government; or | |
• | bank certificates of deposit. |
• | the sale does not involve a material part of the trust’s assets; or | |
• | the sale constitutes a material part of the trust’s assets, subject to the approval of the holders of at least 75% of the outstanding trust units. |
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• | charge for its services as trustee; | |
• | retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the trustee to the extent permitted by law); | |
• | lend funds at commercial rates to the trust to pay the trust’s expenses; and | |
• | seek reimbursement from the trust for itsout-of-pocket expenses. |
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• | the trust, upon the approval of the holders of at least 75% of the outstanding trust units, sells the Net Profits Interest; | |
• | the annual cash available for distribution to the trust is less than $2 million for each of any two consecutive years; | |
• | the holders of at least 75% of the outstanding trust units vote in favor of dissolution; or | |
• | the trust is judicially dissolved. |
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• | dissolve the trust; | |
• | amend the trust agreement (except with respect to certain matters that do not adversely affect the rights of trust unitholders in any material respect); or | |
• | approve the sale of all or any material part of the assets of the trust (including the sale of the Net Profits Interest). |
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Trust Units | Common Stock | |||
Voting | The trust agreement provides voting rights to trust unitholders to remove and replace the trustee and to approve or disapprove amendments to the trust agreement and certain major trust transactions. | Unless otherwise provided in the certificate of incorporation, the corporate statutes provide voting rights to stockholders to elect directors and to approve or disapprove amendments to the certificate of incorporation and certain major corporate transactions. | ||
Income Tax | The trust is not subject to income tax; trust unitholders are subject to income tax on their pro rata share of trust income, gain, loss and deduction. | Corporations are taxed on their income and their stockholders are taxed on dividends. | ||
Distributions | Substantially all of the cash receipts of the trust is required to be distributed to trust unitholders. | Unless otherwise provided in the certificate of incorporation, stockholders are entitled to receive dividends solely at the discretion of the board of directors. | ||
Business and Assets | The business of the trust is limited to specific assets with a finite economic life. | Unless otherwise provided in the certificate of incorporation, a corporation conducts an active business for an unlimited term and can reinvest its earnings and raise additional capital to expand. | ||
Fiduciary Duties | The trustee shall not be liable to the trust unitholders for any of its acts or omissions absent its own fraud, gross negligence or willful misconduct. | Officers and directors have a fiduciary duty of loyalty to the corporation and its stockholders and a duty to exercise due care in the management and administration of a corporation’s affairs. |
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• | 1.0% of the total number of the securities outstanding, or | |
• | the average weekly reported trading volume of the trust units for the four calendar weeks prior to the sale. |
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• | subject to the restrictions described above under“— Lock-up Agreements” and under “Underwriting —Lock-up Agreements,” to use its reasonable best efforts to file a registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable trust units; | |
• | to use its commercially reasonable efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and | |
• | to use its commercially reasonable efforts to maintain the effectiveness of the registration statement under the Securities Act for 90 days (or for three years if a shelf registration statement is requested) after the effectiveness thereof or until the trust units covered by the registration statement have been sold pursuant to such registration statement or until all registrable trust units: |
• | have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities;” | |
• | have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the trust units; or | |
• | become eligible for resale pursuant to Rule 144 (or any similar rule then in effect under the Securities Act). |
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• | banks, insurance companies or other financial institutions; | |
• | trust unitholders subject to the alternative minimum tax; | |
• | tax-exempt organizations; | |
• | dealers in securities or commodities; | |
• | regulated investment companies; | |
• | real estate investment trusts; | |
• | traders in securities that elect to use amark-to-market method of accounting for their securities holdings; | |
• | non-U.S. trust unitholders (as defined below) that are “controlled foreign corporations” or “passive foreign investment companies”; | |
• | persons that are S-corporations, partnerships or other pass-through entities; | |
• | persons that own their interest in the trust units through S-corporations, partnerships or other pass-through entities; | |
• | persons that at any time own more than 5% of the aggregate fair market value of the trust units; | |
• | expatriates and certain former citizens or long-term residents of the United States; | |
• | U.S. trust unitholders (as defined below) whose functional currency is not the U.S. dollar; | |
• | persons who hold the trust units as a position in a hedging transaction, “straddle,” “conversion transaction” or other risk reduction transaction; or | |
• | persons deemed to sell the trust units under the constructive sale provisions of the Code. |
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• | an individual who is a citizen of the United States or who is a resident of the United States for U.S. federal income tax purposes, | |
• | a corporation, or an entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States, a state thereof or the District of Columbia, | |
• | an estate the income of which is subject to U.S. federal income taxation regardless of its source, or | |
• | a trust if it is subject to the primary supervision of a U.S. court and the control of one or more United States persons (as defined for U.S. federal income tax purposes) or that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a United States person. |
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• | the gain is otherwise effectively connected with business conducted by thenon-U.S. trust unitholder in the United States (and, in the case of an applicable tax treaty, is attributable to a permanent establishment or fixed base maintained in the United States by thenon-U.S. trust unitholder); | |
• | thenon-U.S. trust unitholder is an individual who is present in the United States for at least 183 days in the year of the sale or other taxable disposition; or | |
• | thenon-U.S. trust unitholder owns currently, or owned at certain earlier times, directly, or by applying certain attribution rules, more than 5% of the trust units. |
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• | whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA; | |
• | whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and | |
• | whether the investment is in accordance with the documents and instruments governing the plan as required by Section 404(a)(1)(D) of ERISA. |
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Ownership of Trust | Number of | Ownership of Trust Units After | ||||||||||||||||||
Units Before Offering | Trust Units | Offering | ||||||||||||||||||
Selling Trust Unitholder | Number | Percentage | Being Offered | Number | Percentage | |||||||||||||||
Enduro Sponsor | 100.0 | % | (1) | % |
(1) | Includes trust units subject to purchase by the underwriters pursuant to their 30-day option to purchase additional units. |
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Number of | ||||
Underwriters | Trust Units | |||
Barclays Capital Inc. | ||||
Total | ||||
• | the obligation to purchase all of the trust units offered hereby (other than those trust units covered by their option to purchase additional trust units as described below), if any of the trust units are purchased; | |
• | the representations and warranties made by the trust and Enduro Sponsor to the underwriters are true; | |
• | there is no material change in the business of the trust or Enduro Sponsor or the financial markets; and | |
• | the trust and Enduro Sponsor deliver customary closing documents to the underwriters. |
No Exercise | Full Exercise | |||
Per trust unit | ||||
Total |
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• | during the last 17 days of the180-day restricted period the trust issues an earnings release or material news or a material event relating to the trust occurs; or | |
• | prior to the expiration of the180-day restricted period, the trust announces that it will release earnings results during the16-day period beginning on the last day of the180-day period, |
• | estimates of distributions to trust unitholders; | |
• | overall quality of the oil and natural gas properties attributable to the Underlying Properties; |
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• | the history and prospects for the energy industry; | |
• | our financial information; | |
• | the prevailing securities markets at the time of this offering; and | |
• | the recent market prices of, and the demand for, publicly traded units of royalty trusts. |
• | Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum. | |
• | A short position involves a sale by the underwriters of trust units in excess of the number of trust units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of trust units involved in the sales made by the underwriters in excess of the number of trust units they are obligated to purchase is not greater than the number of trust units that they may purchase by exercising their option to purchase additional trust units. In a naked short position, the number of trust units involved is greater than the number of trust units in their option to purchase additional trust units. The underwriters may close out any short position by either exercising their option to purchase additional trust unitsand/or purchasing trust units in the open market. In determining the source of trust units to close out the short position, the underwriters will consider, among other things, the price of trust units available for purchase in the open market as compared to the price at which they may purchase trust units through their option to purchase additional trust units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the trust units in the open market after pricing that could adversely affect investors who purchase in the offering. |
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• | Syndicate covering transactions involve purchases of the trust units in the open market after the distribution has been completed in order to cover syndicate short positions. | |
• | Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the trust units originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions. |
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PREDECESSOR UNDERLYING PROPERTIES: | ||||
F-2 | ||||
F-3 | ||||
F-4 | ||||
SAMSON PERMIAN BASIN ASSETS: | ||||
F-9 | ||||
F-10 | ||||
F-11 | ||||
CONOCOPHILLIPS PERMIAN BASIN ASSETS: | ||||
F-15 | ||||
F-16 | ||||
F-17 | ||||
UNAUDITED PRO FORMA COMBINED UNDERLYING PROPERTIES: | ||||
F-22 | ||||
F-23 | ||||
ENDURO ROYALTY TRUST: | ||||
F-26 | ||||
F-27 | ||||
F-28 | ||||
F-30 | ||||
F-31 | ||||
F-32 | ||||
F-33 |
page ENDURO F-1.
F-1
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F-2
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Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Revenues: | ||||||||||||
Oil | $ | 1,345 | $ | 1,685 | $ | 3,057 | ||||||
Natural gas | 21,112 | 22,519 | 54,485 | |||||||||
Total revenues | 22,457 | 24,204 | 57,542 | |||||||||
Direct operating expenses: | ||||||||||||
Lease operating | 4,484 | 5,365 | 4,695 | |||||||||
Gathering and processing | 1,522 | 1,474 | 2,471 | |||||||||
Production and other taxes | 1,373 | 1,965 | 2,259 | |||||||||
Total direct operating expenses | 7,379 | 8,804 | 9,425 | |||||||||
Excess of revenues over direct operating expenses | $ | 15,078 | $ | 15,400 | $ | 48,117 | ||||||
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1. | Basis of Presentation |
2. | Significant Accounting Policies |
(a) | Use of Estimates |
(b) | Revenue Recognition |
(c) | Direct Operating Expenses |
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3. | Contingencies |
4. | Cash Flow Information |
5. | Subsequent Events |
6. | Supplemental Oil and Natural Gas Disclosures (Unaudited) |
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Oil | Natural Gas | Total | ||||||||||
(MBbls) | (MMcf) | (MBOE) | ||||||||||
January 1, 2008 | 114 | 38,126 | 6,468 | |||||||||
Revisions of previous estimates | 70 | 26,511 | 4,489 | |||||||||
Production | (33 | ) | (6,449 | ) | (1,108 | ) | ||||||
December 31, 2008 | 151 | 58,188 | 9,849 | |||||||||
Revisions of previous estimates | (16 | ) | 2,490 | 399 | ||||||||
Production | (31 | ) | (6,069 | ) | (1,043 | ) | ||||||
December 31, 2009 | 104 | 54,609 | 9,205 | |||||||||
Revisions of previous estimates | (61 | ) | 14,673 | 2,385 | ||||||||
Production | (18 | ) | (4,976 | ) | (847 | ) | ||||||
December 31, 2010 | 25 | 64,306 | 10,743 | |||||||||
Proved developed reserves as of: | ||||||||||||
December 31, 2008 | 106 | 43,480 | 7,353 | |||||||||
December 31, 2009 | 59 | 35,497 | 5,975 | |||||||||
December 31, 2010 | 25 | 31,105 | 5,209 | |||||||||
Proved undeveloped reserves as of: | ||||||||||||
December 31, 2008 | 45 | 14,708 | 2,496 | |||||||||
December 31, 2009 | 45 | 19,112 | 3,230 | |||||||||
December 31, 2010 | — | 33,201 | 5,534 |
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December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Oil (per Bbl) | $ | 79.43 | $ | 61.18 | $ | 44.60 | ||||||
Natural gas (per Mcf) | $ | 4.37 | $ | 3.83 | $ | 5.62 |
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Future cash inflows | $ | 263,643 | $ | 200,931 | $ | 311,799 | ||||||
Future production costs | (62,667 | ) | (75,873 | ) | (94,767 | ) | ||||||
Future development costs | (51,674 | ) | (37,531 | ) | (39,163 | ) | ||||||
Future net cash flows | 149,302 | 87,527 | 177,869 | |||||||||
10% discount for estimating timing of cash flows | (79,745 | ) | (41,852 | ) | (81,788 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 69,557 | $ | 45,675 | $ | 96,081 | ||||||
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Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Sales of oil and natural gas produced, net of production costs | $ | (15,078 | ) | $ | (15,400 | ) | $ | (48,117 | ) | |||
Net changes in prices and production costs | 24,282 | (44,320 | ) | (27,554 | ) | |||||||
Revisions of previous quantity estimates | 23,286 | 2,930 | 53,925 | |||||||||
Development costs incurred during the period | 7,779 | 16,926 | 26,841 | |||||||||
Accretion of discount | 4,567 | 9,608 | 9,827 | |||||||||
Change in estimated future development costs | (17,147 | ) | (11,963 | ) | (30,633 | ) | ||||||
Timing and other | (3,807 | ) | (8,187 | ) | 13,527 | |||||||
Net change in standardized measure | 23,882 | (50,406 | ) | (2,184 | ) | |||||||
Standardized measure, beginning of year | 45,675 | 96,081 | 98,265 | |||||||||
Standardized measure, end of year | $ | 69,557 | $ | 45,675 | $ | 96,081 | ||||||
F-8
Table of Contents
F-9
Table of Contents
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Revenues: | ||||||||||||
Oil | $ | 16,626 | $ | 13,174 | $ | 23,730 | ||||||
Natural gas | 5,650 | 4,733 | 9,770 | |||||||||
Total revenues | 22,276 | 17,907 | 33,500 | |||||||||
Direct operating expenses: | ||||||||||||
Lease operating | 3,438 | 3,783 | 4,327 | |||||||||
Gathering and processing | 212 | 177 | 178 | |||||||||
Production and other taxes | 1,702 | 1,558 | 2,549 | |||||||||
Total direct operating expenses | 5,352 | 5,518 | 7,054 | |||||||||
Excess of revenues over direct operating expenses | $ | 16,924 | $ | 12,389 | $ | 26,446 | ||||||
F-10
Table of Contents
1. | Basis of Presentation |
2. | Significant Accounting Policies |
(a) | Use of Estimates |
(b) | Revenue Recognition |
(c) | Direct Operating Expenses |
F-11
Table of Contents
3. | Contingencies |
4. | Cash Flow Information (Unaudited) |
5. | Subsequent Events |
6. | Supplemental Oil and Natural Gas Disclosures (Unaudited) |
F-12
Table of Contents
Oil | Natural Gas | Total | ||||||||||
(MBbls) | (MMcf) | (MBOE) | ||||||||||
January 1, 2008 | 3,835 | 14,399 | 6,235 | |||||||||
Revisions of previous estimates | (351 | ) | (517 | ) | (437 | ) | ||||||
Production | (246 | ) | (1,164 | ) | (440 | ) | ||||||
December 31, 2008 | 3,238 | 12,718 | 5,358 | |||||||||
Revisions of previous estimates | 139 | (150 | ) | 114 | ||||||||
Production | (233 | ) | (1,110 | ) | (418 | ) | ||||||
December 31, 2009 | 3,144 | 11,458 | 5,054 | |||||||||
Revisions of previous estimates | 120 | 379 | 183 | |||||||||
Production | (216 | ) | (1,056 | ) | (392 | ) | ||||||
December 31, 2010 | 3,048 | 10,781 | 4,845 | |||||||||
Proved developed reserves as of: | ||||||||||||
December 31, 2008 | 3,238 | 12,718 | 5,358 | |||||||||
December 31, 2009 | 3,144 | 11,458 | 5,054 | |||||||||
December 31, 2010 | 3,048 | 10,781 | 4,845 |
December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Oil (per Bbl) | $ | 79.43 | $ | 61.18 | $ | 44.60 | ||||||
Natural gas (per Mcf) | $ | 4.37 | $ | 3.83 | $ | 5.62 |
F-13
Table of Contents
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Future cash inflows | $ | 292,253 | $ | 239,673 | $ | 224,628 | ||||||
Future production costs | (107,372 | ) | (96,804 | ) | (92,314 | ) | ||||||
Future net cash flows | 184,881 | 142,869 | 132,314 | |||||||||
10% discount for estimating timing of cash flows | (99,927 | ) | (73,986 | ) | (64,551 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 84,954 | $ | 68,883 | $ | 67,763 | ||||||
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Sales of oil and natural gas produced, net of production costs | $ | (16,924 | ) | $ | (12,389 | ) | $ | (26,446 | ) | |||
Net changes in prices and production costs | 25,022 | 10,094 | (83,425 | ) | ||||||||
Revisions of previous quantity estimates | 3,361 | 1,650 | (4,972 | ) | ||||||||
Accretion of discount | 6,888 | 6,776 | 16,207 | |||||||||
Timing and other | (2,276 | ) | (5,011 | ) | 4,330 | |||||||
Net change in standardized measure | 16,071 | 1,120 | (94,306 | ) | ||||||||
Standardized measure, beginning of year | 68,883 | 67,763 | 162,069 | |||||||||
Standardized measure, end of year | $ | 84,954 | $ | 68,883 | $ | 67,763 | ||||||
F-14
Table of Contents
F-15
Table of Contents
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Revenues: | ||||||||||||
Oil | $ | 52,062 | $ | 40,450 | $ | 80,014 | ||||||
Natural gas | 7,025 | 5,801 | 11,746 | |||||||||
Total revenues | 59,087 | 46,251 | 91,760 | |||||||||
Direct operating expenses: | ||||||||||||
Lease operating | 16,657 | 16,674 | 20,309 | |||||||||
Gathering and processing | 243 | 234 | 386 | |||||||||
Production and other taxes | 4,994 | 3,989 | 6,409 | |||||||||
Total direct operating expenses | 21,894 | 20,897 | 27,104 | |||||||||
Excess of revenues over direct operating expenses | $ | 37,193 | $ | 25,354 | $ | 64,656 | ||||||
F-16
Table of Contents
1. | Basis of Presentation |
2. | Significant Accounting Policies |
(a) | Use of Estimates |
(b) | Revenue Recognition |
(c) | Direct Operating Expenses |
F-17
Table of Contents
3. | Contingencies |
4. | Cash Flow Information (Unaudited) |
5. | Subsequent Events |
6. | Supplemental Oil and Natural Gas Disclosures (Unaudited) |
F-18
Table of Contents
Oil | Natural Gas | Total | ||||||||||
(MBbls) | (MMcf) | (MBOE) | ||||||||||
January 1, 2008 | 12,228 | 14,484 | 14,642 | |||||||||
Revisions of previous estimates | (4,093 | ) | (2,263 | ) | (4,470 | ) | ||||||
Production | (805 | ) | (1,255 | ) | (1,014 | ) | ||||||
December 31, 2008 | 7,330 | 10,966 | 9,158 | |||||||||
Revisions of previous estimates | 2,343 | 365 | 2,404 | |||||||||
Production | (752 | ) | (1,276 | ) | (965 | ) | ||||||
December 31, 2009 | 8,921 | 10,055 | 10,597 | |||||||||
Revisions of previous estimates | 1,477 | 1,784 | 1,774 | |||||||||
Production | (705 | ) | (1,139 | ) | (895 | ) | ||||||
December 31, 2010 | 9,693 | 10,700 | 11,476 | |||||||||
Proved developed reserves as of: | ||||||||||||
December 31, 2008 | 7,330 | 10,966 | 9,158 | |||||||||
December 31, 2009 | 8,921 | 10,055 | 10,597 | |||||||||
December 31, 2010 | 9,314 | 9,407 | 10,882 | |||||||||
Proved undeveloped reserves as of: | ||||||||||||
December 31, 2008 | — | — | — | |||||||||
December 31, 2009 | — | — | — | |||||||||
December 31, 2010 | 379 | 1,293 | 594 |
F-19
Table of Contents
December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Oil (per Bbl) | $ | 79.43 | $ | 61.18 | $ | 44.60 | ||||||
Natural gas (per Mcf) | $ | 4.37 | $ | 3.83 | $ | 5.62 |
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Future cash inflows | $ | 788,822 | $ | 562,323 | $ | 378,542 | ||||||
Future production costs | (407,974 | ) | (331,913 | ) | (228,540 | ) | ||||||
Future development costs | (6,000 | ) | — | — | ||||||||
Future net cash flows | 374,848 | 230,410 | 150,002 | |||||||||
10% discount for estimating timing of cash flows | (179,827 | ) | (103,004 | ) | (61,428 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 195,021 | $ | 127,406 | $ | 88,574 | ||||||
F-20
Table of Contents
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Extensions and discoveries, net of future development costs | $ | 11,065 | $ | — | $ | — | ||||||
Sales of oil and natural gas produced, net of production costs | (37,193 | ) | (25,354 | ) | (64,656 | ) | ||||||
Net changes in prices and production costs | 69,967 | 31,046 | (206,394 | ) | ||||||||
Revisions of previous quantity estimates | 21,549 | 30,869 | (36,796 | ) | ||||||||
Accretion of discount | 12,741 | 8,857 | 36,168 | |||||||||
Change in estimated future development costs | (5,721 | ) | — | — | ||||||||
Timing and other | (4,793 | ) | (6,586 | ) | (1,427 | ) | ||||||
Net change in standardized measure | 67,615 | 38,832 | (273,105 | ) | ||||||||
Standardized measure, beginning of year | 127,406 | 88,574 | 361,679 | |||||||||
Standardized measure, end of year | $ | 195,021 | $ | 127,406 | $ | 88,574 | ||||||
F-21
Table of Contents
AND DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
F-22
Table of Contents
AND DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
YEAR ENDED DECEMBER 31, 2010
Predecessor | Samson | ConocoPhillips | Total | |||||||||||||||||
Underlying | Permian Basin | Permian Basin | Underlying | |||||||||||||||||
Properties | Assets | Assets | Properties | |||||||||||||||||
Revenues: | ||||||||||||||||||||
Oil | $ | 1,345 | $ | 16,626 | $ | 52,062 | $ | 70,033 | ||||||||||||
Natural gas | 21,112 | 5,650 | 7,025 | 33,787 | ||||||||||||||||
Total revenues | 22,457 | 22,276 | 59,087 | 103,820 | ||||||||||||||||
Direct operating expenses: | ||||||||||||||||||||
Lease operating | 4,484 | 3,438 | 16,657 | 24,579 | ||||||||||||||||
Gathering and processing | 1,522 | 212 | 243 | 1,977 | ||||||||||||||||
Production and other taxes | 1,373 | 1,702 | 4,994 | 8,069 | ||||||||||||||||
Total direct operating expenses | 7,379 | 5,352 | 21,894 | 34,625 | ||||||||||||||||
Excess of revenues over direct operating expenses | $ | 15,078 | $ | 16,924 | $ | 37,193 | $ | 69,195 | ||||||||||||
F-23
Table of Contents
AND DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
YEAR ENDED DECEMBER 31, 2009
Predecessor | Samson | ConocoPhillips | Total | |||||||||||||||||
Underlying | Permian Basin | Permian Basin | Underlying | |||||||||||||||||
Properties | Assets | Assets | Properties | |||||||||||||||||
Revenues: | ||||||||||||||||||||
Oil | $ | 1,685 | $ | 13,174 | $ | 40,450 | $ | 55,309 | ||||||||||||
Natural gas | 22,519 | 4,733 | 5,801 | 33,053 | ||||||||||||||||
Total revenues | 24,204 | 17,907 | 46,251 | 88,362 | ||||||||||||||||
Direct operating expenses: | ||||||||||||||||||||
Lease operating | 5,365 | 3,783 | 16,674 | 25,822 | ||||||||||||||||
Gathering and processing | 1,474 | 177 | 234 | 1,885 | ||||||||||||||||
Production and other taxes | 1,965 | 1,558 | 3,989 | 7,512 | ||||||||||||||||
Total direct operating expenses | 8,804 | 5,518 | 20,897 | 35,219 | ||||||||||||||||
Excess of revenues over direct operating expenses | $ | 15,400 | $ | 12,389 | $ | 25,354 | $ | 53,143 | ||||||||||||
F-24
Table of Contents
AND DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
YEAR ENDED DECEMBER 31, 2008
Predecessor | Samson | ConocoPhillips | Total | |||||||||||||||||
Underlying | Permian Basin | Permian Basin | Underlying | |||||||||||||||||
Properties | Assets | Assets | Properties | |||||||||||||||||
Revenues: | ||||||||||||||||||||
Oil | $ | 3,057 | $ | 23,730 | $ | 80,014 | $ | 106,801 | ||||||||||||
Natural gas | 54,485 | 9,770 | 11,746 | 76,001 | ||||||||||||||||
Total revenues | 57,542 | 33,500 | 91,760 | 182,802 | ||||||||||||||||
Direct operating expenses: | ||||||||||||||||||||
Lease operating | 4,695 | 4,327 | 20,309 | 29,331 | ||||||||||||||||
Gathering and processing | 2,471 | 178 | 386 | 3,035 | ||||||||||||||||
Production and other taxes | 2,259 | 2,549 | 6,409 | 11,217 | ||||||||||||||||
Total direct operating expenses | 9,425 | 7,054 | 27,104 | 43,583 | ||||||||||||||||
Excess of revenues over direct operating expenses | $ | 48,117 | $ | 26,446 | $ | 64,656 | $ | 139,219 | ||||||||||||
F-25
Table of Contents
F-26
Table of Contents
May 12, 2011 | ||||
ASSETS | ||||
Cash | $ | 10 | ||
TRUST CORPUS | ||||
Trust Corpus | $ | 10 | ||
F-27
Table of Contents
1. | Organization of the Trust |
2. | Trust Significant Accounting Policies |
(a) | Basis of Accounting |
F-28
Table of Contents
(b) | Use of Estimates |
3. | Income Taxes |
4. | Distributions to Unitholders |
F-29
Table of Contents
F-30
Table of Contents
May 12, 2011 | ||||||||||||
Historical | Adjustments | Pro Forma | ||||||||||
(in thousands) | ||||||||||||
ASSETS | ||||||||||||
Cash | $ | — | $ | — | $ | — | ||||||
Investment in Net Profits Interest (See Note 5) | — | 700,000 | 700,000 | |||||||||
$ | — | $ | 700,000 | $ | 700,000 | |||||||
TRUST CORPUS | ||||||||||||
Trust Units Issued and Outstanding | $ | — | $ | 700,000 | $ | 700,000 | ||||||
F-31
Table of Contents
Year Ended | ||||
December 31, 2010 | ||||
(in thousands) | ||||
Historical Results | ||||
Income from the Net Profits Interest (See Note 4) | $ | 25,727 | ||
Pro Forma Adjustments | ||||
Less: Trust general and administrative expenses (See Note 5) | 5,068 | |||
Distributable income | $ | 20,659 | ||
Distributable income per unit | $ | |||
F-32
Table of Contents
1. | Basis of Presentation |
2. | Trust Accounting Policies |
F-33
Table of Contents
3. | Income Taxes |
4. | Income from Net Profits Interest |
Pro forma excess of revenues over direct operating expenses of the Underlying Properties | $ | 69,195 | ||
Development costs(a) | (37,036 | ) | ||
�� | ||||
Excess of revenues over direct operating expenses and development costs | 32,159 | |||
Multiplied by Net Profits Interest | 80% | |||
Trust Income from Net Profits Interest | $ | 25,727 | ||
(a) | Per the terms of the net profits interest, development costs are to be deducted when calculating the distributable income to the Trust. |
5. | Pro Forma Adjustments |
Gross cash proceeds from the sale of trust units | $ | 350,000 | ||
Trust units held by Enduro Sponsor | 350,000 | |||
Fair value of investment in Net Profits Interest | $ | 700,000 | ||
F-34
Table of Contents
Enduro Sponsor
ENDURO-1
Table of Contents
Name | Age | Title | ||||
Jon S. Brumley | 40 | President and Chief Executive Officer | ||||
John W. Arms | 44 | Executive Vice President and Chief Operating Officer | ||||
Kimberly A. Weimer | 32 | Vice President, Chief Financial Officer |
ENDURO-2
Table of Contents
ENDURO-3
Table of Contents
ENDURO-4
Table of Contents
Enduro | Enduro Sponsor | |||||||||||||||||||||||||||||
Sponsor | Pro Forma | |||||||||||||||||||||||||||||
Pro Forma | as Adjusted | |||||||||||||||||||||||||||||
for the | for the Offering | |||||||||||||||||||||||||||||
Acquisition | (including the | Predecessor — | ||||||||||||||||||||||||||||
of the | Conveyance of the | DNR | Predecessor — EAC | |||||||||||||||||||||||||||
Acquired | Net Profits | Enduro Sponsor | March 9, | January 1, | ||||||||||||||||||||||||||
Properties | interests) | Inception | 2010 | 2010 | ||||||||||||||||||||||||||
Year Ended | Year Ended | Through | Through | Through | ||||||||||||||||||||||||||
December 31, | December 31, | December 31, | November 30, | March 8, | Year Ended December 31, | |||||||||||||||||||||||||
2010 | 2010 | 2010 | 2010 | 2010 | 2009 | 2008 | ||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||
(Unaudited) | ||||||||||||||||||||||||||||||
Revenue | ||||||||||||||||||||||||||||||
Oil | $ | 70,161 | $ | 42,148 | $ | 106 | $ | 1,036 | $ | 331 | $ | 1,909 | $ | 3,295 | ||||||||||||||||
Natural Gas | 62,420 | 48,905 | 3,486 | 35,503 | 10,756 | 31,998 | 59,075 | |||||||||||||||||||||||
Marketing | 5,131 | 5,131 | 383 | 3,671 | 1,077 | — | — | |||||||||||||||||||||||
Total revenues | 137,712 | 96,184 | 3,975 | 40,210 | 12,164 | 33,907 | 62,370 | |||||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||
Lease operating | 27,019 | 17,187 | 507 | 5,285 | 1,142 | 7,608 | 6,343 | |||||||||||||||||||||||
Production, ad valorem and severance taxes | 9,417 | 6,189 | 170 | 2,003 | 548 | 2,565 | 2,442 | |||||||||||||||||||||||
Gathering and transportation | 3,845 | 3,054 | 206 | 2,755 | 429 | 2,138 | 2,577 | |||||||||||||||||||||||
Depletion, depreciation and amortization | 61,669 | 37,001 | 1,973 | 21,754 | 7,949 | 33,665 | 26,716 | |||||||||||||||||||||||
Exploration expense | 10,188 | 10,188 | — | 9,957 | 231 | 8,688 | 723 | |||||||||||||||||||||||
Marketing | 5,020 | 5,020 | 372 | 3,588 | 1,060 | — | — | |||||||||||||||||||||||
General and administrative | 11,013 | 11,013 | 3,826 | 1,254 | 2,481 | 5,045 | 4,001 | |||||||||||||||||||||||
Merger related transaction costs | — | — | — | 6,922 | 16,136 | — | — | |||||||||||||||||||||||
Derivative fair value loss | 4,977 | 4,977 | 4,977 | — | — | — | — | |||||||||||||||||||||||
Other operating | 968 | 968 | 18 | 24 | 9 | 51 | 28 | |||||||||||||||||||||||
Total expenses | 134,116 | 95,597 | 12,049 | 53,542 | 29,985 | 59,760 | 42,830 | |||||||||||||||||||||||
Operating Income (Loss) | 3,596 | 587 | (8,074 | ) | (13,332 | ) | (17,821 | ) | (25,853 | ) | 19,540 | |||||||||||||||||||
Interest expense, net | (5,659 | ) | — | (148 | ) | (6,183 | ) | — | — | — | ||||||||||||||||||||
Net income (loss) | (2,063 | ) | 587 | (8,222 | ) | (19,515 | ) | (17,821 | ) | (25,853 | ) | 19,540 | ||||||||||||||||||
ENDURO-5
Table of Contents
ENDURO-6
Table of Contents
Enduro Sponsor | Predecessor - DNR | Predecessor - EAC | ||||||||||||||||
Inception | March 9, | January 1, | Year | |||||||||||||||
Through | 2010 Through | 2010 Through | Ended | |||||||||||||||
December 31, | November 30, | March 8, | December 31, | |||||||||||||||
2010 | 2010 | 2010 | 2009 | |||||||||||||||
Revenue | ||||||||||||||||||
Oil | $ | 106 | $ | 1,036 | $ | 331 | $ | 1,909 | ||||||||||
Natural gas | 3,486 | 35,503 | 10,756 | 31,998 | ||||||||||||||
Marketing | 383 | 3,671 | 1,077 | — | ||||||||||||||
Total Revenues | 3,975 | 40,210 | 12,164 | 33,907 | ||||||||||||||
Expenses | ||||||||||||||||||
Lease operating | 507 | 5,285 | 1,142 | 7,608 | ||||||||||||||
Production, ad valorem and severance taxes | 170 | 2,003 | 548 | 2,565 | ||||||||||||||
Gathering and transportation | 206 | 2,755 | 429 | 2,138 | ||||||||||||||
Depletion, depreciation, and amortization | 1,973 | 21,754 | 7,949 | 33,665 | ||||||||||||||
Exploration expense | — | 9,957 | 231 | 8,688 | ||||||||||||||
Marketing | 372 | 3,588 | 1,060 | — | ||||||||||||||
General and administrative | 3,826 | 1,254 | 2,481 | 5,045 | ||||||||||||||
Merger related transaction costs | — | 6,922 | 16,136 | — | ||||||||||||||
Derivative fair value loss | 4,977 | — | — | — | ||||||||||||||
Other operating | 18 | 24 | 9 | 51 | ||||||||||||||
Total expenses | 12,049 | 53,542 | 29,985 | 59,760 | ||||||||||||||
Operating income (loss) | (8,074 | ) | (13,332 | ) | (17,821 | ) | (25,853 | ) | ||||||||||
Interest expense, net | (148 | ) | (6,183 | ) | — | — | ||||||||||||
Net income (loss) | $ | (8,222 | ) | $ | (19,515 | ) | $ | (17,821 | ) | $ | (25,853 | ) | ||||||
Production Volumes | ||||||||||||||||||
Oil (MBbls) | 1 | 14 | 5 | 35 | ||||||||||||||
Natural Gas (MMcf) | 853 | 8,944 | 1,941 | 8,569 | ||||||||||||||
Total (MBoe) | 143 | 1,505 | 329 | 1,463 | ||||||||||||||
Average realized prices | ||||||||||||||||||
Oil ($/Bbl) | $ | 106.00 | $ | 74.00 | $ | 66.20 | $ | 54.54 | ||||||||||
Natural gas ($/Mcf) | $ | 4.09 | $ | 3.97 | $ | 5.54 | $ | 3.73 | ||||||||||
Selected Expenses (per Boe): | ||||||||||||||||||
Lease operating | $ | 3.54 | $ | 3.51 | $ | 3.48 | $ | 5.20 | ||||||||||
Production, ad valorem and severance taxes | $ | 1.19 | $ | 1.33 | $ | 1.67 | $ | 1.75 | ||||||||||
Gathering and transportation | $ | 1.44 | $ | 1.83 | $ | 1.30 | $ | 1.46 | ||||||||||
Depletion, depreciation, and amortization | $ | 13.78 | $ | 14.46 | $ | 24.22 | $ | 23.00 |
ENDURO-7
Table of Contents
ENDURO-8
Table of Contents
Predecessor - EAC | ||||||||
Year Ended December 31, | ||||||||
2009 | 2008 | |||||||
Revenue | ||||||||
Oil | $ | 1,909 | $ | 3,295 | ||||
Natural gas | 31,998 | 59,075 | ||||||
Total Revenues | 33,907 | 62,370 | ||||||
Expenses | ||||||||
Lease operating | 7,608 | 6,343 | ||||||
Production, ad valorem and severance taxes | 2,565 | 2,442 | ||||||
Gathering and transportation | 2,138 | 2,577 | ||||||
Depletion, depreciation, and amortization | 33,665 | 26,716 | ||||||
Exploration expense | 8,688 | 723 | ||||||
General and administrative | 5,045 | 4,001 | ||||||
Other operating | 51 | 28 | ||||||
Total expenses | 59,760 | 42,830 | ||||||
Net income (loss) | $ | (25,853 | ) | $ | 19,540 | |||
Production Volumes | ||||||||
Oil (MBbls) | 35 | 36 | ||||||
Natural Gas (MMcf) | 8,569 | 6,946 | ||||||
Total (MBoe) | 1,463 | 1,193 | ||||||
Average realized prices | ||||||||
Oil ($/Bbl) | $ | 54.54 | $ | 91.53 | ||||
Natural gas ($/Mcf) | $ | 3.73 | $ | 8.50 | ||||
Selected Expenses (per Boe): | ||||||||
Lease operating | $ | 5.20 | $ | 5.32 | ||||
Production, ad valorem and severance taxes | $ | 1.75 | $ | 2.05 | ||||
Gathering and transportation | $ | 1.46 | $ | 2.16 | ||||
Depletion, depreciation, and amortization | $ | 23.00 | $ | 22.39 |
ENDURO-9
Table of Contents
ENDURO-10
Table of Contents
• | a prohibition against incurring debt, subject to permitted exceptions; | |
• | a restriction on creating liens on the assets of Enduro Sponsor, subject to permitted exceptions; | |
• | restrictions on merging and selling assets outside the ordinary course of business; | |
• | a requirement to maintain a ratio of consolidated current assets to current liabilities of not less than 1.0 to 1.0; and | |
• | a requirement that Enduro Sponsor maintain a ratio of debt to annualized adjusted EBITDA (as defined in the Credit Agreement) of not more than 4.0 to 1.0, commencing with the quarter ending March 31, 2011. |
ENDURO-11
Table of Contents
Payments Due by Period | ||||||||||||||||||||
Less Than | More Than | |||||||||||||||||||
Total | 1 Year | 1-3 Years | 3-5 Years | 5 Years | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Long-term debt(1) | $ | 52,000 | $ | — | $ | — | $ | 52,000 | $ | — | ||||||||||
Transportation agreement | 22,385 | 2,464 | 7,398 | 7,398 | 5,125 | |||||||||||||||
Lease agreements | 3,072 | 287 | 1,593 | 1,192 | — | |||||||||||||||
Total | $ | 77,457 | $ | 2,751 | $ | 8,991 | $ | 60,590 | $ | 5,125 | ||||||||||
(1) | The amounts included in the table above represent principal maturities only. See “Management’s discussion and analysis of financial condition and results of operations of Enduro Sponsor — Quantitative and qualitative disclosure about market risk — Interest rate risk” for information regarding interest payment obligations under long-term debt obligations. |
ENDURO-12
Table of Contents
ENDURO-13
Table of Contents
ENDURO-14
Table of Contents
Fair Value | ||||||||||||||||||||
Daily Put | Average | Daily Swap | Average | December 31, | ||||||||||||||||
Period | Volumes | Price | Volumes | Price | 2010 | |||||||||||||||
(Mcf) | ($/Mcf) | (Mcf) | ($/Mcf) | (In thousands) | ||||||||||||||||
January 2011 — February 2011 | 12,000 | $ | 4.19 | 10,000 | $ | 4.30 | $ | 190 | ||||||||||||
March 2011 — December 2011 | 13,000 | $ | 4.18 | 10,000 | $ | 4.30 | 1,116 | |||||||||||||
January 2012 — December 2012 | 13,000 | $ | 4.92 | 10,000 | $ | 4.57 | 1,875 | |||||||||||||
January 2013 — December 2013 | 2,000 | $ | 4.95 | 5,000 | $ | 5.10 | 391 | |||||||||||||
$ | 3,572 | |||||||||||||||||||
ENDURO-15
Table of Contents
Average | Average | |||||||||||||||||||||||||||||||
Daily | Average | Daily | Collar | Collar | Daily | Fair Value | ||||||||||||||||||||||||||
Put | Put | Collar | Put | Cap | Swap | Average | December 31, | |||||||||||||||||||||||||
Period | Volumes | Price | Volumes | Price | Price | Volumes | Price | 2010 | ||||||||||||||||||||||||
(Bbls) | ($/Bbl) | (Bbls) | ($/Bbl) | ($/Bbl) | (Bbls) | ($/Bbl) | (In thousands) | |||||||||||||||||||||||||
January 2011 — February 2011 | — | $ | — | 180 | $ | 80.00 | $ | 94.60 | 150 | $ | 85.50 | $ | 744 | |||||||||||||||||||
March 2011 — December 2011 | 500 | $ | 92.00 | 180 | $ | 80.00 | $ | 94.60 | 150 | $ | 85.50 | (395 | ) | |||||||||||||||||||
January 2012 — December 2012 | 500 | $ | 92.00 | 170 | $ | 81.00 | $ | 95.85 | 150 | $ | 88.60 | 1,466 | ||||||||||||||||||||
January 2013 — December 2013 | — | $ | — | 160 | $ | 82.00 | $ | 95.60 | 150 | $ | 90.00 | (337 | ) | |||||||||||||||||||
$ | 1,478 | |||||||||||||||||||||||||||||||
Average | Average | Average | Fair Value | |||||||||||||||||
Daily | Sub-Floor | Floor | Cap | December 31, | ||||||||||||||||
Period | Volumes | Price | Price | Price | 2010 | |||||||||||||||
(Bbls) | ($/Bbl) | ($/Bbl) | ($/Bbl) | (In thousands) | ||||||||||||||||
March 2011 — December 2011 | 500 | $ | 67.50 | $ | 90.00 | $ | 110.00 | $ | 376 | |||||||||||
January 2012 — December 2012 | 500 | $ | 67.50 | $ | 90.00 | $ | 110.00 | 212 | ||||||||||||
January 2013 — December 2013 | 500 | $ | 67.50 | $ | 90.00 | $ | 110.00 | 58 | ||||||||||||
$ | 646 | |||||||||||||||||||
ENDURO-16
Table of Contents
ENDURO-17
Table of Contents
ENDURO-18
Table of Contents
ENDURO RESOURCE PARTNERS LLC PREDECESSOR: | ||||
ENDURO F-2 | ||||
ENDURO F-3 | ||||
ENDURO F-4 | ||||
ENDURO F-5 | ||||
ENDURO F-6 | ||||
ENDURO F-7 | ||||
ENDURO RESOURCE PARTNERS LLC: | ||||
ENDURO F-19 | ||||
ENDURO F-20 | ||||
ENDURO F-21 | ||||
ENDURO F-22 | ||||
ENDURO F-23 | ||||
ENDURO F-24 | ||||
UNAUDITED PRO FORMA FINANCIAL STATEMENTS: | ||||
ENDURO F-39 | ||||
ENDURO F-40 | ||||
ENDURO F-41 | ||||
ENDURO F-42 |
ENDURO F-1
Table of Contents
ENDURO F-2
Table of Contents
Predecessor- | Predecessor- | ||||||||
DNR | EAC | ||||||||
November 30, | December 31, | ||||||||
2010 | 2009 | ||||||||
(In thousands) | |||||||||
ASSETS | |||||||||
Current assets: | |||||||||
Accounts receivable | $ | 8,287 | $ | 11,771 | |||||
Prepaid drilling costs | 1,345 | 3,778 | |||||||
Total current assets | 9,632 | 15,549 | |||||||
Oil and natural gas properties — successful efforts method: | |||||||||
Proved properties | 220,237 | 368,461 | |||||||
Unproved properties | 199,130 | 20,792 | |||||||
Accumulated depletion, depreciation, and amortization | (31,707 | ) | (103,722 | ) | |||||
Total oil and natural gas properties, net | 387,660 | 285,531 | |||||||
Other property and equipment, net | 22 | 47 | |||||||
Total assets | $ | 397,314 | $ | 301,127 | |||||
LIABILITIES AND OWNER’S NET EQUITY | |||||||||
Current liabilities: | |||||||||
Accrued lease operating expense | $ | 1,260 | $ | 1,205 | |||||
Production, ad valorem, and severance taxes payable | 929 | 739 | |||||||
Accrued development capital | 19,253 | 15,684 | |||||||
Other | 554 | 656 | |||||||
Total current liabilities | 21,996 | 18,284 | |||||||
Asset retirement obligations | 587 | 1,404 | |||||||
Total liabilities | 22,583 | 19,688 | |||||||
Commitments and contingencies | |||||||||
Owner’s net equity | 374,731 | 281,439 | |||||||
Total liabilities and owners’ net equity | $ | 397,314 | $ | 301,127 | |||||
ENDURO F-3
Table of Contents
Predecessor- | |||||||||||||||||
DNR | Predecessor-EAC | ||||||||||||||||
March 9, 2010 | January 1, | ||||||||||||||||
Through | 2010 Through | Year Ended | Year Ended | ||||||||||||||
November 30, | March 8, | December 31, | December 31, | ||||||||||||||
2010 | 2010 | 2009 | 2008 | ||||||||||||||
(In thousands) | |||||||||||||||||
Revenues: | |||||||||||||||||
Oil | $ | 1,036 | $ | 331 | $ | 1,909 | $ | 3,295 | |||||||||
Natural gas | 35,503 | 10,756 | 31,998 | 59,075 | |||||||||||||
Marketing | 3,671 | 1,077 | — | — | |||||||||||||
Total revenues | 40,210 | 12,164 | 33,907 | 62,370 | |||||||||||||
Expenses: | |||||||||||||||||
Lease operating | 5,285 | 1,142 | 7,608 | 6,343 | |||||||||||||
Production, ad valorem, and severance taxes | 2,003 | 548 | 2,565 | 2,442 | |||||||||||||
Gathering and transportation | 2,755 | 429 | 2,138 | 2,577 | |||||||||||||
Depletion, depreciation, and amortization | 21,754 | 7,949 | 33,665 | 26,716 | |||||||||||||
Exploration expense | 9,957 | 231 | 8,688 | 723 | |||||||||||||
Marketing | 3,588 | 1,060 | — | — | |||||||||||||
General and administrative | 1,254 | 2,481 | 5,045 | 4,001 | |||||||||||||
Merger-related transaction costs | 6,922 | 16,136 | — | — | |||||||||||||
Other operating | 24 | 9 | 51 | 28 | |||||||||||||
Total expenses | 53,542 | 29,985 | 59,760 | 42,830 | |||||||||||||
Operating income (loss) | (13,332 | ) | (17,821 | ) | (25,853 | ) | 19,540 | ||||||||||
Interest expense | (6,183 | ) | — | — | — | ||||||||||||
Net income (loss) | $ | (19,515 | ) | $ | (17,821 | ) | $ | (25,853 | ) | $ | 19,540 | ||||||
ENDURO F-4
Table of Contents
Owner’s Net Equity | ||||
(In thousands) | ||||
Predecessor — EAC | ||||
Balance at January 1, 2008 | $ | 105,278 | ||
Net income | 19,540 | |||
Net contributions from owner | 109,615 | |||
Balance at December 31, 2008 | 234,433 | |||
Net loss | (25,853 | ) | ||
Net contributions from owner | 72,859 | |||
Balance at December 31, 2009 | 281,439 | |||
Net loss | (17,821 | ) | ||
Net contributions from owner | 26,455 | |||
Balance at March 8, 2010 | $ | 290,073 | ||
Predecessor — DNR | ||||
Balance at March 9, 2010 | $ | — | ||
Net loss | (19,515 | ) | ||
Net contributions from owner | 394,246 | |||
Balance at November 30, 2010 | $ | 374,731 | ||
ENDURO F-5
Table of Contents
Predecessor - | |||||||||||||||||
DNR | Predecessor - EAC | ||||||||||||||||
March 9, 2010 | January 1, | Year | Year | ||||||||||||||
Through | 2010 Through | Ended | Ended | ||||||||||||||
November 30, | March 8, | December 31, | December 31, | ||||||||||||||
2010 | 2010 | 2009 | 2008 | ||||||||||||||
(In thousands) | |||||||||||||||||
Cash flows from operating activities: | |||||||||||||||||
Net income (loss) | $ | (19,515 | ) | $ | (17,821 | ) | $ | (25,853 | ) | $ | 19,540 | ||||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | |||||||||||||||||
Depletion, depreciation, and amortization | 21,754 | 7,949 | 33,665 | 26,716 | |||||||||||||
Other non-cash items | 9,981 | 240 | 8,739 | 751 | |||||||||||||
Changes in operating assets and liabilities: | |||||||||||||||||
Accounts receivable | 5,415 | (1,931 | ) | 1,897 | (5,699 | ) | |||||||||||
Prepaid drilling costs | 4,658 | (2,225 | ) | 3,084 | (6,862 | ) | |||||||||||
Accrued expenses | 1,403 | (1,259 | ) | 1,043 | 582 | ||||||||||||
Net cash provided by (used in) operating activities | 23,696 | (15,047 | ) | 22,575 | 35,028 | ||||||||||||
Cash flows from investing activities: | |||||||||||||||||
Development of oil and natural gas properties | (57,060 | ) | (11,408 | ) | (93,620 | ) | (73,616 | ) | |||||||||
Acquisition of oil and natural gas properties | (360,882 | ) | — | (1,814 | ) | (71,027 | ) | ||||||||||
Net cash used in investing activities | (417,942 | ) | (11,408 | ) | (95,434 | ) | (144,643 | ) | |||||||||
Cash flows from financing activities: | |||||||||||||||||
Net contributions from owner | 394,246 | 26,455 | 72,859 | 109,615 | |||||||||||||
Net cash provided by financing activities | 394,246 | 26,455 | 72,859 | 109,615 | |||||||||||||
Net increase in cash and cash equivalents | — | — | — | — | |||||||||||||
Cash and cash equivalents, beginning of period | — | — | — | — | |||||||||||||
Cash and cash equivalents, end of period | $ | — | $ | — | $ | — | $ | — | |||||||||
ENDURO F-6
Table of Contents
1. | Organization and Nature of Operations |
2. | Summary of Significant Accounting Policies |
ENDURO F-7
Table of Contents
ENDURO F-8
Table of Contents
ENDURO F-9
Table of Contents
ENDURO F-10
Table of Contents
ENDURO F-11
Table of Contents
3. | Acquisition |
Proved oil and natural gas properties | $ | 164,154 | ||
Unproved properties | 199,130 | |||
Other equipment | 26 | |||
Accounts receivable | 13,702 | |||
Prepaid drilling costs | 6,003 | |||
Total assets acquired | 383,015 | |||
Accrued development costs | (20,235 | ) | ||
Asset retirement obligations | (558 | ) | ||
Operating payables | (1,340 | ) | ||
Total liabilities assumed | (22,133 | ) | ||
Fair value of net assets acquired | $ | 360,882 | ||
4. | Disclosures About Fair Value Measurements |
• | Level 1 — Unadjusted quoted prices are available for identical assets or liabilities in active markets. | |
• | Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than |
ENDURO F-12
Table of Contents
quoted prices that are observable for the asset or liability (e.g., interest rates); and inputs derived principally from or corroborated by observable market data by correlation or other means. |
• | Level 3 — Unobservable inputs for the asset or liability. |
Predecessor - | |||||||||||||||||
DNR | Predecessor - EAC | ||||||||||||||||
March 9, 2010 | Year | ||||||||||||||||
Through | January 1, | Ended | Year Ended | ||||||||||||||
November 30, | 2010 Through | December 31, | December 31, | ||||||||||||||
2010 | March 8, 2010 | 2009 | 2008 | ||||||||||||||
Camterra Resources, Inc. | 28 | % | 33 | % | 31 | % | 34 | % | |||||||||
Chesapeake Operating, Inc. | 17 | % | * | * | * | ||||||||||||
Petrohawk Energy Corporation | 11 | % | 12 | % | 24 | % | 26 | % | |||||||||
Spark Energy | 20 | % | 23 | % | * | * |
* | Less than 10% for the period indicated. |
ENDURO F-13
Table of Contents
5. | Asset Retirement Obligations |
Predecessor- DNR | Predecessor - EAC | ||||||||||||
January 1, | Year | ||||||||||||
March 9, 2010 | 2010 Through | Ended | |||||||||||
Through | March 8, | December 31, | |||||||||||
November 30, 2010 | 2010 | 2009 | |||||||||||
Beginning asset retirement obligations | $ | — | $ | 1,404 | $ | 1,322 | |||||||
Liabilities assumed at acquisition | 558 | — | — | ||||||||||
Wells drilled | 5 | — | 268 | ||||||||||
Change in estimate | — | (1 | ) | (237 | ) | ||||||||
Accretion of discount | 24 | 9 | 51 | ||||||||||
Ending asset retirement obligations | $ | 587 | $ | 1,412 | $ | 1,404 | |||||||
6. | Commitments and Contingencies |
ENDURO F-14
Table of Contents
2010 | $ | 209 | ||
2011 | 2,464 | |||
2012 | 2,470 | |||
2013 | 2,464 | |||
2014 | 2,464 | |||
2015 | 2,464 | |||
Thereafter | 10,059 | |||
$ | 22,594 | |||
7. | Subsequent Events |
8. | Supplemental Oil and Natural Gas Disclosures (Unaudited) |
Predecessor- | |||||||||||||||||
DNR | Predecessor-EAC | ||||||||||||||||
March 9 | January 1, 2010 | Year | Year | ||||||||||||||
Through | Through | Ended | Ended | ||||||||||||||
November 30, | March 8, | December 31, | December 31, | ||||||||||||||
2010 | 2010 | 2009 | 2008 | ||||||||||||||
(In thousands) | |||||||||||||||||
Proved acquisitions | $ | 164,154 | $ | — | $ | — | $ | 56,186 | |||||||||
Unproved acquisitions | 199,130 | — | 1,814 | 14,841 | |||||||||||||
Total acquisitions | 363,284 | — | 1,814 | 71,027 | |||||||||||||
Exploratory costs | 9,945 | 11,534 | 59,092 | 29,057 | |||||||||||||
Development costs | 46,138 | 4,424 | 30,742 | 59,546 | |||||||||||||
Total costs incurred | $ | 419,367 | $ | 15,958 | $ | 91,648 | $ | 159,630 | |||||||||
ENDURO F-15
Table of Contents
Predecessor- | |||||||||||||
DNR | Predecessor-EAC | ||||||||||||
November 30, | December 31, | December 31, | |||||||||||
2010 | 2009 | 2008 | |||||||||||
Proved reserves | |||||||||||||
Oil (MBbl) | 112 | 114 | 151 | ||||||||||
Natural gas (MMcf) | 107,686 | 108,906 | 61,239 | ||||||||||
Combined (MBOE) | 18,059 | 18,265 | 10,357 | ||||||||||
Proved developed reserves | |||||||||||||
Oil (MBbl) | 67 | 69 | 106 | ||||||||||
Natural gas (MMcf) | 57,673 | 53,667 | 46,378 | ||||||||||
Combined (MBOE) | 9,679 | 9,014 | 7,836 |
ENDURO F-16
Table of Contents
Oil | Natural Gas | Combined | ||||||||||
(MBbls) | (MMcf) | (MBOE) | ||||||||||
Predecessor — EAC: | ||||||||||||
Balance as of January 1, 2008 | 114 | 39,495 | 6,696 | |||||||||
Revisions of estimates | 73 | 28,690 | 4,855 | |||||||||
Production | (36 | ) | (6,946 | ) | (1,194 | ) | ||||||
Balance as of December 31, 2008 | 151 | 61,239 | 10,357 | |||||||||
Revisions of estimates | (2 | ) | 56,236 | 9,371 | ||||||||
Production | (35 | ) | (8,569 | ) | (1,463 | ) | ||||||
Balance as of December 31, 2009 | 114 | 108,906 | 18,265 | |||||||||
Production | (5 | ) | (1,941 | ) | (329 | ) | ||||||
Balance as of March 8, 2010 | 109 | 106,965 | 17,936 | |||||||||
Predecessor — DNR: | ||||||||||||
Balance as of March 9, 2010 | — | — | — | |||||||||
Acquisitions | 126 | 116,630 | 19,564 | |||||||||
Production | (14 | ) | (8,944 | ) | (1,505 | ) | ||||||
Balance as of November 30, 2010 | 112 | 107,686 | 18,059 |
ENDURO F-17
Table of Contents
Predecessor- | |||||||||||||||||
DNR | Predecessor - EAC | ||||||||||||||||
November | March 8, | December 31, | December 31, | ||||||||||||||
30, 2010 | 2010 | 2009 | 2008 | ||||||||||||||
Oil and natural gas producing activities: | |||||||||||||||||
Future cash inflows | $ | 433,755 | $ | 377,488 | $ | 388,575 | $ | 333,413 | |||||||||
Future production costs | (141,262 | ) | (119,095 | ) | (121,214 | ) | (102,007 | ) | |||||||||
Future development costs | (33,462 | ) | (87,435 | ) | (103,393 | ) | (39,563 | ) | |||||||||
Undiscounted future net cash flows | 259,031 | 170,958 | 163,968 | 191,843 | |||||||||||||
10% annual discount factor | (87,408 | ) | (101,132 | ) | (102,162 | ) | (89,016 | ) | |||||||||
Standardized measure of discounted future cash flows | $ | 171,623 | $ | 69,826 | $ | 61,806 | $ | 102,827 | |||||||||
Predecessor- | |||||||||||||||||
DNR | Predecessor-EAC | ||||||||||||||||
March 8, | January 1, | ||||||||||||||||
2010 | 2010 | Year | Year | ||||||||||||||
Through | Through | Ended | Ended | ||||||||||||||
November 30, | March 8, | December | December | ||||||||||||||
2010 | 2010 | 31, 2009 | 31, 2008 | ||||||||||||||
Oil and natural gas sales, net of production costs | $ | (26,496 | ) | $ | (8,968 | ) | $ | (21,596 | ) | $ | (51,008 | ) | |||||
Net change in sales price and production costs | — | — | (46,255 | ) | (18,432 | ) | |||||||||||
Revisions of quantity estimates | — | — | 44,159 | 59,189 | |||||||||||||
Previously estimated development costs incurred | 56,083 | 15,958 | 39,563 | 28,087 | |||||||||||||
Change in estimated future development costs | — | — | (63,830 | ) | (25,759 | ) | |||||||||||
Accretion of discount | 9,909 | 1,030 | 10,283 | 9,947 | |||||||||||||
Change in timing and other | — | — | (3,345 | ) | 1,335 | ||||||||||||
Purchases ofminerals-in-place | 132,127 | — | — | — | |||||||||||||
Net change in standardized measure | 171,623 | 8,020 | (41,021 | ) | 3,359 | ||||||||||||
Standardized measure balance, beginning of period | — | 61,806 | 102,827 | 99,468 | |||||||||||||
Standardized measure balance, end of period | $ | 171,623 | $ | 69,826 | $ | 61,806 | $ | 102,827 | |||||||||
ENDURO F-18
Table of Contents
ENDURO F-19
Table of Contents
December 31, | ||||
2010 | ||||
(In thousands, | ||||
except unit | ||||
amounts) | ||||
ASSETS | ||||
Current assets: | ||||
Cash and cash equivalents | $ | 53,984 | ||
Accounts receivable — trade | 7,215 | |||
Prepaid expenses | 223 | |||
Derivatives | 3,075 | |||
Total current assets | 64,497 | |||
Oil and natural gas properties — successful efforts method of accounting: | ||||
Proved properties | 209,723 | |||
Unproved properties | 34,569 | |||
Accumulated depletion, depreciation, and amortization | (1,946 | ) | ||
Total oil and natural gas properties, net | 242,346 | |||
Other property and equipment, net | 184 | |||
Acquisition deposits | 47,500 | |||
Derivatives | 5,655 | |||
Other | 1,650 | |||
Total assets | $ | 361,832 | ||
LIABILITIES AND MEMBERS’ EQUITY | ||||
Current liabilities: | ||||
Accounts payable | $ | 786 | ||
Accrued liabilities: | ||||
Lease operating | 1,667 | |||
Development capital | 10,565 | |||
Production taxes, transportation, and marketing | 748 | |||
Derivatives | 1,044 | |||
Current portion of firm transportation contract liability | 2,464 | |||
Oil and natural gas revenues payable | 1,832 | |||
Other | 2,576 | |||
Total current liabilities | 21,682 | |||
Long-term debt | 52,000 | |||
Derivatives | 1,990 | |||
Asset retirement obligations, net of current portion | 1,496 | |||
Firm transportation contract liability, net of current portion | 10,725 | |||
Total liabilities | 87,893 | |||
Commitments and contingencies | ||||
Members’ equity: | ||||
Class A, 282,160,500 units issued and outstanding | 273,939 | |||
Class B, 96,000 units issued and outstanding | — | |||
Total members’ equity | 273,939 | |||
Total liabilities and members’ equity | $ | 361,832 | ||
ENDURO F-20
Table of Contents
March 3, 2010 | ||||
(Inception) | ||||
Through | ||||
December 31, | ||||
2010 | ||||
(In thousands, | ||||
except per unit | ||||
amounts) | ||||
Revenues: | ||||
Oil | $ | 106 | ||
Natural gas | 3,486 | |||
Marketing | 383 | |||
Total revenues | 3,975 | |||
Expenses: | ||||
Lease operating | 507 | |||
Production, ad valorem, and severance taxes | 170 | |||
Gathering and transportation | 206 | |||
Depletion, depreciation, and amortization | 1,973 | |||
Marketing | 372 | |||
General and administrative | 3,826 | |||
Derivative fair value loss | 4,977 | |||
Other operating | 18 | |||
Total expenses | 12,049 | |||
Operating loss | (8,074 | ) | ||
Interest expense, net | (148 | ) | ||
Net loss | $ | (8,222 | ) | |
Net loss per Class A unit — basic and diluted | $ | (0.06 | ) | |
Weighted average units outstanding — Class A: | ||||
Basic | 140,780 | |||
Diluted | 140,780 |
ENDURO F-21
Table of Contents
Members’ | ||||||||
Units | Equity | |||||||
(In thousands, except units) | ||||||||
Balance at March 3, 2010 (Inception) | $ | — | ||||||
Members’ contributions and issuance of Class A units | 282,160,500 | 282,161 | ||||||
Issuance of Class B units | 96,000 | — | ||||||
Net loss | (8,222 | ) | ||||||
Balance at December 31, 2010 | $ | 273,939 | ||||||
ENDURO F-22
Table of Contents
March 3, | ||||
2010 | ||||
(Inception) | ||||
Through | ||||
December 31, | ||||
2010 | ||||
(In thousands) | ||||
Cash flows from operating activities: | ||||
Net loss | $ | (8,222 | ) | |
Adjustments to reconcile net loss to net cash used in operating activities: | ||||
Depletion, depreciation, and amortization | 1,973 | |||
Unrealized loss on derivatives | 4,977 | |||
Other non-cash items | 45 | |||
Changes in operating assets and liabilities: | ||||
Accounts receivable | (4,066 | ) | ||
Prepaid expenses | (223 | ) | ||
Derivative assets | (10,673 | ) | ||
Accounts payable and other accrued expenses | 3,112 | |||
Net cash used in operating activities | (13,077 | ) | ||
Cash flows from investing activities: | ||||
Acquisition deposits | (47,500 | ) | ||
Acquisition of oil and natural gas properties | (217,736 | ) | ||
Purchases of other property and equipment | (186 | ) | ||
Net cash used in investing activities | (265,422 | ) | ||
Cash flows from financing activities: | ||||
Contributions from members | 282,161 | |||
Proceeds from long-term debt borrowings | 52,000 | |||
Payment of deferred loan costs | (1,678 | ) | ||
Net cash provided by financing activities | 332,483 | |||
Net increase in cash and cash equivalents | 53,984 | |||
Cash and cash equivalents, beginning of period | — | |||
Cash and cash equivalents, end of period | $ | 53,984 | ||
Supplemental cash flow information: | ||||
Cash paid during the period for interest | $ | 134 | ||
Non-cash investing and financing activities: | ||||
Properties acquired, other than for cash | $ | 83 |
ENDURO F-23
Table of Contents
1. | Organization and Nature of Operations |
2. | Summary of Significant Accounting Policies |
ENDURO F-24
Table of Contents
ENDURO F-25
Table of Contents
ENDURO F-26
Table of Contents
3. | Acquisition |
ENDURO F-27
Table of Contents
Oil and natural gas properties | $ | 241,634 | ||
Other equipment | 24 | |||
Accounts receivable | 4,950 | |||
Total assets acquired | 246,608 | |||
Asset retirement obligations | (2,542 | ) | ||
Firm transportation contract liability | (13,762 | ) | ||
Operating payables | (16,543 | ) | ||
Total liabilities assumed | (32,847 | ) | ||
Fair value of net assets acquired | $ | 213,761 | ||
Pro forma revenues | $ | 44,186 | ||
Pro forma net loss | (3,467 | ) |
4. | Disclosures About Fair Value Measurements |
• | Level 1 — Unadjusted quoted prices are available for identical assets or liabilities in active markets. | |
• | Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates); and inputs derived principally from or corroborated by observable market data by correlation or other means. | |
• | Level 3 — Unobservable inputs for the asset or liability. |
ENDURO F-28
Table of Contents
Fair Value Measurements at Reporting Date Using | ||||||||||||||||
Quoted Prices in | Significant | |||||||||||||||
Active Markets | Other | Significant | ||||||||||||||
Fair Value at | for Identical | Observable | Unobservable | |||||||||||||
December 31, | Assets | Inputs | Inputs | |||||||||||||
2010 | (Level 1) | (Level 2) | (Level 3) | |||||||||||||
Oil and natural gas derivative contracts — assets | $ | 8,730 | $ | — | $ | 143 | $ | 8,587 | ||||||||
Oil and natural gas derivative contracts — liabilities | 3,034 | — | 2,328 | 706 |
Derivative Contracts — Floors | ||||||||
and Caps | ||||||||
Oil | Natural Gas | |||||||
Balance at Inception | $ | — | $ | — | ||||
Purchases | 4,713 | 5,960 | ||||||
Unrealized losses included in earnings | (1,716 | ) | (1,076 | ) | ||||
Balance at December 31, 2010 | $ | 2,997 | $ | 4,884 | ||||
Carrying Value | Fair Value | |||||||
Financial assets: | ||||||||
Natural gas commodity contracts — current asset | $ | 1,639 | $ | 1,639 | ||||
Oil commodity contracts — current asset | 1,436 | 1,436 | ||||||
Natural gas commodity contracts — long-term asset | 3,386 | 3,386 | ||||||
Oil commodity contracts — long-term asset | 2,269 | 2,269 | ||||||
Financial liabilities: | ||||||||
Natural gas commodity contracts — current liabilities | 333 | 333 | ||||||
Oil commodity contracts — current liabilities | 711 | 711 | ||||||
Natural gas commodity contracts — long-term liabilities | 1,120 | 1,120 | ||||||
Oil commodity contracts — long-term liabilities | 870 | 870 | ||||||
Long-term debt | 52,000 | 52,000 |
ENDURO F-29
Table of Contents
ENDURO F-30
Table of Contents
Counterparty | Assets | Liabilities | ||||||
Credit Agricole | $ | 929 | $ | 1,040 | ||||
BNP Paribas | 2,675 | 661 | ||||||
Bank of America Merrill Lynch | 5,126 | 1,333 | ||||||
Total | $ | 8,730 | $ | 3,034 | ||||
5. | Derivative Financial Instruments |
Fair Value at | ||||||||||||||||||||
Daily Put | Average | Daily Swap | Average | December 31, | ||||||||||||||||
Period | Volumes | Price | Volumes | Price | 2010 | |||||||||||||||
(Mcf) | ($/Mcf) | (Mcf) | ($/Mcf) | (In thousands) | ||||||||||||||||
January 2011 — February 2011 | 12,000 | $ | 4.19 | 10,000 | $ | 4.30 | $ | 190 | ||||||||||||
March 2011 — December 2011 | 13,000 | $ | 4.18 | 10,000 | $ | 4.30 | 1,116 | |||||||||||||
January 2012 — December 2012 | 13,000 | $ | 4.92 | 10,000 | $ | 4.57 | 1,875 | |||||||||||||
January 2013 — December 2013 | 2,000 | $ | 4.95 | 5,000 | $ | 5.10 | 391 | |||||||||||||
$ | 3,572 | |||||||||||||||||||
Average | Average | |||||||||||||||||||||||||||||||
Daily | Average | Daily | Collar | Collar | Daily | Fair Value at | ||||||||||||||||||||||||||
Put | Put | Collar | Put | Cap | Swap | Average | December 31, | |||||||||||||||||||||||||
Period | Volumes | Price | Volumes | Price | Price | Volumes | Price | 2010 | ||||||||||||||||||||||||
(Bbls) | ($/Bbl) | (Bbls) | ($/Bbl) | ($/Bbl) | (Bbls) | ($/Bbl) | (In thousands) | |||||||||||||||||||||||||
January 2011 — February 2011 | — | $ | — | 180 | $ | 80.00 | $ | 94.60 | 150 | $ | 85.50 | $ | 744 | |||||||||||||||||||
March 2011 — December 2011 | 500 | $ | 92.00 | 180 | $ | 80.00 | $ | 94.60 | 150 | $ | 85.50 | (395 | ) | |||||||||||||||||||
January 2012 — December 2012 | 500 | $ | 92.00 | 170 | $ | 81.00 | $ | 95.85 | 150 | $ | 88.60 | 1,466 | ||||||||||||||||||||
January 2013 — December 2013 | — | $ | — | 160 | $ | 82.00 | $ | 95.60 | 150 | $ | 90.00 | (337 | ) | |||||||||||||||||||
$ | 1,478 | |||||||||||||||||||||||||||||||
ENDURO F-31
Table of Contents
Average | Average | Average | Fair Value at | |||||||||||||||||
Daily | Sub-Floor | Floor | Cap | December 31, | ||||||||||||||||
Period | Volumes | Price | Price | Price | 2010 | |||||||||||||||
(Bbls) | ($/Bbl) | ($/Bbl) | ($/Bbl) | (In thousands) | ||||||||||||||||
March 2011 — December 2011 | 500 | $ | 67.50 | $ | 90.00 | $ | 110.00 | $ | 376 | |||||||||||
January 2012 — December 2012 | 500 | $ | 67.50 | $ | 90.00 | $ | 110.00 | 212 | ||||||||||||
January 2013 — December 2013 | 500 | $ | 67.50 | $ | 90.00 | $ | 110.00 | 58 | ||||||||||||
$ | 646 | |||||||||||||||||||
6. | Long-Term Debt |
• | a prohibition against incurring debt, subject to permitted exceptions; | |
• | a restriction on creating liens on the assets of the Company, subject to permitted exceptions; | |
• | restrictions on merging and selling assets outside the ordinary course of business; |
ENDURO F-32
Table of Contents
• | consolidated current assets to current liabilities of not less than 1.0 to 1.0; and, | |
• | a requirement that the Company maintain a ratio of debt to annualized adjusted EBITDA (as defined in the Credit Agreement) of not more than 4.0 to 1.0, commencing with the quarter ending March 31, 2011. |
7. | Asset Retirement Obligations |
Asset retirement obligations at March 3, 2010 (Inception) | $ | — | ||
Liabilities assumed at acquisition | 2,542 | |||
Accretion of discount | 18 | |||
Asset retirement obligations at December 31, 2010 | $ | 2,560 | ||
8. | Members’ Equity |
ENDURO F-33
Table of Contents
9. | Commitments and Contingencies |
2011 | $ | 287 | ||
2012 | 417 | |||
2013 | 443 | |||
2014 | 733 | |||
2015 | 685 | |||
Thereafter | 507 | |||
$ | 3,072 | |||
ENDURO F-34
Table of Contents
2011 | $ | 2,464 | ||
2012 | 2,470 | |||
2013 | 2,464 | |||
2014 | 2,464 | |||
2015 | 2,464 | |||
Thereafter | 10,059 | |||
$ | 22,385 | |||
10. | Major Customers |
11. | Related-Party Transactions |
12. | Subsequent Events |
ENDURO F-35
Table of Contents
13. | Supplemental Oil and Natural Gas Disclosures (Unaudited) |
Inception Through | ||||
December 31, 2010 | ||||
(In thousands) | ||||
Proved acquisitions | $ | 207,123 | ||
Unproved acquisitions | 34,569 | |||
Total acquisitions | 241,692 | |||
Development costs | 2,600 | |||
Total costs incurred | $ | 244,292 | ||
ENDURO F-36
Table of Contents
Inception through December 31, 2010 | ||||||||||||
Oil | Natural Gas | Total | ||||||||||
(MBbls) | (MMcf) | (MBOE) | ||||||||||
Total proved reserves | ||||||||||||
Balance as of March 3, 2010 (Inception) | — | — | — | |||||||||
Purchases ofminerals-in-place | 27 | 99,289 | 16,575 | |||||||||
Production | (1 | ) | (853 | ) | (143 | ) | ||||||
Balance as of December 31, 2010 | 26 | 98,436 | 16,432 | |||||||||
Total proved developed reserves | ||||||||||||
Balance as of March 3, 2010 (Inception) | — | — | — | |||||||||
Balance as of December 31, 2010 | 26 | 63,848 | 10,667 | |||||||||
Proved undeveloped reserves | ||||||||||||
Balance as of March 3, 2010 (Inception) | — | — | — | |||||||||
Balance as of December 31, 2010 | — | 34,588 | 5,765 |
Oil and natural gas producing activities: | ||||
Future cash inflows | $ | 394,848 | ||
Future production costs | (98,627 | ) | ||
Future development costs | (55,634 | ) | ||
Undiscounted future net cash flows | 240,587 | |||
10% annual discount factor | (113,190 | ) | ||
Standardized measure of discounted future cash flows | $ | 127,397 | ||
ENDURO F-37
Table of Contents
Standardized measure balance as of March 3, 2010 (Inception) | $ | — | ||
Oil and natural gas sales, net of production costs | (2,709 | ) | ||
Previously estimated development costs incurred | 2,600 | |||
Purchases ofminerals-in-place | 127,506 | |||
Standardized measure balance as of December 31, 2010 | $ | 127,397 | ||
ENDURO F-38
Table of Contents
ENDURO F-39
Table of Contents
(in thousands)
December 31, 2010 | ||||||||||||||||||||
Offering | Pro Forma | |||||||||||||||||||
Historical | Adjustments(a) | Pro Forma | Adjustments | As Adjusted | ||||||||||||||||
Assets | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 53,984 | $ | (53,325 | ) | $ | 659 | $ | 103,500 | (b) | $ | 104,159 | ||||||||
Accounts receivable — trade | 7,215 | — | 7,215 | — | 7,215 | |||||||||||||||
Prepaid expenses | 223 | — | 223 | — | 223 | |||||||||||||||
Derivatives | 3,075 | — | 3,075 | — | 3,075 | |||||||||||||||
Total current assets | 64,497 | (53,325 | ) | 11,172 | 103,500 | 114,672 | ||||||||||||||
Oil and natural gas properties — successful efforts method of accounting: | ||||||||||||||||||||
Proved properties | 209,723 | 484,434 | 694,157 | (212,148 | )(c) | 482,009 | ||||||||||||||
Unproved properties | 34,569 | — | 34,569 | — | 34,569 | |||||||||||||||
Accumulated depletion, depreciation, and amortization | (1,946 | ) | — | (1,946 | ) | 939 | (c) | (1,007 | ) | |||||||||||
Total oil and natural gas properties, net | 242,346 | 484,434 | 726,780 | (211,209 | )(c) | 515,571 | ||||||||||||||
Other property and equipment, net | 184 | — | 184 | — | 184 | |||||||||||||||
Acquisition deposits | 47,500 | (47,500 | ) | — | — | — | ||||||||||||||
Derivatives | 5,655 | — | 5,655 | — | 5,655 | |||||||||||||||
Other | 1,650 | — | 1,650 | — | 1,650 | |||||||||||||||
Total assets | $ | 361,832 | $ | 383,609 | $ | 745,441 | $ | (107,709 | ) | $ | 637,732 | |||||||||
Liabilities and members’ equity | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable | $ | 786 | $ | — | $ | 786 | $ | — | $ | 786 | ||||||||||
Accrued liabilities: | ||||||||||||||||||||
Lease operating | 1,667 | — | 1,667 | — | 1,667 | |||||||||||||||
Development capital | 10,565 | — | 10,565 | — | 10,565 | |||||||||||||||
Production taxes, transportation, and marketing | 748 | — | 748 | — | 748 | |||||||||||||||
Derivatives | 1,044 | — | 1,044 | — | 1,044 | |||||||||||||||
Current portion of firm transportation contract liability | 2,464 | — | 2,464 | — | 2,464 | |||||||||||||||
Oil and natural gas revenues payable | 1,832 | — | 1,832 | — | 1,832 | |||||||||||||||
Other | 2,576 | 26 | 2,602 | — | 2,602 | |||||||||||||||
Total current liabilities | 21,682 | 26 | 21,708 | — | 21,708 | |||||||||||||||
Long-term debt | 52,000 | 164,500 | 216,500 | (216,500 | )(b) | — | ||||||||||||||
Derivatives | 1,990 | — | 1,990 | — | 1,990 | |||||||||||||||
Asset retirement obligations, net of current portion | 1,496 | 36,403 | 37,899 | — | 37,899 | |||||||||||||||
Firm transportation contract liability, net of current portion | 10,725 | — | 10,725 | — | 10,725 | |||||||||||||||
Total liabilities | 87,893 | 200,929 | 288,822 | (216,500 | ) | 72,322 | ||||||||||||||
Members’ equity: | ||||||||||||||||||||
Class A, 282,160,500 units issued and outstanding | 273,939 | 182,680 | 456,619 | 108,791 | (d) | 565,410 | ||||||||||||||
Class B, 96,000 units issued and outstanding | — | — | — | — | — | |||||||||||||||
Total members’ equity | 273,939 | 182,680 | 456,619 | 108,791 | 565,410 | |||||||||||||||
Total liabilities and members’ equity | $ | 361,832 | $ | 383,609 | $ | 745,441 | $ | (107,709 | ) | $ | 637,732 | |||||||||
ENDURO F-40
Table of Contents
Year Ended December 31, 2010 | ||||||||||||||||||||||||||||||||||||||||||
Enduro | Predecessor - | Predecessor - | ||||||||||||||||||||||||||||||||||||||||
Sponsor | DNR | EAC | ||||||||||||||||||||||||||||||||||||||||
Inception | March 9 | January 1 | Acquisition Adjustments | Pro Forma | ||||||||||||||||||||||||||||||||||||||
Through | Through | Through | Samson | ConocoPhillips | Other | Total | After | |||||||||||||||||||||||||||||||||||
December 31, | November 30, | March 8, | Permian Basin | Permian Basin | Acquisition | Acquisition | Acquisition | Offering | Pro Forma | |||||||||||||||||||||||||||||||||
2010 | 2010 | 2010 | Assets(a) | Assets(a) | Adjustments | Adjustments | Adjustments | Adjustments | As Adjusted | |||||||||||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||||||||||||||||||
Oil | $ | 106 | $ | 1,036 | $ | 331 | $ | 16,626 | $ | 52,062 | $ | — | $ | 68,688 | $ | 70,161 | $ | (28,013 | )(i) | $ | 42,148 | |||||||||||||||||||||
Natural gas | 3,486 | 35,503 | 10,756 | 5,650 | 7,025 | — | 12,675 | 62,420 | (13,515 | )(i) | 48,905 | |||||||||||||||||||||||||||||||
Marketing | 383 | 3,671 | 1,077 | — | — | — | — | 5,131 | — | 5,131 | ||||||||||||||||||||||||||||||||
Total revenues | 3,975 | 40,210 | 12,164 | 22,276 | 59,087 | — | 81,363 | 137,712 | (41,528 | ) | 96,184 | |||||||||||||||||||||||||||||||
Expenses: | ||||||||||||||||||||||||||||||||||||||||||
Lease operating | 507 | 5,285 | 1,142 | 3,428 | 16,657 | — | 20,085 | 27,019 | (9,832 | )(j) | 17,187 | |||||||||||||||||||||||||||||||
Production, ad valorem, and severance taxes | 170 | 2,003 | 548 | 1,702 | 4,994 | — | 6,696 | 9,417 | (3,228 | )(j) | 6,189 | |||||||||||||||||||||||||||||||
Gathering and transportation | 206 | 2,755 | 429 | 212 | 243 | — | 455 | 3,845 | (791 | )(j) | 3,054 | |||||||||||||||||||||||||||||||
Depletion, depreciation, and amortization | 1,973 | 21,754 | 7,949 | 10,853 | (e) | 24,793 | (e) | (29,703 | )(e) | 29,993 | 61,669 | (24,668 | )(k) | 37,001 | ||||||||||||||||||||||||||||
24,050 | (e) | |||||||||||||||||||||||||||||||||||||||||
Exploration expense | — | 9,957 | 231 | — | — | — | — | 10,188 | 10,188 | |||||||||||||||||||||||||||||||||
Marketing | 372 | 3,588 | 1,060 | — | — | — | — | 5,020 | — | 5,020 | ||||||||||||||||||||||||||||||||
General and administrative | 3,826 | 1,254 | 2,481 | 1,053 | (f) | 2,399 | (f) | — | 3,452 | 11,013 | — | 11,013 | ||||||||||||||||||||||||||||||
Merger-related transaction costs | — | 6,922 | 16,136 | — | — | (23,058 | )(g) | (23,058 | ) | — | — | — | ||||||||||||||||||||||||||||||
Derivative fair value loss | 4,977 | — | — | — | — | — | — | 4,977 | — | 4,977 | ||||||||||||||||||||||||||||||||
Other operating | 18 | 24 | 9 | 81 | (h) | 836 | (h) | — | 917 | 968 | — | 968 | ||||||||||||||||||||||||||||||
Total expenses | 12,049 | 53,542 | 29,985 | 17,329 | 49,922 | (28,711 | ) | 38,540 | 134,116 | (38,519 | ) | 95,597 | ||||||||||||||||||||||||||||||
Operating income (loss) | (8,074 | ) | (13,332 | ) | (17,821 | ) | 4,947 | 9,165 | 28,711 | 42,823 | 3,596 | (3,009 | ) | 587 | ||||||||||||||||||||||||||||
Interest expense, net | (148 | ) | (6,183 | ) | — | (1,508 | )(l) | (4,003 | )(l) | 6,183 | (l) | 672 | (5,659 | ) | 5,659 | (l) | — | |||||||||||||||||||||||||
Net income (loss) | $ | (8,222 | ) | $ | (19,515 | ) | $ | (17,821 | ) | $ | 3,439 | $ | 5,162 | $ | 34,894 | $ | 43,495 | $ | (2,063 | ) | $ | 2,650 | $ | 587 | ||||||||||||||||||
ENDURO F-41
Table of Contents
1. | Basis of Presentation |
2. | Pro Forma Adjustments |
(b | ) | Gross cash proceeds from the sale of trust units | $ | 350,000 | ||||
Repayment of outstanding borrowings on revolving credit facility | (216,500 | ) | ||||||
Payment of underwriting discount, structuring fee and other offering expenses | (30,000 | ) | ||||||
$ | 103,500 | |||||||
ENDURO F-42
Table of Contents
(c | ) | Reduction of oil and natural gas properties due to conveyance of Net Profits Interest: | ||||||
Historical cost of Underlying Properties | $ | 567,643 | ||||||
Less: Accumulated depletion, depreciation, and amortization | (1,174 | )(1) | ||||||
Total oil and natural gas properties of the Underlying Properties, net | 566,469 | |||||||
Less: Asset retirement obligations | (38,446 | ) | ||||||
Net property to be conveyed to the Trust | 528,023 | |||||||
Multiplied by Net Profits Interest | 80 | % | ||||||
Historical cost of oil and natural gas properties to be conveyed to the Trust | 422,418 | |||||||
Multiplied by Enduro Sponsor’s retained interest | 50 | % | ||||||
Reduction of oil and natural gas properties due to conveyance of Net Profits Interest to the Trust | $ | 211,209 | ||||||
(1) | The pro forma adjustment due to the conveyance of the Net Profits Interest on the accumulated depletion, depreciation, and amortization equates to 80% of $1,174, or $939 |
(d | ) | Gain on sale of Net Profits Interest calculated as follows: | ||||||
Gross cash proceeds from the sale of trust units | $ | 350,000 | ||||||
Less: Net book value of conveyed Net Profits Interest | (422,418 | ) | ||||||
Plus: Enduro Sponsor retained interest in trust units | 211,209 | |||||||
Payment of underwriting discounts, structuring fees and other offering expenses | (30,000 | ) | ||||||
Gain on sale of units | $ | 108,791 | ||||||
ENDURO F-43
Table of Contents
(i | ) | Decrease in oil and natural gas sales attributable to the Net Profits Interest: | ||||||
Oil | $ | (28,013 | ) | |||||
Natural gas | (13,515 | ) | ||||||
(j | ) | Decrease in operating expenses attributable to the Net Profits Interest: | ||||||
Lease operating | $ | (9,832 | ) | |||||
Production, ad valorem, and severance taxes | (3,228 | ) | ||||||
Gathering and transportation | (791 | ) | ||||||
The pro forma adjustments related to the decrease in oil and natural gas sales and the decrease in operating expenses represent the proportionate reduction in such amounts due to the conveyance of the Net Profits Interest and are not intended to represent the calculation of the Net Profits Interest payable to the Trust. | ||||||||
(k | ) | Reduce depreciation on assets conveyed to Trust | $ | (24,668 | ) |
ENDURO F-44
Table of Contents
9601 AMBERGLEN BLVD., SUITE 117 | 306 WEST SEVENTH STREET, SUITE 302 | 1000 LOUISIANA STREET, SUITE 625 | ||
AUSTIN, TEXAS78729-1106 | FORT WORTH, TEXAS 76102-4987 | HOUSTON, TEXAS 77002-5008 | ||
512-249-7000 | 817-336-2461 | 713-651-9944 | ||
www.cgaus.com |
Re: | Evaluation Summary | |||
Enduro Resource Partners LLC Interests | ||||
Total Proved Reserves | ||||
Texas and Louisiana Properties | ||||
As of December 31, 2010 | ||||
Pursuant to the Guidelines of the | ||||
Securities and Exchange Commission for | ||||
Reporting Corporate Reserves and | ||||
Future Net Revenue | ||||
ANNEX A-1-1
Table of Contents
Proved | ||||||||||||||||||
Proved | Developed | |||||||||||||||||
Developed | Non- | Proved | Total | |||||||||||||||
Producing | Producing | Undeveloped | Proved | |||||||||||||||
Net Reserves | ||||||||||||||||||
Oil | - Mbbl | 25.6 | 0.0 | 0.0 | 25.6 | |||||||||||||
Gas | - MMcf | 53,065.5 | 10,782.2 | 34,588.2 | 98,435.9 | |||||||||||||
Revenue | ||||||||||||||||||
Oil | - M | $ | 1,974.7 | 0.0 | 0.0 | 1,974.7 | ||||||||||||
Gas | - M | $ | 211,574.7 | 40,971.5 | 140,327.7 | 392,873.9 | ||||||||||||
Severance Taxes | - M | $ | 7,760.1 | 862.9 | 3,225.3 | 11,848.3 | ||||||||||||
Ad Valorem Taxes | - M | $ | 4,312.9 | 802.2 | 2,742.0 | 7,857.1 | ||||||||||||
Operating Expenses | - M | $ | 55,531.1 | 4,619.7 | 12,032.0 | 72,182.8 | ||||||||||||
Investments | - M | $ | 0.0 | 3,738.2 | 51,896.0 | 55,634.2 | ||||||||||||
Net Operating Income (BFIT) | - M | $ | 145,945.3 | 30,948.6 | 70,432.3 | 247,326.2 | ||||||||||||
Discounted at 10% | - M | $ | 90,223.2 | 19,610.5 | 20,391.0 | 130,224.8 |
ANNEX A-1-2
Table of Contents
ANNEX A-1-3
Table of Contents
Explanatory Comments for Summary Tables
Description of Table Information
Identity of Interest Evaluated
Property Description — Location
Reserve Classification and Development Status
Effective Date of Evaluation
(Columns) | ||
(1)(11)(21) | Calendar orFiscal years/months commencing on effective date. | |
(2)(3)(4) | Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts. | |
(5)(6)(7) | Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage. | |
(8) | Average (volume weighted)gross liquid price per barrel before deducting production-severance taxes. | |
(9) | Average (volume weighted)gross gas price per Mcf before deducting production-severance taxes. | |
(10) | Average (volume weighted)gross NGL price per barrel before deducting production-severance taxes. | |
(12) | Revenue derived from oil sales — column (5) times column (8). | |
(13) | Revenue derived from gas sales — column (6) times column (9). | |
(14) | Revenue derived from NGL sales — column (7) times column (10). | |
(15) | Revenue derived from hedge positions. | |
(16) | Total Revenue — sum of column (12) through column (15). | |
(17) | Production-Severance taxes deducted from gross oil, gas and NGL revenue. | |
(18) | Revenue after taxes — column (16) less column (17). | |
(19) | Ad Valorem taxes. | |
(20) | $/MCFE6 — is the total of column (22), column (25), column (26), and column (27) divided by MCF Gas Equivalent (“MCFE”). MCFE is net gas production column (6) plus net oil production column (5) converted to gas at one bbl oil per six Mcf gas plus net NGL production column (7) converted to gas at one bbl NGL per 3.9 Mcf gas. | |
(22) | Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS. | |
(23) | Averagegross wells. | |
(24) | Averagenet wells are gross wells times working interest. | |
(25) | Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair. | |
(26) | 3rd Party COPASare combined fixed rate administrative overhead charges for non-operated oil and gas producers. | |
(27) | Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs. |
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(28) | Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life. | |
(29)(30) | Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered. | |
(31) | Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates. |
DCF Profile | • The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile. | |
Life | • The economic life of the appraised property is noted in the lower right-hand corner of the table. | |
Footnotes | • Comments regarding the evaluation may be shown in the lower left-hand footnotes. | |
Price Deck | • A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes. |
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Methods Employed in the Estimation of Reserves
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Reserve Definitions and Classifications
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9601 AMBERGLEN BLVD., SUITE 117 | 306 WEST SEVENTH STREET, SUITE 302 | 1000 LOUISIANA STREET, SUITE 625 | ||
AUSTIN, TEXAS78729-1106 | FORT WORTH, TEXAS 76102-4987 | HOUSTON, TEXAS 77002-5008 | ||
512-249-7000 | 817-336-2461 | 713-651-9944 | ||
www.cgaus.com |
Re: | Evaluation Summary | |||
Enduro Resource Partners LLC Interests | ||||
Pro Forma Samson Non-Operated Acquisition of | ||||
Permian Properties by Enduro Resource Partners | ||||
Using Yearend SEC Prices as of December 31, 2010 | ||||
Proved Developed Producing Reserves | ||||
Texas and New Mexico Properties | ||||
As of December 31, 2010 | ||||
Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue | ||||
ANNEX A-2-1
Table of Contents
Proved | ||||||
Developed | ||||||
Producing | ||||||
Net Reserves | ||||||
Oil | - Mbbl | 3,047.8 | ||||
Gas | - MMcf | 10,780.7 | ||||
Revenue | ||||||
Oil | - M$ | 237,652.0 | ||||
Gas | - M$ | 54,600.6 | ||||
Severance Taxes | - M$ | 17,159.8 | ||||
Ad Valorem Taxes | - M$ | 7,301.9 | ||||
Operating Expenses | - M$ | 82,910.5 | ||||
Net Operating Income (BFIT) | - M$ | 184,880.4 | ||||
Discounted at 10% | - M$ | 84,954.0 |
ANNEX A-2-2
Table of Contents
ANNEX A-2-3
Table of Contents
Explanatory Comments for Summary Tables
Description of Table Information
Identity of Interest Evaluated
Property Description — Location
Reserve Classification and Development Status
Effective Date of Evaluation
(Columns) | ||
(1)(11)(21) | Calendar orFiscal years/months commencing on effective date. | |
(2)(3)4) | Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts. | |
(5)(6)(7) | Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage. | |
(8) | Average (volume weighted)gross liquid price per barrel before deducting production-severance taxes. | |
(9) | Average (volume weighted)gross gas price per Mcf before deducting production-severance taxes. | |
(10) | Average (volume weighted)gross NGL price per barrel before deducting production-severance taxes. | |
(12) | Revenue derived from oil sales — column (5) times column (8). | |
(13) | Revenue derived from gas sales — column (6) times column (9). | |
(14) | Revenue derived from NGL sales — column (7) times column (10). | |
(15) | Revenue derived from hedge positions. | |
(16) | Total Revenue — sum of column (12) through column (15). | |
(17) | Production-Severance taxes deducted from gross oil, gas and NGL revenue. | |
(18) | Revenue after taxes — column (16) less column (17). | |
(19) | Ad Valorem taxes. | |
(20) | $/MCFE6 — is the total of column (22), column (25), column (26), and column (27) divided by MCF Gas Equivalent (“MCFE”). MCFE is net gas production column (6) plus net oil production column (5) converted to gas at one bbl oil per six Mcf gas plus net NGL production column (7) converted to gas at one bbl NGL per 3.9 Mcf gas. | |
(22) | Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS. | |
(23) | Averagegross wells. | |
(24) | Averagenet wells are gross wells times working interest. | |
(25) | Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair. | |
(26) | 3rd Party COPASare combined fixed rate administrative overhead charges for non-operated oil and gas producers. | |
(27) | Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs. |
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(28) | Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life. | |
(29)(30) | Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered. | |
(31) | Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates. |
DCF Profile | • The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile. | |
Life | • The economic life of the appraised property is noted in the lower right-hand corner of the table. | |
Footnotes | • Comments regarding the evaluation may be shown in the lower left-hand footnotes. | |
Price Deck | • A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes. |
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Methods Employed in the Estimation of Reserves
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Reserve Definitions and Classifications
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9601 AMBERGLEN BLVD., SUITE 117 | 306 WEST SEVENTH STREET, SUITE 302 | 1000 LOUISIANA STREET, SUITE 625 | ||
AUSTIN, TEXAS78729-1106 | FORT WORTH, TEXAS 76102-4987 | HOUSTON, TEXAS 77002-5008 | ||
512-249-7000 | 817-336-2461 | 713-651-9944 | ||
www.cgaus.com |
Re: | Evaluation Summary | |||
Enduro Resource Partners LLC Interests | ||||
Pro Forma Conoco Phillips Acquisition of Permian Properties by Enduro Resource Partners Using Yearend SEC Prices as of December 31, 2010 | ||||
Total Proved Reserves | ||||
Texas and New Mexico Properties | ||||
As of December 31, 2010 | ||||
Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue | ||||
ANNEX A-3-1
Table of Contents
Proved | ||||||||||||||
Developed | Proved | Total | ||||||||||||
Producing | Undeveloped | Proved | ||||||||||||
Net Reserves | ||||||||||||||
Oil | - Mbbl | 9,131.2 | 379.2 | 9,510.4 | ||||||||||
Gas | - MMcf | 9,406.4 | 1,293.4 | 10,699.8 | ||||||||||
NGL | 182.7 | 0.0 | 182.7 | |||||||||||
Revenue | ||||||||||||||
Oil | - M$ | 692,325.1 | 28,715.3 | 721,040.4 | ||||||||||
Gas | - M$ | 51,748.6 | 7,496.6 | 59,245.2 | ||||||||||
NGL | 8,536.6 | 0.0 | 8,536.6 | |||||||||||
Severance Taxes | - M$ | 41,604.2 | 1,883.1 | 43,487.3 | ||||||||||
Ad Valorem Taxes | - M$ | 21,520.4 | 1,201.5 | 22,721.9 | ||||||||||
Operating Expenses | - M$ | 335,279.8 | 5,721.4 | 341,001.1 | ||||||||||
Other Deductions | - M$ | 719.8 | 44.3 | 764.1 | ||||||||||
Investments | - M$ | 0.0 | 6,000.0 | 6,000.0 | ||||||||||
Net Operating Income (BFIT) | - M$ | 353,486.3 | 21,361.5 | 374,847.8 | ||||||||||
Discounted at 10% | - M$ | 183,955.8 | 11,064.8 | 195,020.5 |
ANNEX A-3-2
Table of Contents
ANNEX A-3-3
Table of Contents
ANNEX A-3-4
Table of Contents
Explanatory Comments for Summary Tables
Description of Table Information
Identity of Interest Evaluated
Property Description — Location
Reserve Classification and Development Status
Effective Date of Evaluation
(Columns) | ||
(1)(11)(21) | Calendar orFiscal years/months commencing on effective date. | |
(2)(3)(4) | Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts. | |
(5)(6)(7) | Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage. | |
(8) | Average (volume weighted)gross liquid price per barrel before deducting production-severance taxes. | |
(9) | Average (volume weighted)gross gas price per Mcf before deducting production-severance taxes. | |
(10) | Average (volume weighted)gross NGL price per barrel before deducting production-severance taxes. | |
(12) | Revenue derived from oil sales — column (5) times column (8). | |
(13) | Revenue derived from gas sales — column (6) times column (9). | |
(14) | Revenue derived from NGL sales — column (7) times column (10). | |
(15) | Revenue derived from hedge positions. | |
(16) | Total Revenue — sum of column (12) through column (15). | |
(17) | Production-Severance taxes deducted from gross oil, gas and NGL revenue. | |
(18) | Revenue after taxes — column (16) less column (17). | |
(19) | Ad Valorem taxes. | |
(20) | $/MCFE6 — is the total of column (22), column (25), column (26), and column (27) divided by MCF Gas Equivalent (“MCFE”). MCFE is net gas production column (6) plus net oil production column (5) converted to gas at one bbl oil per six Mcf gas plus net NGL production column (7) converted to gas at one bbl NGL per 3.9 Mcf gas. | |
(22) | Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS. | |
(23) | Averagegross wells. | |
(24) | Averagenet wells are gross wells times working interest. | |
(25) | Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair. | |
(26) | 3rd Party COPASare combined fixed rate administrative overhead charges for non-operated oil and gas producers. | |
(27) | Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs. |
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(28) | Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life. | |
(29)(30) | Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered. | |
(31) | Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates. |
DCF Profile | • The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile. | |
Life | • The economic life of the appraised property is noted in the lower right-hand corner of the table. | |
Footnotes | • Comments regarding the evaluation may be shown in the lower left-hand footnotes. | |
Price Deck | • A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes. |
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Methods Employed in the Estimation of Reserves
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Reserve Definitions and Classifications
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9601 AMBERGLEN BLVD., SUITE 117 | 306 WEST SEVENTH STREET, SUITE 302 | 1000 LOUISIANA STREET, SUITE 625 | ||
AUSTIN, TEXAS78729-1106 | FORT WORTH, TEXAS76102-4987 | HOUSTON, TEXAS77002-5008 | ||
512-249-7000 | 817-336-2461 | 713-651-9944 | ||
www.cgaus.com |
Re: | Pro Forma Evaluation | Pursuant to the Guidelines of the | ||
Enduro Resource Partners LLC Interests | Securities and Exchange Commission for | |||
Total Proved Reserves for the Underlying Properties | Reporting Corporate Reserves and | |||
of Enduro Royalty Trust Total Controlled Interests | Future Net Revenue | |||
Texas, Louisiana and New Mexico Properties | ||||
Using Yearend SEC Prices as of December 31, 2010 |
Proved | ||||||||||||||||||
Proved | Developed | |||||||||||||||||
Developed | Non- | Proved | Total | |||||||||||||||
Producing | Producing | Undeveloped | Proved | |||||||||||||||
Net Reserves | ||||||||||||||||||
Oil | - Mbbl | 12,204.3 | 0.0 | 379.2 | 12,583.6 | |||||||||||||
Gas | - MMcf | 48,494.9 | 2,798.0 | 34,494.5 | 85,787.4 | |||||||||||||
NGL | - Mbbl | 182.7 | 0.0 | 0.0 | 182.7 | |||||||||||||
Revenue | ||||||||||||||||||
Oil | - M$ | 931,928.0 | 0.0 | 28,715.3 | 960,643.3 | |||||||||||||
Gas | - M$ | 221,463.6 | 11,360.0 | 142,714.5 | 375,538.1 | |||||||||||||
NGL | - M$ | 8,536.6 | 0.0 | 0.0 | 8,536.6 | |||||||||||||
Severance Taxes | - M$ | 63,314.4 | 229.1 | 4,997.1 | 68,540.5 | |||||||||||||
Ad Valorem Taxes | - M$ | 31,269.6 | 222.6 | 3,843.6 | 35,335.8 | |||||||||||||
Operating Expenses | - M$ | 455,929.7 | 944.1 | 17,263.6 | 474,137.3 | |||||||||||||
Investments | - M$ | 0.0 | 2,429.9 | 55,243.9 | 57,673.7 | |||||||||||||
Net Operating Income (BFIT) | - M$ | 611,414.5 | 7,534.4 | �� | 90,081.7 | 709,030.5 | ||||||||||||
Discounted at 10% | - M$ | 313,925.7 | 4,401.8 | 31,204.4 | 349,531.9 |
ANNEX B-1
Table of Contents
ANNEX B-2
Table of Contents
ANNEX B-3
Table of Contents
Explanatory Comments for Summary Tables
(Columns) | ||
(1)(11)(21) | Calendar orFiscal years/months commencing on effective date. | |
(2)(3)(4) | Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts. | |
(5)(6)(7) | Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage. | |
(8) | Average (volume weighted)gross liquid price per barrel before deducting production-severance taxes. | |
(9) | Average (volume weighted)gross gas price per Mcf before deducting production-severance taxes. | |
(10) | Average (volume weighted)gross NGL price per barrel before deducting production-severance taxes. | |
(12) | Revenue derived from oil sales — column (5) times column (8). | |
(13) | Revenue derived from gas sales — column (6) times column (9). | |
(14) | Revenue derived from NGL sales — column (7) times column (10). | |
(15) | Revenue derived from hedge positions. | |
(16) | Revenue not derived from column (12) through column (15); may include electrical sales revenue and saltwater disposal revenue. | |
(17) | Total Revenue — sum of column (12) through column (16). | |
(18) | Production-Severance taxes deducted from gross oil, gas and NGL revenue. | |
(19) | Ad Valorem taxes. | |
(20) | $/BOE6 — is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column (5) plus net gas production column (6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column (7) converted to oil at one bbl NGL per 0.65 bbls of oil. | |
(22) | Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS. | |
(23) | Averagegross wells. | |
(24) | Averagenet wells are gross wells times working interest. | |
(25) | Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair. | |
(26) | 3rd Party COPASare combined fixed rate administrative overhead charges for non-operated oil and gas producers. | |
(27) | Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs. |
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(28) | Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life. | |
(29)(30) | Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered. | |
(31) | Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates. |
DCF Profile | • The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns(30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile. | |
Life | • The economic life of the appraised property is noted in the lower right-hand corner of the table. | |
Footnotes | • Comments regarding the evaluation may be shown in the lower left-hand footnotes. | |
Price Deck | • A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes. |
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Methods Employed in the Estimation of Reserves
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Cawley, Gillespie & Associates, Inc. | Page 4 |
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Reserve Definitions and Classifications
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9601 AMBERGLEN BLVD., SUITE 117 AUSTIN, TEXAS78729-1106 512-249-7000 | 306 WEST SEVENTH STREET, SUITE 302 FORT WORTH, TEXAS 76102-4987 817-336-2461 www.cgaus.com | 1000 LOUISIANA STREET, SUITE 625 HOUSTON, TEXAS 77002-5008 713-651-9944 |
Proved | ||||||||||||||||||
Proved | Developed | |||||||||||||||||
Developed | Non- | Proved | Total | |||||||||||||||
Producing | Producing | Undeveloped | Proved | |||||||||||||||
Net Reserves | ||||||||||||||||||
Oil | − Mbbl | 5,352.0 | 0.0 | 190.0 | 5,541.8 | |||||||||||||
Gas | − MMcf | 26,153.6 | 1,554.0 | 15,314.9 | 43,058.0 | |||||||||||||
NGL | − Mbbl | 100.6 | 0.0 | 0.0 | 100.6 | |||||||||||||
Revenue | ||||||||||||||||||
Oil | − M$ | 408,630.2 | 0.0 | 14,384.5 | 423,014.7 | |||||||||||||
Gas | − M$ | 119,425.4 | 6,309.4 | 62,638.7 | 188,373.4 | |||||||||||||
NGL | − M$ | 4,702.8 | 0.0 | 0.0 | 4,702.8 | |||||||||||||
Severance Taxes | − M$ | 29,593.6 | 160.4 | 3,168.4 | 32,922.4 | |||||||||||||
Ad Valorem Taxes | − M$ | 14,049.6 | 123.0 | 1,799.6 | 15,972.2 | |||||||||||||
Operating Expenses | − M$ | 0.0 | 0.0 | 0.0 | 0.0 | |||||||||||||
Investments | − M$ | 0.0 | 0.0 | 0.0 | 0.0 | |||||||||||||
Net Operating Income (BFIT) | − M$ | 489,115.2 | 6,026.0 | 72,055.1 | 567,196.3 | |||||||||||||
Discounted at 10% | − M$ | 251,206.7 | 3,520.5 | 24,960.5 | 279,687.7 |
ANNEX C-1
Table of Contents
ANNEX C-2
Table of Contents
ANNEX C-3
Table of Contents
Explanatory Comments for Summary Tables
Description of Table Information
Identity of Interest Evaluated
Property Description — Location
Reserve Classification and Development Status
Effective Date of Evaluation
(Columns) | ||
(1)(11)(21) | Calendar orFiscal years/months commencing on effective date. | |
(2)(3)(4) | Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts. | |
(5)(6)(7) | Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage. | |
(8) | Average (volume weighted)gross liquid price per barrel before deducting production-severance taxes. | |
(9) | Average (volume weighted)gross gas price per Mcf before deducting production-severance taxes. | |
(10) | Average (volume weighted)gross NGL price per barrel before deducting production-severance taxes. | |
(12) | Revenue derived from oil sales — column (5) times column (8). | |
(13) | Revenue derived from gas sales — column (6) times column (9). | |
(14) | Revenue derived from NGL sales — column (7) times column (10). | |
(15) | Revenue derived from hedge positions. | |
(16) | Revenue not derived from column (12) through column (15); may include electrical sales revenue and saltwater disposal revenue. | |
(17) | Total Revenue — sum of column (12) through column (16). | |
(18) | Production-Severance taxes deducted from gross oil, gas and NGL revenue. | |
(19) | Ad Valorem taxes. | |
(20) | $/BOE6 — is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column (5) plus net gas production column (6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column (7) converted to oil at one bbl NGL per 0.65 bbls of oil. | |
(22) | Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS. | |
(23) | Averagegross wells. | |
(24) | Averagenet wells are gross wells times working interest. | |
(25) | Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair. | |
(26) | 3rd Party COPASare combined fixed rate administrative overhead charges for non-operated oil and gas producers. | |
(27) | Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs. |
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(28) | Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life. | |
(29)(30) | Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered. | |
(31) | Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates. |
DCF Profile | • The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile. | |
Life | • The economic life of the appraised property is noted in the lower right-hand corner of the table. | |
Footnotes | • Comments regarding the evaluation may be shown in the lower left-hand footnotes. | |
Price Deck | • A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes. |
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Methods Employed in the Estimation of Reserves
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Reserve Definitions and Classifications
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Item 13. | Other Expenses of Issuance and Distribution. |
Registration fee | $ | 43,538 | ||
FINRA filing fee | 38,000 | |||
NYSE listing fee | * | |||
Printing and engraving expenses | * | |||
Fees and expenses of legal counsel | * | |||
Accounting fees and expenses | * | |||
Transfer agent and registrar fees | * | |||
Trustee fees and expenses | * | |||
Miscellaneous | * | |||
Total | $ | * |
* | To be provided by amendment |
Item 14. | Indemnification of Directors and Officers. |
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Item 15 | Recent Sales of Unregistered Securities. |
Item 16. | Exhibits and Financial Statement Schedules. |
Exhibit | ||||||
Number | Description | |||||
1 | .1** | — | Form of Underwriting Agreement. | |||
3 | .1* | — | Certificate of Formation of Enduro Resource Partners LLC. | |||
3 | .2** | — | Second Amended and Restated Limited Liability Company Agreement of Enduro Resource Partners LLC. | |||
3 | .3* | — | Certificate of Trust of Enduro Royalty Trust. | |||
3 | .4* | — | Trust Agreement. | |||
3 | .5** | — | Form of Amended and Restated Trust Agreement. | |||
5 | .1** | — | Opinion of Richards, Layton & Finger, P.A. relating to the validity of the trust units. | |||
8 | .1** | — | Opinion of Latham & Watkins LLP relating to tax matters. | |||
10 | .1** | — | Form of Net Profits Interest Conveyance. | |||
10 | .2** | — | Form of Administrative Services Agreement. | |||
10 | .3** | — | Form of Registration Rights Agreement. | |||
21 | .1* | — | Subsidiaries of Enduro Resource Partners LLC. | |||
23 | .1* | — | Consent of Ernst & Young, LLP — Fort Worth, Texas office. | |||
23 | .2* | — | Consent of Ernst & Young, LLP — Tulsa, Oklahoma office. | |||
23 | .3** | — | Consent of Richards, Layton & Finger, P.A. (contained in Exhibit 5.1). | |||
23 | .4** | — | Consent of Latham & Watkins LLP (contained in Exhibit 8.1). | |||
23 | .5* | — | Consent of Cawley, Gillespie & Associates, Inc. | |||
24 | .1* | — | Powers of Attorney (included on the signature pages of this registration statement). | |||
99 | .1* | — | Summary Reserve Reports of Cawley, Gillespie & Associates, Inc. (included asAnnexes A-1,A-2,A-3, B and C to the prospectus). |
* | Filed herewith. | |
** | To be filed by amendment. |
Item 17. | Undertakings. |
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By: | /s/ Jon S. Brumley |
Signature | Title | |||
/s/ Jon S. Brumley Jon S. Brumley | President, Chief Executive Officer and Manager (Principal Executive Officer) | |||
/s/ Kimberly A. Weimer Kimberly A. Weimer | Vice President, Chief Financial Officer (Principal Financial and Accounting Officer) | |||
/s/ John W. Arms John W. Arms | Manager | |||
/s/ David Leuschen David Leuschen | Manager | |||
/s/ Pierre F. Lapeyre, Jr. Pierre F. Lapeyre, Jr. | Manager | |||
/s/ N. John Lancaster N. John Lancaster | Manager | |||
/s/ I. Jon Brumley I. Jon Brumley | Manager |
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By: | /s/ Jon S. Brumley |
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Exhibit | ||||||
Number | Description | |||||
1 | .1** | — | Form of Underwriting Agreement. | |||
3 | .1* | — | Certificate of Formation of Enduro Resource Partners LLC. | |||
3 | .2** | — | Second Amended and Restated Limited Liability Company Agreement of Enduro Resource Partners LLC. | |||
3 | .3* | — | Certificate of Trust of Enduro Royalty Trust. | |||
3 | .4* | — | Trust Agreement. | |||
3 | .5** | — | Form of Amended and Restated Trust Agreement. | |||
5 | .1** | — | Opinion of Richards, Layton & Finger, P.A. relating to the validity of the trust units. | |||
8 | .1** | — | Opinion of Latham & Watkins LLP relating to tax matters. | |||
10 | .1** | — | Form of Net Profits Interest Conveyance. | |||
10 | .2** | — | Form of Administrative Services Agreement. | |||
10 | .3** | — | Form of Registration Rights Agreement. | |||
21 | .1* | — | Subsidiaries of Enduro Resource Partners LLC. | |||
23 | .1* | — | Consent of Ernst & Young, LLP — Fort Worth, Texas office. | |||
23 | .2* | — | Consent of Ernst & Young, LLP — Tulsa, Oklahoma office. | |||
23 | .3** | — | Consent of Richards, Layton & Finger, P.A. (contained in Exhibit 5.1). | |||
23 | .4** | — | Consent of Latham & Watkins LLP (contained in Exhibit 8.1). | |||
23 | .5* | — | Consent of Cawley, Gillespie & Associates, Inc. | |||
24 | .1* | — | Powers of Attorney (included on the signature pages of this registration statement). | |||
99 | .1* | — | Summary Reserve Reports of Cawley, Gillespie & Associates, Inc. (included asAnnexes A-1,A-2,A-3, B and C to the prospectus). |
* | Filed herewith. | |
** | To be filed by amendment. |