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Delaware | 1311 | 20-4745690 | ||
(State or Other Jurisdiction of Incorporation or Organization) | (Primary Standard Industrial Classification Code Number) | (I.R.S. Employer Identification Number) |
George G. Young III Haynes and Boone, LLP 1221 McKinney, Suite 2100 Houston, Texas 77010 Telephone: (713) 547-2081 Fax: (713) 236-5699 | James M. Prince Dan A. Fleckman Vinson & Elkins, L.L.P. 1001 Fannin Street, Suite 2300 Houston, Texas 77002 Telephone: (713) 758-2222 |
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The information in this prospectus is not complete and may be changed. We may not sell these securities 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. |
• | We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the minimum quarterly distribution rate under our cash distribution policy. | |
• | If oil or gas prices decline significantly for a prolonged period, we may lower our distributions or not pay distributions at all. | |
• | Unless we replace the oil and gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders. | |
• | Our development operations will require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves. | |
• | We may incur substantial debt in the future. This debt may restrict our ability to make distributions. | |
• | EnerVest Management Partners, Ltd. controls our general partner, which has sole responsibility for conducting our business and managing our operations. EnerVest, EV Investors and EnCap have conflicts of interest, which may permit them to favor their own interests to your detriment. | |
• | Cost reimbursements due to our general partner and its affiliates for services provided may be substantial and could reduce our cash available for distribution to you. | |
• | Holders of our common units have limited voting rights and are not entitled to elect our general partner or the members of the board of directors of its general partner. | |
• | Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent. | |
• | Control of our general partner may be transferred to a third party without unitholder consent. |
• | You will experience immediate and substantial dilution of $8.75 in tangible net book value per common unit. |
• | You may be required to pay taxes on income from us even if you do not receive any cash distributions from us. |
Per Common Unit | Total | |||||||
Initial public offering price | $ | $ | ||||||
Underwriting discount(1) | $ | $ | ||||||
Proceeds, before expenses, to EV Energy Partners, L.P. | $ | $ |
(1) | Excludes a financial advisory fee of 0.5% of the gross proceeds of this offering, or $390,000 assuming an offering price of $20.00 per common unit, payable by us to A.G. Edwards & Sons, Inc. for evaluation, analysis and structuring of our partnership and its initial public offering. Please read “Underwriting” beginning on page 165. |
A.G. Edwards | Raymond James |
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F-1 | ||||||||
Appendix A — Agreement of Limited Partnership of EV Energy Partners, L.P. | ||||||||
Appendix B — Glossary of Terms | ||||||||
Appendix C — Report of Cawley, Gillespie & Associates, Inc. | ||||||||
Long-Term Incentive Plan | ||||||||
Gas Purchase Agreement | ||||||||
Term sheet | ||||||||
Base Contract for Purchase of Natural Gas-EOG | ||||||||
Base Contract for Sale and Purchase of Natural Gas | ||||||||
Base Contract for Sale and Purchase of Natural Gas | ||||||||
List of Subsidiaries | ||||||||
Consent of Cawley, Gillespie & Associates, Inc. | ||||||||
Consent of Deloitte & Touche LLP | ||||||||
Consent of Nominee for Director for Mr. Peterson | ||||||||
Consent of Nominee for Director for Mr. Lindahl III |
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Estimated Net Proved | ||||||||||||||||||||||||||||||||
Reserves (Bcfe) | Standardized | 2005 Production | Producing Wells | |||||||||||||||||||||||||||||
Developed | Undeveloped | Total | Measure(1) | MMcfe | % | Gross | Net | |||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||
Appalachian Basin | 28.8 | 5.8 | 34.6 | $ | 116.0 | 1,871 | 69 | 841 | 716 | |||||||||||||||||||||||
Northern Louisiana | 16.6 | 0.0 | 16.6 | 45.2 | 850 | 31 | 1,112 | 1,112 | ||||||||||||||||||||||||
Total | 45.4 | 5.8 | 51.2 | $ | 161.2 | 2,721 | 100 | 1,953 | 1,828 | |||||||||||||||||||||||
(1) | Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities.” Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure. |
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• | Continually maintain an inventory of proved undeveloped drilling locations, which are sufficient, when drilled and completed, to allow us to maintain our production levels for approximately three years; | |
• | Replace and increase our reserves and production over the long term by pursuing acquisitions throughout the continental United States of long-lived producing oil or gas properties with low decline rates, predictable production profiles and relatively low risk drilling opportunities; | |
• | Maintain low levels of indebtedness to permit us to finance opportunistic acquisitions; | |
• | Reduce exposure to commodity price risk through hedging; | |
• | Retain control over the operation of a substantial portion of our production; and | |
• | Focus on controlling the costs of our operations. |
• | We have a substantial inventory of low risk, proved undeveloped drilling locations; | |
• | Our properties have a long reserve life, with predictable decline rates; | |
• | Our management is experienced in oil and gas acquisitions and operations; | |
• | We will have no long-term debt immediately following the closing of the offering, which will allow us more flexibility in financing acquisitions; and |
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• | Our relationship with EnerVest will provide us with a wide breadth of operational, technical, risk management and other expertise across a wide geographical range, which will assist us in evaluating acquisition, development and marketing opportunities. |
• | Our ability to pursue our business plan and make distributions to unitholders will depend upon our maintaining or increasing our revenues and cash flows, which will be subject to the following risks: |
• | a reduction in the prices we receive for our production, which prices have been and are expected to continue to be volatile and affected by factors beyond our control such as weather, economic conditions, availability of alternative fuels and government regulations; | |
• | the costs we must reimburse EnerVest to operate our wells; and | |
• | whether we incur substantial costs to comply with environmental laws or to remediate or clean up environmental contamination. |
• | Unless we replace the oil and gas reserves we produce, our production and revenues will decline, which will adversely affect our ability to pursue our business plans and make distributions to unitholders. Risks associated with our ability to replace our reserves include: |
• | our ability to acquire oil and gas properties, including our ability to evaluate the value of an acquisition and compete with other purchasers of properties; | |
• | our ability to maintain production and replace reserves by development drilling, including risks related to failure to discover reserves in commercial quantities, weather conditions and catastrophic events such as fires or explosions; | |
• | our ability to attract financing for our acquisitions and drilling activities; and | |
• | the availability of equipment and services necessary to drill our wells, and the costs we must incur to drill wells and otherwise develop our non-producing reserves. |
• | We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the minimum quarterly distribution rate under our cash distribution policy. | |
• | The assumptions underlying the forecast of cash available for distribution we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. | |
• | The estimated oil and gas reserve quantities and future production rates set forth in this prospectus are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves. | |
• | As a result of our hedging activities we may not fully participate in increases in commodity prices, which would reduce our revenues and cash available for distribution to unitholders from amounts we would receive if we had not hedged. |
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• | EnerVest controls our general partner, which has sole responsibility for conducting our business and managing our operations. EnerVest, EV Investors and the EnCap partnerships, which will be limited partners of our general partner, will have conflicts of interest with us, which may permit them to favor their own interests to your detriment. | |
• | Neither EnerVest nor EnCap is limited in its ability to compete with us for acquisition or drilling opportunities. This could cause conflicts of interest and limit our ability to acquire additional oil and gas properties which in turn could adversely affect our ability to maintain production over the long term, and our results of operations and cash available for distribution to our unitholders. | |
• | Cost reimbursements due to our general partner and its affiliates for services provided may be substantial and could reduce our cash available for distribution to you. | |
• | Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units. | |
• | Our partnership agreement restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. | |
• | Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or holders of our common units and subordinated units. This may result in lower distributions to holders of our common units in certain situations. | |
• | Holders of our common units have limited voting rights and are not entitled to elect our general partner or the members of the board of directors of its general partner. | |
• | Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent. | |
• | Our partnership restricts the voting rights of unitholders owning 20% or more of our common units. | |
• | Control of our general partner may be transferred to a third party without unitholder consent. |
• | You will experience immediate and substantial dilution of $8.75 in tangible net book value per common unit. |
• | We may issue additional units without your approval, which would dilute your existing ownership interests. | |
• | Unitholders may have limited liquidity for their units, a trading market may not develop for the units and you may not be able to resell your units at the initial public offering price. |
• | Our tax treatment depends on our status as a partnership for federal income tax purposes and not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service treats us as a corporation or we become subject to a material amount of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution to our unitholders. |
• | The Internal Revenue Service could contest our federal income tax positions, which may adversely affect the market for our common units, and the cost of any Internal Revenue Service contest will reduce our cash available for distribution to our unitholders. | |
• | You may be required to pay taxes on income from us even if you do not receive any cash distributions from us. | |
• | Tax gain or loss on disposition of common units could be more or less than expected. |
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• | Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them. | |
• | We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units. | |
• | The sale or exchange of 50% or more of our capital and profits interests during any12-month period will result in the termination of our partnership for federal income tax purposes. | |
• | Unitholders may be subject to state and local taxes and tax return filing requirements in states where they do not live as a result of investing in our common units. |
• | purchases and sales of oil and gas properties and other acquisitions and dispositions, including whether or not to offer us acquisitions that EnerVest determines to be suitable for the EnerVest partnerships; | |
• | the manner in which our business is operated; | |
• | the level of our borrowings; | |
• | the amount, nature and timing of our capital expenditures; and | |
• | the amount of cash reserves necessary or appropriate to satisfy general, administrative and other expenses and debt service requirements, and otherwise provide for the proper conduct of our business. |
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• | EnerVest Production Partners, a direct and indirect wholly-owned subsidiary of EnerVest, owned the Northern Louisiana properties; |
• | EnerVest WV, a partnership owned by EnerVest, as general partner, and an institutional investor, as limited partner, owned the Appalachian properties in the West Virginia area; and |
• | CGAS, which was owned by an EverVest partnership, owned the Appalachian properties in the Ohio area and exploration properties and deep wells that will not be transferred to us. |
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• | EnerVest contributed its ownership interests in EnerVest Production Partners and EnerVest WV to EV Properties in exchange for a general and limited partnership interest in EV Properties; |
• | The EnCap partnerships contributed a net $16 million in cash to EV Properties and EV Properties purchased the partnership interests in EnerVest WV owned by the institutional investor for $16 million; and |
• | EV Investors acquired an interest in EV Properties. |
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• | EnerVest, EV Investors and the EnCap partnerships will transfer ownership of EV Properties to us directly, and indirectly as a capital contribution to our general partner, which will contribute the interest it receives in EV Properties to us in exchange for units representing its 2% general partner interest in us; and |
• | CGAS will transfer the Ohio area properties to us by forming EV Clinton Properties, L.P., transferring the properties to EV Clinton Properties and then transferring the partnership interests in EV Clinton Properties to us. |
• | EnerVest will receive a 71.25% interest in our general partner, EV Investors will receive a 5.0% interest in our general partner and the EnCap partnerships will receive a 23.75% interest in our general partner; |
• | Our general partner will receive a 2% general partner interest and all of the incentive distribution rights; |
• | EnerVest will receive 163,645 common units and 809,975 subordinated units, and a cash payment of $16.53 million; | |
• | EV Investors will receive 155,000 subordinated units; | |
• | The EnCap partnerships will receive 88,117 common units and 436,141 subordinated units, and a cash payment of $8.90 million; and | |
• | CGAS will receive 343,238 common units and 1,698,884 subordinated units, and a cash payment of $34.76 million. EnerVest is the general partner of the EnerVest partnerships that own CGAS, and has a 25.75% interest in those partnerships. |
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Number of Units | % | |||||||
Common units: | ||||||||
Public | 3,900,000 | 50.3% | ||||||
Former owners of our predecessors: | ||||||||
EnerVest | 163,645 | 2.1% | ||||||
CGAS | 343,238 | 4.4% | ||||||
EnCap partnerships | 88,117 | 1.1% | ||||||
Total common units | 4,495,000 | 58.0% | ||||||
Subordinated units: | ||||||||
Former owners of our predecessors: | ||||||||
EnerVest | 809,975 | 10.5% | ||||||
EV Investors | 155,000 | 2.0% | ||||||
CGAS | 1,698,884 | 21.9% | ||||||
EnCap partnerships | 436,141 | 5.6% | ||||||
Total subordinated units | 3,100,000 | 40.0% | ||||||
General partner interest(2): | ||||||||
Implied general partner units | 155,000 | 2.0% | ||||||
Total units | 7,750,000 | 100.0% | ||||||
(1) | Assumes the underwriter’s over-allotment option to purchase up to 585,000 common units is not exercised. For information on how the underwriter’s option to purchase additional common units and issue such units to the public will affect the ownership structure, please read “Selling Unitholders” on page 163. |
(2) | Our general partner has a 2% interest in us. This interest is not represented by units. The 155,000 implied units in this table represents 2% of the total units that would be outstanding if the general partner’s interest in us was represented by units. |
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Common units offered to the public | 3,900,000 common units. If the underwriters exercise their option to purchase additional units in full, we will issue 585,000 additional common units to the public and redeem 585,000 common units from EnerVest, CGAS and the EnCap partnerships. Please read ‘‘Selling Unitholders” on page 163. |
Units outstanding after this offering | 4,495,000 common units and 3,100,000 subordinated units, representing 59.2% and 40.8%, respectively, of our limited partner interests. | |
Use of proceeds | We estimate that we will receive net proceeds of approximately $72.5 million from the sale of 3,900,000 common units, assuming an offering price of $20.00 per unit after deducting underwriting discounts but before paying offering expenses. We intend to use the estimated net proceeds from this offering as follows: | |
• We will pay an aggregate of $60.2 million to the former owners of our predecessors as part of the consideration for the interests in our predecessors contributed to us; | ||
• We will use $10.3 million to repay in full the indebtedness incurred by one of our predecessors to purchase our Northern Louisiana properties; and |
• We estimate that we will pay $2.0 million to EnerVest to reimburse it for out of pocket legal, accounting, printing and other fees and expenses of the offering incurred by it. |
If the underwriters’ option to purchase additional common units is exercised, we will use the net proceeds received from the underwriters’ exercise of their option to redeem the same number of common units from EnerVest, CGAS and the EnCap partnerships. |
Cash distributions | We intend to make minimum quarterly distributions of $0.40 per common unit per quarter ($1.60 per common unit on an annualized basis) to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We intend to retain substantial cash reserves to finance the capital expenditures necessary to maintain our existing levels of production. Our ability to pay cash distributions at this minimum quarterly distribution rate is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 57. |
Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement and in the glossary of terms attached as Appendix B. |
All of our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in the glossary, and generally means amounts we receive |
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from operating sources, such as sales of our oil and gas production, less operating expenditures, such as production costs and taxes and less estimated average maintenance capital expenditures, which are generally amounts we estimate we will spend in the future to maintain our production levels over the long term. Capital surplus is defined in the glossary and generally means amounts we receive from non-operating sources such as sales of properties and issuances of debt or equity securities or borrowings, other than short term working capital borrowings. We distribute operating surplus differently than capital surplus. We do not expect to make any distributions of available cash from capital surplus. Our partnership agreement requires that we distribute all of our available cash from operating surplus each quarter in the following manner: |
• | first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.40 plus any arrearages from prior quarters; | |
• | second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.40; and | |
• | third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.46. |
If cash distributions to our unitholders from operating surplus exceed $0.46 per common unit in any quarter, our general partner will receive, in addition to distributions on its 2% general partner interest, increasing percentages, up to 23%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “How We Will Make Cash Distributions” beginning on page 47. |
The amount of pro forma available cash generated during the year ended December 31, 2005 would have been sufficient to allow us to pay the full minimum quarterly distributions on all of our common units and 32% of the minimum quarterly distribution on our subordinated units during that period. Please read “Our Cash Distribution Policy and Restrictions on Distributions — Pro Forma Financial Information and Financial Forecast” beginning on page 60. |
We believe that, based on the Statement of Forecasted Results of Operations and Cash Flows for the Twelve Months Ending June 30, 2007, included under the caption “Our Cash Distribution Policy and Restrictions on Distributions — Pro Forma Financial Information and Financial Forecast” beginning on page 60, we will have sufficient cash available from operating surplus for distribution to make cash distributions for the four quarters ending June 30, 2007 at the initial distribution rate of $0.40 per unit per quarter ($1.60 per common unit on an annualized basis) on all common units and subordinated units. |
Subordinated units | Following this offering, EnerVest, EV Investors, CGAS and the EnCap partnerships will own all of our subordinated units. The principal difference between our common units and subordinated |
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units is that in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution from operating surplus of $0.40 per unit only after the common units have received the minimum quarterly distribution from operating surplus plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Accordingly, the holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages. The subordination period generally will end if we have earned and paid from operating surplus at least $1.60 on each outstanding unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2011. The subordination period may also end on or after three consecutive non-overlapping four quarter periods ending on or after June 30, 2009, if certain financial tests are met as described below. The subordination period will not end prior to June 30, 2009 under any circumstances other than upon the removal of our general partner other than for cause and the units held by our general partner and its affiliates are not voted in favor of such removal. |
When the subordination period ends, all remaining subordinated units will convert into common units on aone-for-one basis, and the common units will no longer be entitled to arrearages. |
Early conversion of subordinated units | If we have earned and paid from operating surplus at least $1.60 on each outstanding unit and paid to the general partner the amount representing its general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2009, 25% of the subordinated units will convert into common units at the end of such period. In addition, if we have earned and paid from operating surplus at least $1.60 on each outstanding unit and paid to the general partner the amount representing its general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2010, an additional 25% of the subordinated units will convert into common units at the end of such period. The early conversion of the second 25% of the subordinated units may not occur until at least one year after the early conversion of the first 25% of the subordinated units. If our subordinated units are owned by more than one person, a portion of the subordinated units owned by each person will be converted pro rata based on the number of subordinated units owned. |
In addition to the early conversion described above, if we have earned and paid from operating surplus at least $2.00 (125% of the annualized minimum quarterly distribution) on each outstanding unit and paid to the general partner the amount representing its general partner interest for any two consecutive, non-overlapping four quarter periods ending on or after June 30, 2009, all of the outstanding subordinated units will convert into common units at the end of such period. |
Class B units | Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled, for each of |
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the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B units equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. Please read “How We Will Make Cash Distributions — Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels” beginning on page 55. |
Issuance of additional units | We can issue an unlimited number of units without the consent of our unitholders. Please read “Units Eligible for Future Sale” beginning on page 145 and “The Partnership Agreement — Issuance of Additional Securities” beginning on page 135. |
Limited voting rights | Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or EV Management, its general partner, or the directors of EV Management on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering our general partner, its owners and their affiliates, and the EnCap partnerships will own an aggregate of 48.7% of our common and subordinated units. This will give our general partner the practical ability to prevent its involuntary removal. Please read “The Partnership Agreement — Voting Rights” beginning on page 133. |
Limited call right | If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units. The purchase price of common units will be the greater of, |
• the average offering price of the common units for the 20 trading days preceding the purchase, and |
• the highest price paid for common units by our general partner or its affiliates during the 90 days before the purchase. |
Estimated ratio of taxable income to distributions | We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2008, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.60 per unit, we estimate that your average allocable federal taxable income per year will be no more than $ per unit. |
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Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” beginning on page 149 for the basis of this estimate. |
Material tax consequences | For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences” beginning on page 146 for the basis of this estimate. |
Exchange listing | We have applied to list our common units on the NASDAQ National Market under the symbol ‘‘EVEP.” |
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Pro Forma | ||||||||||||||||||||||||||||
EV Energy Partners, L.P. | ||||||||||||||||||||||||||||
Combined Predecessors (1) | Three | |||||||||||||||||||||||||||
Three Months | Months | |||||||||||||||||||||||||||
Ended | Year Ended | Ended | ||||||||||||||||||||||||||
Year Ended December 31, | March 31, | December 31, | March 31, | |||||||||||||||||||||||||
2003(2) | 2004 | 2005(3) | 2005 | 2006 | 2005 | 2006 | ||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||||
Natural gas and oil revenues | $ | 10,370 | $ | 28,336 | $ | 45,148 | $ | 8,362 | $ | 11,669 | $ | 24,493 | $ | 5,622 | ||||||||||||||
Realized gain (loss) on natural gas swaps | (242 | ) | (1,890 | ) | (7,194 | ) | 444 | (190 | ) | (3,952 | ) | 157 | ||||||||||||||||
Transportation and marketing-related revenues(4) | 3,443 | 3,438 | 6,225 | 1,003 | 1,679 | 6,104 | 1,660 | |||||||||||||||||||||
Total revenues(4) | 13,571 | 29,884 | 44,179 | 9,809 | 13,158 | 26,645 | 7,439 | |||||||||||||||||||||
Operating Costs and Expenses: | ||||||||||||||||||||||||||||
Lease operating expenses(4) | 3,466 | 6,615 | 7,236 | 1,460 | 1,799 | 4,354 | 1,102 | |||||||||||||||||||||
Purchased gas cost(4) | 2,933 | 3,003 | 5,660 | 848 | 1,557 | 5,659 | 1,557 | |||||||||||||||||||||
Production taxes | 65 | 119 | 292 | 26 | 53 | 224 | 39 | |||||||||||||||||||||
Asset retirement obligations accretion expense | 67 | 160 | 171 | 43 | 44 | 46 | 13 | |||||||||||||||||||||
Exploration expenses(5) | 1,338 | 1,281 | 2,539 | 878 | 58 | — | — | |||||||||||||||||||||
Dry hole costs(5) | — | 440 | 530 | — | 149 | — | — | |||||||||||||||||||||
Impairment of unproved properties(5) | — | 1,415 | 2,041 | — | — | — | — | |||||||||||||||||||||
Depreciation, depletion and amortization | 1,837 | 4,135 | 4,409 | 1,020 | 1,105 | 4,312 | 1,141 | |||||||||||||||||||||
General and administrative expenses(6) | 1,069 | 1,061 | 899 | 341 | 640 | 1,672 | 643 | |||||||||||||||||||||
Management fees | 69 | 94 | 117 | 28 | 35 | — | — | |||||||||||||||||||||
Total operating costs and expenses, net(4) | 10,844 | 18,323 | 23,894 | 4,644 | 5,440 | 16,267 | 4,495 | |||||||||||||||||||||
Gain on sale of other property | 30 | 130 | — | — | — | — | — | |||||||||||||||||||||
Operating income | 2,757 | 11,691 | 20,285 | 5,165 | 7,718 | 10,378 | 2,944 |
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Pro Forma | ||||||||||||||||||||||||||||
EV Energy Partners, L.P. | ||||||||||||||||||||||||||||
Combined Predecessors (1) | Three | |||||||||||||||||||||||||||
Three Months | Months | |||||||||||||||||||||||||||
Ended | Year Ended | Ended | ||||||||||||||||||||||||||
Year Ended December 31, | March 31, | December 31, | March 31, | |||||||||||||||||||||||||
2003(2) | 2004 | 2005(3) | 2005 | 2006 | 2005 | 2006 | ||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Other Income (Expense), net: | ||||||||||||||||||||||||||||
Interest and financing expense — third party | (126 | ) | (158 | ) | (625 | ) | (37 | ) | (184 | ) | — | — | ||||||||||||||||
Interest and financing expense — related party | — | (169 | ) | (7 | ) | — | — | — | — | |||||||||||||||||||
Other income, net | 360 | 209 | 204 | (174 | ) | 143 | 4 | 3 | ||||||||||||||||||||
Total other income (expense), net | 234 | (118 | ) | (428 | ) | (211 | ) | (41 | ) | 4 | 3 | |||||||||||||||||
Income before income tax provision | 2,991 | 11,573 | 19,857 | 4,954 | 7,677 | 10,382 | 2,947 | |||||||||||||||||||||
Income tax provision | 317 | 2,521 | 5,349 | 1,421 | 1,545 | — | — | |||||||||||||||||||||
Equity earnings in investments | 3 | (621 | ) | 565 | 389 | 90 | — | — | ||||||||||||||||||||
Net income | 2,677 | 8,431 | 15,073 | 3,922 | 6,222 | 10,382 | 2,947 | |||||||||||||||||||||
Other comprehensive income (loss)(2) | — | (100 | ) | (4,168 | ) | (3,167 | ) | 5,638 | — | — | ||||||||||||||||||
Comprehensive income(2) | $ | 2,677 | $ | 8,331 | $ | 10,905 | $ | 755 | $ | 11,860 | $ | 10,382 | $ | 2,947 | ||||||||||||||
Cash Flow Data: | ||||||||||||||||||||||||||||
Net cash provided by operating activities | $ | 3,382 | $ | 16,704 | $ | 27,979 | $ | 6,310 | $ | 5,906 | N/A | N/A | ||||||||||||||||
Net cash (used in) investing activities | (8,476 | ) | (3,821 | ) | (17,797 | ) | (12,474 | ) | (1,444 | ) | N/A | N/A | ||||||||||||||||
Net cash provided by (used in) financing activities | 6,019 | (12,160 | ) | (4,695 | ) | 5,330 | (9,011 | ) | N/A | N/A | ||||||||||||||||||
Other Financial Information: | ||||||||||||||||||||||||||||
Adjusted EBITDA(7) | $ | 6,332 | $ | 18,580 | $ | 30,744 | $ | 7,321 | $ | 9,307 | $ | 14,740 | $ | 4,101 | ||||||||||||||
Capital expenditures(8) | 10,436 | 5,704 | 16,889 | 12,358 | 1,419 | 13,030 | 849 |
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Pro Forma EV Energy | ||||||||||||||||
Combined Predecessors (1) | Partners, L.P. | |||||||||||||||
December 31, | March 31, | March 31, | ||||||||||||||
2004 | 2005 | 2006 | 2006 | |||||||||||||
(In thousands) | ||||||||||||||||
Balance Sheet Data (at period end): | ||||||||||||||||
Current assets: | ||||||||||||||||
Cash and cash equivalents | $ | 1,672 | $ | 7,159 | $ | 2,610 | $ | 90 | ||||||||
Accounts receivable — gas and oil sales(4) | 8,560 | 8,798 | 6,679 | 3,357 | ||||||||||||
Due from affiliates(9) | — | 96 | — | — | ||||||||||||
Other current assets | 1,132 | 3,083 | 2,469 | 2,272 | ||||||||||||
Total current assets | 11,364 | 19,136 | 11,758 | 5,719 | ||||||||||||
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization | 46,484 | 57,037 | 57,561 | 87,847 | ||||||||||||
Other property, plant and equipment, net of accumulated depreciation | 687 | 563 | 514 | 213 | ||||||||||||
Other assets | 266 | 1,427 | 3,500 | 1,087 | ||||||||||||
Total assets | $ | 58,801 | $ | 78,163 | $ | 73,333 | $ | 94,866 | ||||||||
Current liabilities: | ||||||||||||||||
Accounts payable and accrued liabilities | $ | 3,262 | $ | 5,968 | $ | 2,662 | $ | 1,339 | ||||||||
Due to affiliates(4)(9) | 3,324 | 6,387 | 4,362 | 3,923 | ||||||||||||
Commodity hedge liability — related party(10) | — | 5,228 | 1,486 | 26 | ||||||||||||
Advances — related party | 1,136 | — | — | — | ||||||||||||
Commodity hedge liability — third party | 154 | 954 | 172 | 172 | ||||||||||||
Current income tax liability | — | 1,171 | 2,623 | — | ||||||||||||
Other current liabilities | 394 | 70 | 241 | — | ||||||||||||
Total current liabilities | 8,270 | 19,778 | 11,546 | 5,460 | ||||||||||||
Asset retirement obligations | 2,050 | 2,752 | 2,806 | 2,192 | ||||||||||||
Long-term debt | 2,850 | 10,500 | 10,350 | — | ||||||||||||
Deferred income tax liability | 4,416 | 4,205 | 4,723 | — | ||||||||||||
Long-term commodity hedge liability — related party(10) | — | 19 | — | — | ||||||||||||
Total liabilities | 17,586 | 37,254 | 29,425 | 7,652 | ||||||||||||
Owners’ equity, excluding accumulated other comprehensive loss | 41,315 | 45,177 | 42,538 | 84,870 | ||||||||||||
Accumulated other comprehensive loss | (100 | ) | (4,268 | ) | 1,370 | 2,344 | ||||||||||
Total owners’ equity | 41,215 | 40,909 | 43,908 | 87,214 | ||||||||||||
Total liabilities and owners’ equity | $ | 58,801 | $ | 78,163 | $ | 73,333 | $ | 94,866 | ||||||||
(1) | Our predecessors are EV Properties and CGAS. EnerVest is the general partner of EV Properties and the general partner of the EnerVest partnerships that own CGAS. EV Properties was formed in April 2006 by EnerVest, EV Investors and the EnCap partnerships. In connection with the formation of EV Properties, EnerVest contributed interests in two partnerships, EnerVest Production Partners, Ltd., which owned the Northern Louisiana properties, and EnerVest WV, L.P., which owned the West Virginia properties. The EnCap partnerships contributed $16 million in net cash to EV Properties which was used to purchase the interest of an unaffiliated limited partner in EnerVest WV. In connection with this offering, CGAS formed EV Clinton Properties, and will contribute to it our Appalachian properties in |
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the Ohio area. The properties CGAS will retain are deeper, higher risk exploration properties. The retained assets represent approximately half of the assets owned by CGAS. Our predecessors’ combined financial statements include the results of EnerVest Production Partners, EnerVest WV and CGAS, combined as entities under common control. Our pro forma financial statements include adjustments to these historical combined statements to eliminate the results of the properties to be retained by CGAS, and immaterial assets of EnerVest Production Partners that were distributed prior to its acquisition by EV Properties. Our pro forma financial statements also include adjustments to reflect the acquisition of a portion of our Louisiana properties, which we purchased on March 1, 2005, as if the acquisition occurred on January 1, 2005. |
(2) | Includes the results of CGAS since its acquisition in August 2003. |
(3) | Includes the results of an acquisition of oil and gas interests in the Monroe field since the acquisition in March 2005. |
(4) | Restated for the years ended December 31, 2003, 2004 and 2005 to eliminate certain intercompany transactions as described in Note 16 — Restatement on pageF-40 of the Notes to the Combined Financial Statements. |
(5) | Exploration expenses, dry hole costs and impairment of unproved properties were incurred by CGAS with respect to properties which it will not transfer to us. |
(6) | Our pro forma general and administrative expenses do not include the additional costs we would have incurred if we had been a public company in 2005. We estimate that these costs would have been approximately $1.4 million on a pro forma basis for 2005. |
(7) | See “Non-GAAP Financial Measure” on page 23. |
(8) | Pro forma capital expenditures include $10.7 million related to an acquisition of oil and gas interests in the Monroe field in March 2005. |
(9) | Due from affiliate amounts are undistributed oil and gas revenues, net of operating expenses, relating to wells EnerVest operates for our predecessors, and receivables from an EnerVest partnership that markets a portion of our natural gas production in Northern Louisiana. Due to affiliates are amounts relating to the accrued and unpaid hedge liabilities with affiliates described in note 10 below, and short term advances for capital and operating expenditures made by EnerVest to our predecessors. |
(10) | Commodity hedge — related party relates to hedges our predecessors’ made under a master swap agreement entered into by the parent entities of our predecessors. |
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Pro Forma | ||||
December 31, | ||||
2005(1) | ||||
Reserve Data(1): | ||||
Estimated net proved reserves: | ||||
Natural gas (Bcf) | 44.8 | |||
Oil (MMBbls) | 1.1 | |||
Total (Bcfe) | 51.2 | |||
Proved developed (Bcfe) | 45.4 | |||
Proved undeveloped (Bcfe) | 5.8 | |||
Proved developed reserves as % of total proved reserves | 88.8 | % | ||
Standardized Measure (in millions)(2) | $ | 161.2 |
(1) | Our estimates of proved reserves have been made in accordance with SEC guidelines using constant oil and gas prices and operating costs at the date indicated. The average year-end price for oil and gas used to estimate our oil and gas reserve information was $61.04 per barrel of oil and $10.08 per MMBtu of gas. |
(2) | Standardized measure is the present value of estimated future net cash flows to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized measure does not give effect to derivative transactions. Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure. We have hedged a substantial portion of our anticipated production through 2008. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” beginning on page 85. |
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Pro Forma | Pro Forma | |||||||
Year Ended | Three Months Ended | |||||||
December 31, | March 31, | |||||||
2005 | 2006 | |||||||
Net Production: | ||||||||
Oil (MBbl) | 61 | 13 | ||||||
Gas (MMcf) | 2,355 | 554 | ||||||
Total production (MMcfe) | 2,721 | 630 | ||||||
Average daily production (Mcfe/d) | 7,453 | 7,001 | ||||||
Average Sales Prices: | ||||||||
Average sales prices (including hedges): | ||||||||
Oil (per Bbl) | $ | 53.04 | $ | 58.89 | ||||
Gas (per Mcf) | 7.35 | 9.08 | ||||||
Average sales prices (excluding hedges): | ||||||||
Oil (per Bbl) | $ | 53.04 | $ | 58.89 | ||||
Gas (per Mcf) | 9.03 | 8.80 | ||||||
Average Unit Costs per Mcfe: | ||||||||
Lease operating expenses | $ | 1.60 | $ | 1.75 | ||||
Production taxes | $ | 0.08 | $ | 0.06 | ||||
General and administrative expenses(1) | $ | 0.61 | $ | 1.02 | ||||
Depreciation, depletion and amortization | $ | 1.59 | $ | 1.81 |
(1) | Pro forma general and administrative expense does not include the additional expenses we would have incurred as a public company. We estimate these costs would have been $1.4 million in 2005 or $0.51 per Mcfe on a pro forma basis and $350,000 for the three months ended March 31, 2006 or $0.55 per Mcfe on a pro forma basis. |
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• | Interest expense; | |
• | Depreciation, depletion and amortization; | |
• | (Gain) Loss on sale of assets; |
• | Unrealized loss (gain) on derivatives; |
• | Accretion of asset retirement obligation; | |
• | Income tax provision; | |
• | Exploration expense and dry hole cost; and | |
• | Impairment of unproven properties. |
Pro Forma | ||||||||||||||||||||||||||||
Combined Predecessors | Year Ended | Three Months | ||||||||||||||||||||||||||
Year Ended December 31, | Three Months Ended March 31, | December 31, | Ended | |||||||||||||||||||||||||
2003 | 2004 | 2005 | 2005 | 2006 | 2005 | March 31, 2006 | ||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Net cash flows provided by operating activities | $ | 3,382 | $ | 16,704 | $ | 27,979 | $ | 6,310 | $ | 5,906 | ||||||||||||||||||
Add (deduct): | ||||||||||||||||||||||||||||
Depreciation, depletion and amortization | (1,837 | ) | (4,135 | ) | (4,409 | ) | (1,020 | ) | (1,105 | ) | ||||||||||||||||||
Impairment of unproved properties and dry hole cost | — | (1,855 | ) | (2,571 | ) | — | (149 | ) | ||||||||||||||||||||
Asset retirement obligation and accretion expense | (67 | ) | (160 | ) | (170 | ) | (43 | ) | (44 | ) | ||||||||||||||||||
Loss (gain) on sale of other property | 30 | 130 | — | — | — | |||||||||||||||||||||||
Changes in working capital | 1,471 | 230 | (6,209 | ) | (283 | ) | 1,647 | |||||||||||||||||||||
Other non cash charges | (302 | ) | (2,483 | ) | 453 | (1,042 | ) | (33 | ) | |||||||||||||||||||
Net income | 2,677 | 8,431 | 15,073 | 3,922 | 6,222 | 10,382 | 2,947 | |||||||||||||||||||||
Plus: | ||||||||||||||||||||||||||||
Interest expense | 126 | 327 | 632 | 37 | 184 | — | — | |||||||||||||||||||||
Depreciation, depletion and amortization | 1,837 | 4,135 | 4,409 | 1,020 | 1,105 | 4,312 | 1,141 | |||||||||||||||||||||
(Gain) loss on sale of assets | (30 | ) | (130 | ) | — | — | — | — | — | |||||||||||||||||||
Accretion of asset retirement obligation | 67 | 160 | 171 | 43 | 44 | 46 | 13 | |||||||||||||||||||||
Income tax provision | 317 | 2,521 | 5,349 | 1,421 | 1,545 | — | — | |||||||||||||||||||||
Exploration expense and dry hole cost | 1,338 | 1,721 | 3,069 | 878 | 207 | — | — | |||||||||||||||||||||
Impairment of unproved properties | — | 1,415 | 2,041 | — | — | — | — | |||||||||||||||||||||
Adjusted EBITDA | $ | 6,332 | $ | 18,580 | $ | 30,744 | $ | 7,321 | $ | 9,307 | $ | 14,740 | $ | 4,101 | ||||||||||||||
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• | the amount of oil and natural gas we produce; | |
• | the prices at which we sell our oil and gas production; | |
• | our ability to acquire additional oil and gas properties at economically attractive prices; | |
• | our ability to hedge commodity prices; | |
• | the level of our capital expenditures; | |
• | the level of our operating and administrative costs; and | |
• | the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon. |
• | the amount of cash reserves established by our general partner for the proper conduct of our business and for capital expenditures to maintain our production levels over the long-term, which may be substantial; |
• | the cost of acquisitions; | |
• | our debt service requirements and other liabilities; | |
• | fluctuations in our working capital needs; | |
• | our ability to borrow funds and access capital markets; | |
• | timing and collectibility of receivables; and | |
• | prevailing economic conditions. |
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• | the domestic and foreign supply of and demand for oil and gas; | |
• | the price and quantity of foreign imports of oil and gas; |
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• | the level of consumer product demand; | |
• | weather conditions; | |
• | overall domestic and global economic conditions; | |
• | political and economic conditions and events in foreign oil and gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America and Russia, and acts of terrorism or sabotage; | |
• | the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; | |
• | technological advances affecting energy consumption; | |
• | domestic and foreign governmental regulations and taxation; | |
• | the impact of energy conservation efforts; | |
• | the proximity and capacity of natural gas pipelines and other transportation facilities to our production; and | |
• | the price and availability of alternative fuels. |
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• | the estimated quantities of our oil and gas reserves; | |
• | the amount of oil and gas we produce from existing wells; | |
• | the prices at which we sell our production; and | |
• | our ability to acquire, locate and produce new reserves. |
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• | unexpected drilling conditions; | |
• | facility or equipment failure or accidents; | |
• | shortages or delays in the availability of drilling rigs and equipment; | |
• | adverse weather conditions; | |
• | compliance with environmental and governmental requirements; | |
• | title problems; | |
• | unusual or unexpected geological formations; | |
• | pipeline ruptures; | |
• | fires, blowouts, craterings and explosions; and | |
• | uncontrollable flows of oil or gas or well fluids. |
• | incorrect assumptions regarding the future prices of oil and gas or the future operating or development costs of properties acquired; | |
• | incorrect estimates of the oil and gas reserves attributable to a property we acquire; |
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• | an inability to integrate successfully the businesses we acquire; | |
• | the assumption of liabilities; | |
• | limitations on rights to indemnity from the seller; | |
• | the diversion of management’s attention from other business concerns; and | |
• | losses of key employees at the acquired businesses. |
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• | damages to equipment caused by adverse weather conditions, including hurricanes and flooding; | |
• | facility or equipment malfunctions; | |
• | pipeline ruptures or spills; | |
• | fires, blowouts, craterings and explosions; and | |
• | uncontrollable flows of oil or gas or well fluids. |
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• | neither our partnership agreement nor any other agreement requires EnerVest or the EnCap partnerships to pursue a business strategy that favors us or to refer any business opportunity to us; | |
• | our general partner is allowed to take into account the interests of parties other than us, such as EnerVest and the EnCap partnerships, in resolving conflicts of interest; | |
• | our general partner determines the amount and timing of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders; | |
• | our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; | |
• | our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and | |
• | our general partner decides whether to retain separate counsel, accountants or others to perform services for us. |
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• | whether or not to exercise its right to reset the target distribution levels of its incentive distribution rights at higher levels and receive, in connection with this reset, a number of Class B units that are convertible at any time following the first anniversary of the issuance of these Class B units into common units; | |
• | whether or not to exercise its limited call right; | |
• | how to exercise its voting rights with respect to the units it owns; | |
• | whether or not to exercise its registration rights; and | |
• | whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement. |
• | provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership; | |
• | generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general |
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partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and |
• | provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal. |
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• | our unitholders’ proportionate ownership interest in us will decrease; | |
• | the amount of cash available for distribution on each unit may decrease; | |
• | because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; | |
• | the ratio of taxable income to distributions may increase; | |
• | the relative voting strength of each previously outstanding unit may be diminished; and | |
• | the market price of the common units may decline. |
• | General economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds; |
• | conditions in the oil and gas industry; |
• | the market price of, and demand for, our common units; |
• | our results of operations and financial condition; and |
• | prices for oil and gas. |
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• | a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or | |
• | your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business. |
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• | To pay an aggregate of $60.2 million to EnerVest, CGAS and the EnCap partnerships as part of the consideration for the interests in our predecessors that will be contributed to us; | |
• | To repay approximately $10.3 million of indebtedness incurred by one of our predecessors to finance a portion of the purchase price of our Northern Louisiana properties acquired in 2000 and March 2005; and |
• | To reimburse EnerVest for an estimated $2.0 million of out of pocket legal, accounting, printing and other expenses of the offering. |
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• | the historical cash and capitalization of our combined predecessors as of March 31, 2006; |
• | our pro forma cash and capitalization as of March 31, 2006, reflecting the formation transactions described under “Summary — Formation Transactions and Partnership Structure — General”; and |
• | our pro forma cash and capitalization as of March 31, 2006, reflecting this offering, the other transactions described under “Summary — Formation Transactions and Partnership Structure — General” and the application of the net proceeds from this offering as described under “Use of Proceeds.” |
As of March 31, 2006 | ||||||||||||
Pro Forma | ||||||||||||
Adjusted For | ||||||||||||
Combined | Formation | Pro Forma | ||||||||||
Predecessors | Transactions | As Adjusted | ||||||||||
(In thousands) | ||||||||||||
Cash and cash equivalents | $ | 2,610 | $ | 90 | $ | 90 | ||||||
Total long-term debt | $ | 10,350 | $ | 10,350 | $ | — | ||||||
Partners’ capital/net parent equity: | ||||||||||||
Net parent equity | $ | 43,908 | $ | 32,020 | $ | — | ||||||
Common units — Public | — | — | 70,540 | |||||||||
Common units — Owners of our predecessors | — | — | 2,577 | |||||||||
Subordinated units — Owners of our predecessors | — | — | 13,426 | |||||||||
General partner interest | — | — | 671 | |||||||||
Total partners’ capital/net parent investment | 43,908 | 32,020 | 87,214 | |||||||||
Total capitalization | $ | 54,258 | $ | 42,370 | $ | 84,380 | ||||||
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Assumed initial public offering price per common unit | $ | 20.00 | ||||||
Net tangible book value per common unit before the offering(1) | $ | 4.13 | ||||||
Increase in net tangible book value per common unit attributable to purchasers in the offering | 7.12 | |||||||
Less: Pro forma net tangible book value per common unit after the offering(2) | 11.25 | |||||||
Immediate dilution in tangible net book value per common unit to new investors(3) | $ | 8.75 | ||||||
(1) | Determined by dividing the number of units and implied general partner units (4,495,000 common units, 3,100,000 subordinated units and 155,000 implied general partner units) to be issued to EnerVest, CGAS, the EnCap partnerships and EV Investors for their contribution of assets and liabilities to us into the net tangible book value of the contributed assets and liabilities. |
(2) | Determined by dividing the total number of units and implied general partner units to be outstanding after the offering (4,495,000 common units, 3,100,000 subordinated units and 155,000 implied general partner units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering. |
(3) | If the assumed initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $9.55 and $7.95, respectively. |
Units Acquired | Total Consideration | |||||||||||||||
Number | Percent | Amount | Percent | |||||||||||||
(In thousands) | ||||||||||||||||
Owners of our predecessors(1)(2) | 3,850 | 49.7 | $ | (28,170 | ) | (56.5 | ) | |||||||||
New investors | 3,900 | 50.3 | 78,000 | 156.5 | ||||||||||||
Total | 7,750 | 100.0 | $ | 49,830 | 100.0 | |||||||||||
(1) | Our general partner, which will be owned 71.25% by EnerVest, 23.75% by the EnCap partnerships and 5.00% by EV Investors, will receive 2% general partner interest in us. The owners of our predecessors, EnerVest, the EnCap partnerships, CGAS and EV Investors, will receive an aggregate of 595,000 common units and 3,100,000 subordinated units. |
(2) | The assets contributed by our predecessors were recorded at historical cost in accordance with GAAP. The proforma book value of the consideration provided by our predecessors, as of March 31, 2006, after giving effect to the application of the net proceeds of this offering is as follows: |
(In thousands) | ||||
Net predecessor investment | $ | 32,020 | ||
Less: Payment to our predecessors from the net proceeds of the offering | (60,190 | ) | ||
Total consideration | $ | (28,170 | ) | |
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• | lessthe amount of cash reserves established by our general partner to: |
- | provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; |
• | plus,if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter including cash from working capital borrowings. Working capital borrowings are borrowings used solely for working capital purposes or to pay distributions to unitholders. |
• | an amount equal to two times the amount needed for any one quarter for us to pay a distribution on all of our units, the general partner’s 2% interest and the incentive distribution rights at the same per-unit amount as was distributed in the immediately preceding quarter;plus |
• | all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions;plus |
• | working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter;less |
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• | our operating expenditures after the closing of this offering;less |
• | estimated average maintenance capital expenditures;less |
• | the amount of cash reserves established by our general partner to provide funds for future operating and capital expenditures. |
• | borrowings (other than working capital borrowings); |
• | sales of our equity and debt securities; |
• | the termination of interest rate and commodity swap agreements; and |
• | sales or other dispositions of assets for cash, other than sales of oil and gas production, disposition of assets made in connection with plugging and abandoning wells and site reclamation, sales of inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets. |
• | payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings; |
• | maintenance capital expenditures; |
• | expansion capital expenditures; |
• | payment of transaction expenses relating to interim capital transactions; or |
• | distributions to partners. |
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• | it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for that quarter and subsequent quarters; | |
• | it will reduce the need to borrow under our credit facility to pay distributions; | |
• | it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions to our general partner; and | |
• | it will reduce the likelihood that a large maintenance capital expenditure in a period will prevent the conversion of some or all of their subordinated units into common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period. |
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• | distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and the 2% general partner interest equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; |
• | the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common and subordinated units and the 2% general partner interest during those periods on a fully diluted basis during those periods; and |
• | there are no arrearages in payment of the minimum quarterly distribution on the common units. |
• | the subordination period will end and each subordinated unit will immediately convert into one common unit; | |
• | any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and |
• | the general partner will have the right to convert its 2% general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests. |
• | distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and the 2% general partner interest equaled or exceeded $2.00 (125% of the |
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• | the adjusted operating surplus generated during each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of a distribution of $2.00 per common unit (125% of the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units and the 2% general partner interest during those periods on a fully diluted basis; and |
• | there are no arrearages in payment of the minimum quarterly distribution on the common units. |
• | operating surplus generated with respect to that period;less | |
• | any net increase in working capital borrowings with respect to that period;less | |
• | any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period;plus | |
• | any net decrease in working capital borrowings with respect to that period;plus | |
• | any net increase in cash reserves for operating expenditures made with respect to that period required by any debt instrument for the repayment of principal, interest or premium. |
• | first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; | |
• | second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; | |
• | third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and | |
• | thereafter, in the manner described in “Incentive Distribution Rights” below. |
• | first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and | |
• | thereafter, in the manner described in “General Partner Interest and Incentive Distribution Rights” below. |
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• | we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and | |
• | we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution; |
• | first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.46 per unit for that quarter (the “first target distribution”); | |
• | second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.50 per unit for that quarter (the “second target distribution”); and | |
• | thereafter, 75% to all unitholders, pro rata, and 25% to the general partner. |
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• | first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarter distribution for that quarter; | |
• | second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for that quarter; and | |
• | thereafter, 75% to all unitholders, pro rata, and 25% to the general partner. |
Quarterly | Marginal Percentage | |||||||||||||||
Distribution | Interest in Distribution | Quarterly Distribution | ||||||||||||||
per Unit Prior to | General | per Unit following | ||||||||||||||
Reset | Unitholders | Partner | Hypothetical Reset | |||||||||||||
Minimum Quarterly Distribution | $0.40 | 98 | % | 2 | % | $0.60 | ||||||||||
First Target Distribution | up to $0.46 | 98 | % | 2 | % | up to $0.69 | (1) | |||||||||
Second Target Distribution | above $0.46 | above $0.69 | ||||||||||||||
up to $0.50 | 85 | % | 15 | % | up to $0.75 | (2) | ||||||||||
Thereafter | above $0.50 | 75 | % | 25 | % | above $0.75 |
(1) | This amount is 115% of the hypothetical reset minimum quarterly distribution. | |
(2) | This amount is 125% of the hypothetical reset minimum quarterly distribution. |
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General Partner Cash Distributions | ||||||||||||||||||||||||||
Common | Prior to Reset | |||||||||||||||||||||||||
Quarterly | Unitholders | 2% | ||||||||||||||||||||||||
Distribution | Cash | General | ||||||||||||||||||||||||
per Unit | Distribution | Class B | Partner | Total | ||||||||||||||||||||||
Prior to Reset | Prior to Reset | Units | Interest | IDRs | Total | Distributions | ||||||||||||||||||||
Minimum Quarterly Distribution | $0.40 | $ | 3,038,000 | $ | — | $ | 62,000 | $ | — | $ | 62,000 | $ | 3,100,000 | |||||||||||||
First Target Distribution | up to $0.46 | 455,700 | — | 9,300 | — | 9,300 | 465,000 | |||||||||||||||||||
Second Target Distribution | above $0.46 | 303,800 | — | 7,148 | 46,464 | 53,612 | 357,412 | |||||||||||||||||||
up to $0.50 | ||||||||||||||||||||||||||
Thereafter | above $0.50 | 759,500 | — | 20,254 | 232,912 | 253,166 | 1,012,666 | |||||||||||||||||||
$ | 4,557,000 | $ | — | $ | 98,702 | $ | 279,376 | $ | 378,078 | $ | 4,935,078 |
Common | General Partner Cash | |||||||||||||||||||||||||
Quarterly | Unitholders | Distributions After Reset | ||||||||||||||||||||||||
Distribution | Cash | 2% General | ||||||||||||||||||||||||
per Unit | Distribution | Class B | Partner | Total | ||||||||||||||||||||||
After Reset | After Reset | Units | Interest | IDRs | Total | Distributions | ||||||||||||||||||||
Minimum Quarterly Distribution | $0.60 | $ | 4,557,000 | $ | 279,376 | $ | 98,702 | $ | — | $ | 378,078 | $ | 4,935,078 | |||||||||||||
First Target Distribution | up to $0.69 | — | — | — | — | — | — | |||||||||||||||||||
Second Target Distribution | above $0.69 | — | — | — | — | — | — | |||||||||||||||||||
up to $0.75 | ||||||||||||||||||||||||||
Thereafter | above $0.75 | — | — | — | — | — | — | |||||||||||||||||||
$ | 4,557,000 | $ | 279,376 | $ | 98,702 | $ | — | $ | 378,078 | $ | 4,935,078 |
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Total Quarterly | Marginal Percentage Interest | |||||||||
Distribution per Unit | in Distributions | |||||||||
Target Amount | Unitholders | General Partner | ||||||||
Minimum Quarterly Distribution | $0.40 | 98 | % | 2 | % | |||||
First Target Distribution | up to $0.46 | 98 | % | 2 | % | |||||
Second Target Distribution | above $0.46 up to $0.50 | 85 | % | 15 | % | |||||
Thereafter | above $0.50 | 75 | % | 25 | % |
• | first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price; | |
• | second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and | |
• | thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus. |
• | the minimum quarterly distribution; |
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• | target distribution levels; | |
• | the unrecovered initial unit price; | |
• | the number of common units issuable during the subordination period without a unitholder vote; and | |
• | the number of common units into which a subordinated unit is convertible. |
• | first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances; | |
• | second, 98% to the common unitholders, pro rata, and 2% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution; | |
• | third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; |
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• | fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence; | |
• | fifth, 85% to all unitholders, pro rata, and 15% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to our general partner for each quarter of our existence; and | |
• | thereafter, 75% to all unitholders, pro rata, and 25% to our general partner. |
• | first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero; | |
• | second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and | |
• | thereafter, 100% to our general partner. |
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• | The prices at which we sell our future production will be volatile and could decrease substantially. While our hedging program will reduce the effect of this volatility for several years, any prolonged decrease in commodity prices will reduce our cash available for distribution. | |
• | If we fail to make acquisitions on economically attractive terms, we will not be able to maintain our production levels over the long-term, which will adversely effect our ability to make cash distributions. | |
• | Our business requires a significant amount of capital expenditures to maintain our production levels over the long term. The amount of these capital expenditures could increase materially in the future, reducing the amounts that would otherwise be distributed to our unitholders. In addition, we may need to borrow to finance our capital expenditures, and our credit facility for these borrowings may contain restrictions on our ability to make distributions. |
• | Our general partner will have broad discretion to establish reserves, which may be material, for the prudent conduct of our business, for capital expenditures to maintain our production levels over the long-term, and for future cash distributions to our unitholders. The establishment of these reserves may result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our distribution policy. |
• | While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of the public common unitholders, our partnership agreement can be amended with the approval of a majority of the outstanding common units and any Class B units issued upon the reset of incentive distribution rights, if any, voting as a single class (including common units held by EnerVest, the EnCap Partnership, EV Investors and their respective affiliates) after the subordination period has ended. | |
• | We anticipate that our credit facility will have covenants that will restrict our ability to pay distributions while there are amounts outstanding under the facility. Immediately after the offering, we will not have any borrowings under our credit facility, but we may borrow in the future to finance acquisitions or our drilling program or for other purposes. Should we be unable to satisfy any of the financial covenants in our anticipated credit facility or if we are otherwise in default under our credit facility, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. | |
• | UnderSection 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. |
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Distributions | ||||||||||||
Number of | One | Four | ||||||||||
Units | Quarter | Quarters | ||||||||||
Publicly held common units | 3,900,000 | $ | 1,560,000 | $ | 6,240,000 | |||||||
Common units held by EnerVest(1) | 163,645 | 65,458 | 261,832 | |||||||||
Common units held by CGAS(1) | 343,238 | 137,295 | 549,181 | |||||||||
Common units held by the EnCap partnerships(1) | 88,117 | 35,247 | 140,987 | |||||||||
Total common units | 4,495,000 | $ | 1,798,000 | $ | 7,192,000 | |||||||
Subordinated units held by EnerVest | 809,975 | $ | 323,990 | $ | 1,295,960 | |||||||
Subordinated units held by CGAS | 1,698,884 | 679,554 | 2,718,214 | |||||||||
Subordinated units held by EV Investors | 155,000 | 62,000 | 248,000 | |||||||||
Subordinated units held by the EnCap partnerships | 436,141 | $ | 174,456 | 697,826 | ||||||||
Total subordinated units | 3,100,000 | $ | 1,240,000 | $ | 4,960,000 | |||||||
Implied units held by our general partner | 155,000 | $ | 62,000 | $ | 248,000 | |||||||
Total units | 7,750,000 | $ | 3,100,000 | $ | 12,400,000 | |||||||
(1) | If the underwriters’ over-allotment option to purchase additional common units is exercised, an equivalent number of common units will be redeemed proportionately from EnerVest, CGAS and the EnCap partnerships. Accordingly, the exercise of the underwriters’ over-allotment option will not affect the total amount of common units outstanding or the amount of cash needed to pay the initial distribution rate on all units. |
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• | Pro Forma and Forecasted Results of Operations in which we present our pro forma results of operations for the year ended December 31, 2005 and the twelve months ending March 31, 2006 and our financial forecast of our results of operations for the twelve months ending June 30, 2007 and the important assumptions on which these forecasts are based; |
• | Forecasted Cash Available for Distribution for the twelve months ending June 30, 2007 based on our financial forecast of our results of operations for this period; and |
• | Pro Forma Combined Available Cash for the year ended December 31, 2005 and the twelve months ended March 31, 2006, in which we present the amount of available cash we would have had for our fiscal year ended December 31, 2005 based on our pro forma financial statements and for the twelve months ended March 31, 2006. |
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Combined | Combined | ||||||||||||
Pro Forma | Pro Forma | Forecast | |||||||||||
Year Ended | Twelve Months | Twelve Months | |||||||||||
December 31, | Ended | Ending | |||||||||||
2005 | March 31, 2006 | June 30, 2007 | |||||||||||
(In thousands, except per unit data) | |||||||||||||
Revenue: | |||||||||||||
Natural gas and oil revenue | $ | 24,493 | $ | 25,493 | $ | 24,927 | |||||||
Realized gain (loss) on swaps | (3,952 | ) | (3,994 | ) | 2,788 | ||||||||
Transportation and marketing — related revenues | 6,104 | 6,782 | 5,666 | ||||||||||
Total revenues | 26,645 | 28,281 | 33,381 | ||||||||||
Operating expenses: | |||||||||||||
Lease operating expense | 4,354 | 4,523 | 4,725 | ||||||||||
Purchased gas cost | 5,659 | 6,370 | 5,298 | ||||||||||
Production taxes | 224 | 254 | 308 | ||||||||||
Asset retirement obligations accretion expense | 46 | 52 | 46 | ||||||||||
Depreciation, depletion and amortization | 4,312 | 4,346 | 4,991 | ||||||||||
General and administrative expense | 1,672 | 1,854 | 4,000 | ||||||||||
Total operating expenses | 16,267 | 17,399 | 19,369 | ||||||||||
Operating income | 10,378 | 10,882 | 14,012 | ||||||||||
Other income (expense) | 4 | 8 | — | ||||||||||
Net income | $ | 10,382 | $ | 10,890 | $ | 14,012 | |||||||
General partner’s interest in net income | 208 | 218 | 280 | ||||||||||
Limited partner interest in net income | 10,174 | 10,672 | 13,732 | ||||||||||
Diluted net income per limited partner unit | 1.34 | 1.41 | 1.81 | ||||||||||
Diluted weighted average limited partner units outstanding | 7,595 | 7,595 | 7,595 | ||||||||||
Note 1. | Basis of Presentation. |
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• | In April 2006, EnerVest, EV Investors and the EnCap partnerships formed EV Properties. EnerVest contributed the general and limited partnership interests in EnerVest Production Partners, which owned our Northern Louisiana properties and the general partnership interest in EnerVest WV that owned our properties in West Virginia. The EnCap partnerships contributed a net $16 million in cash to EV Properties. The cash contribution to EV Properties was used to purchase the interest of the limited partner in EnerVest WV. Following this purchase, we owned all of the general and limited partnership interests in EnerVest Production Partners and EnerVest WV, which owned the Northern Louisiana and West Virginia properties. | |
• | When EV Properties was formed, EV Investors was issued an interest in EV Properties. | |
• | In connection with the closing of the offering of common units contemplated by this prospectus, EnerVest, EV Investors and the EnCap partnerships will contribute the general and limited partnership interests in EV Properties to us and our general partner in exchange for some of our common units, subordinated units and cash, and an interest in our general partner. |
• | In connection with the closing of the offering, CGAS, a corporation owned by partnerships in which EnerVest owns a 25.75% interest as general partner, formed EV Clinton Properties and will convey to it the Ohio area properties. CGAS will contribute EV Clinton Properties to us in exchange for some of our common and subordinated units and cash. |
Note 2. | Summary of Significant Accounting Policies. |
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Note 3. | Significant Forecast Assumptions. |
Forecasted Production and Oil and Gas Price Information
Twelve Months | ||||||||||||
Ending | ||||||||||||
June 30, | ||||||||||||
2007 | ||||||||||||
Net production(1): | ||||||||||||
Oil (MBbl) | 60 | |||||||||||
Gas (MMcf) | 2,426 | |||||||||||
MMcfe | 2,788 | |||||||||||
Average daily production (MMcfe) | 7,638 | |||||||||||
Average natural gas sales price per Mcf(2): | ||||||||||||
Average NYMEX sales price (hedged volumes) | $ | 9.70 | ||||||||||
Average NYMEX sales price (unhedged volumes) | $ | 8.50 | ||||||||||
Percent of production hedged | 76 | % | ||||||||||
Premium to NYMEX | $ | 1.11 | ||||||||||
Weighted average net natural gas sales price | $ | 9.61 | ||||||||||
Average oil sales price per Bbl(3): | ||||||||||||
Average NYMEX sales price (hedged volumes) | $ | 76.40 | ||||||||||
Average NYMEX sales price (unhedged volumes) | $ | 65.00 | ||||||||||
Percent of production hedged | 76 | % | ||||||||||
Premium to NYMEX | $ | 7.86 | ||||||||||
Weighted average net oil sales price | $ | 72.86 |
(1) | Our forecasted net production volumes for the twelve months ending June 30, 2007 reflect the production estimated for the twelve months ending June 30, 2007 in the estimates of net proved reserves derived from our reserve report at December 31, 2005 prepared by Cawley, Gillespie & Associates, Inc., our independent reserve engineers. Our 2005 reserve report includes estimated aggregate production for the twelve months ending June 30, 2007 of 608 MMcfe from 22 wells we plan to drill on our Appalachian properties prior to June 30, 2007, which are classified as proved undeveloped in our 2005 reserve report. |
(2) | Our weighted average net natural gas sales price of $9.61 is calculated by taking into account the volume of natural gas we have hedged for the forecast period (1,888 MMMBtu, or approximately 76% of total forecasted production volume during the twelve month period ending June 30, 2007) at a weighted average NYMEX price of $9.70 per MMBtu during the twelve month period ending June 30, 2007 and unhedged natural gas production volumes at an assumed price of $8.50 per MMBtu during the twelve months ending June 30, 2007. The natural gas price for our Appalachian production is adjusted by a premium of $1.03 per Mcf to the assumed price of $8.50 per MMBtu, which accounts for our estimate of a positive Appalachian basis differential and positive Btu adjustments. Gas production from our Northern Louisiana properties is adjusted by deducting $0.54 per Mcf from the assumed price of $8.50 per MMBtu, which accounts for our estimate of a negative Northern Louisiana basis differential and a lower Btu content for our Northern Louisiana gas production. |
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(3) | We have hedged 76% of our anticipated oil production (or 125 Bbls per day) for the twelve months ending June 30, 2007 at an average NYMEX price of $76.40 per Bbl. Our unhedged oil sales price is calculated at an assumed price of $65.00 per Bbl during the twelve months ending June 30, 2007. These prices are adjusted by deducting $3.10 per Bbl to reflect transportation costs and quality differentials. |
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Twelve Months Ending June 30, 2007
Twelve Months | ||||
Ending | ||||
June 30, | ||||
2007 | ||||
(In thousands) | ||||
Net income | $ | 14,012 | ||
Plus: | ||||
Interest expense | — | |||
Depletion, depreciation and amortization | 4,991 | |||
(Gain) Loss on sale of assets | — | |||
Accretion of asset retirement obligation | 46 | |||
Income tax provision | — | |||
Exploration, expense and dry hole cost | — | |||
Impairment of unproved properties | — | |||
Adjusted EBITDA | 19,049 | |||
Less: | ||||
Interest expense | — | |||
Forecasted capital expenditures | 4,530 | |||
Forecasted cash available for distribution | $ | 14,519 | ||
Forecasted cash distributions(1): | ||||
Per unit | $ | 1.60 | ||
Common units | $ | 7,192 | ||
Subordinated units | 4,960 | |||
General partner interest | 248 | |||
Total forecasted distributions | $ | 12,400 | ||
Excess | 2,119 | |||
Percent of distributions payable to common unitholders | 100 | % | ||
Percent of distributions payable to subordinated unitholders | 100 | % |
(1) | The amount forecasted as available for distribution during the twelve months ending June 30, 2007 will be different than the amount of distributions that a holder of common units would receive during those periods because the cash available for distribution during the last quarter in each of those periods would be distributed 45 days following the end of the quarter. |
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For Distribution for the Year Ended December 31, 2005
and the Twelve Months Ended March 31, 2006
Twelve Months | ||||||||
Year Ended | Ended | |||||||
December 31 | March 31, | |||||||
2005 | 2006 | |||||||
(In thousands, | ||||||||
except per unit data) | ||||||||
Net income: | $ | 10,382 | $ | 10,890 | ||||
Plus: | ||||||||
Interest expense | — | — | ||||||
Depletion, depreciation and amortization | 4,312 | 4,346 | ||||||
(Gain) Loss on sale of assets | — | — | ||||||
Accretion of asset retirement obligation | 46 | 52 | ||||||
Income tax provision | — | — | ||||||
Exploration, expense and dry hole cost | — | — | ||||||
Impairment of unproved properties | — | — | ||||||
Adjusted EBITDA | 14,740 | 15,288 | ||||||
Less: | ||||||||
Additional expense of being a public company(1) | 1,400 | 1,400 | ||||||
Interest expense | — | — | ||||||
Capital expenditures(2) | 13,030 | 2,651 | ||||||
Plus: | ||||||||
Borrowings (repayments) of debt under credit facility | 8,650 | (150 | ) | |||||
Pro forma cash available for distribution | 8,960 | 11,087 | ||||||
Expected distributions: | ||||||||
Common units | 7,192 | 7,192 | ||||||
Subordinated units | 1,589 | 3,673 | ||||||
General partner interest | 179 | 222 | ||||||
Total expected distribution | $ | 8,960 | $ | 11,087 | ||||
Annualized initial quarterly distributions per unit | $ | 1.60 | $ | 1.60 | ||||
Aggregate distribution payable at annualized initial quarterly distributions | $ | 12,400 | $ | 12,400 | ||||
Excess (shortfall) | (3,440 | ) | (1,313 | ) | ||||
Percent of distributions payable to common unitholders | 100 | % | 100 | % | ||||
Percent of distributions payable to subordinated unitholders | 32 | % | 74 | % |
(1) | We expect our incremental general and administrative expenses will include costs associated with annual and quarterly reports to unitholders, our annual meeting of unitholders, tax return and Schedule K-1 preparations and distribution, investor relations, registrar and transfer agent fees, incremental director and officer liability insurance costs, independent director compensation, additional accounting and legal fees and SEC reporting and filing requirements. |
(2) | Pro forma capital expenditures for the year ended December 31, 2005 include $10.7 million related to an acquisition in March 2005. |
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Twelve Months | ||||
Ending | ||||
June 30, | ||||
2007 | ||||
(in thousands) | ||||
Adjusted EBITDA | $ | 19,049 | ||
Forecasted interest expense | — | |||
Forecasted estimated average maintenance capital expenditures | 5,297 | |||
Forecasted operating surplus generated during the period | $ | 13,752 | ||
Annualized initial quarterly distribution | 12,400 | |||
Excess operating surplus | $ | 1,352 | ||
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Pro Forma | ||||||||||||||||||||||||||||||||||||
Combined Predecessors(1) | EV Energy Partners, L.P. | |||||||||||||||||||||||||||||||||||
Three Months | Year | Three Months | ||||||||||||||||||||||||||||||||||
Ended | Ended | Ended | ||||||||||||||||||||||||||||||||||
Year Ended December 31, | March 31, | December 31, | March 31, | |||||||||||||||||||||||||||||||||
2001 | 2002 | 2003(2) | 2004 | 2005(3) | 2005 | 2006 | 2005 | 2006 | ||||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||||||||||||
Natural gas and oil revenues | $ | 4,160 | $ | 2,815 | $ | 10,370 | $ | 28,336 | $ | 45,148 | $ | 8,362 | $ | 11,669 | $ | 24,493 | $ | 5,622 | ||||||||||||||||||
Realized gain (loss) on natural gas swaps | (462 | ) | (67 | ) | (242 | ) | (1,890 | ) | (7,194 | ) | 444 | (190 | ) | (3,952 | ) | 157 | ||||||||||||||||||||
Transportation and marketing-related revenues(4) | 354 | 383 | 3,443 | 3,438 | 6,225 | 1,003 | 1,679 | 6,104 | 1,660 | |||||||||||||||||||||||||||
Total revenues(4) | 4,052 | 3,131 | 13,571 | 29,884 | 44,179 | 9,809 | 13,158 | 26,645 | 7,439 | |||||||||||||||||||||||||||
Operating Costs and Expenses: | ||||||||||||||||||||||||||||||||||||
Lease operating expenses(4) | 3,144 | 2,371 | 3,466 | 6,615 | 7,236 | 1,460 | 1,799 | 4,354 | 1,102 | |||||||||||||||||||||||||||
Purchased gas cost(4) | — | — | 2,933 | 3,003 | 5,660 | 848 | 1,557 | 5,659 | 1,557 | |||||||||||||||||||||||||||
Production taxes | 13 | 10 | 65 | 119 | 292 | 26 | 53 | 224 | 39 | |||||||||||||||||||||||||||
Asset retirement obligations accretion expense | — | — | 67 | 160 | 171 | 43 | 44 | 46 | 13 | |||||||||||||||||||||||||||
Exploration expenses(5) | — | — | 1,338 | 1,281 | 2,539 | 878 | 58 | — | — | |||||||||||||||||||||||||||
Dry hole costs(5) | — | — | — | 440 | 530 | — | 149 | — | — | |||||||||||||||||||||||||||
Impairment of unproved properties(5) | — | — | — | 1,415 | 2,041 | — | — | — | — | |||||||||||||||||||||||||||
Depreciation, depletion and amortization | 113 | 87 | 1,837 | 4,135 | 4,409 | 1,020 | 1,105 | 4,312 | 1,141 | |||||||||||||||||||||||||||
General and administrative expenses(6) | 181 | 202 | 1,069 | 1,061 | 899 | 341 | 640 | 1,672 | 643 | |||||||||||||||||||||||||||
Management fees | — | — | 69 | 94 | 117 | 28 | 35 | — | — | |||||||||||||||||||||||||||
Total operating costs and expenses, net(4) | 3,451 | 2,670 | 10,844 | 18,323 | 23,894 | 4,644 | 5,440 | 16,267 | 4,495 | |||||||||||||||||||||||||||
Gain (loss) on sale of other property | 4 | — | 30 | 130 | — | — | — | — | — | |||||||||||||||||||||||||||
Operating income | 605 | 461 | 2,757 | 11,691 | 20,285 | 5,165 | 7,718 | 10,378 | 2,944 |
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Pro Forma | ||||||||||||||||||||||||||||||||||||
Combined Predecessors(1) | EV Energy Partners, L.P. | |||||||||||||||||||||||||||||||||||
Three Months | Year | Three Months | ||||||||||||||||||||||||||||||||||
Ended | Ended | Ended | ||||||||||||||||||||||||||||||||||
Year Ended December 31, | March 31, | December 31, | March 31, | |||||||||||||||||||||||||||||||||
2001 | 2002 | 2003(2) | 2004 | 2005(3) | 2005 | 2006 | 2005 | 2006 | ||||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||||||
Other Income (Expense), net: | ||||||||||||||||||||||||||||||||||||
Total other income (expense), net | (223 | ) | (144 | ) | 234 | (118 | ) | (428 | ) | (211 | ) | (41 | ) | 4 | 3 | |||||||||||||||||||||
Income before income tax provision | 382 | 317 | 2,991 | 11,573 | 19,857 | 4,954 | 7,677 | 10,382 | 2,947 | |||||||||||||||||||||||||||
Income tax provision | — | — | 317 | 2,521 | 5,349 | 1.421 | 1,545 | — | — | |||||||||||||||||||||||||||
Equity earnings in investments | — | — | 3 | (621 | ) | 565 | 389 | 90 | — | — | ||||||||||||||||||||||||||
Net income | 382 | 317 | 2,677 | 8,431 | 15,073 | 3,922 | 6,222 | 10,382 | 2,947 | |||||||||||||||||||||||||||
Other comprehensive income (loss)(2) | — | — | — | (100 | ) | (4,168 | ) | (3,167 | ) | 5,638 | — | — | ||||||||||||||||||||||||
Comprehensive income(2) | $ | 382 | $ | 317 | $ | 2,677 | $ | 8,331 | $ | 10,905 | $ | 755 | $ | 11,860 | $ | 10,382 | $ | 2,947 | ||||||||||||||||||
Pro Forma(1) | ||||||||||||||||||||||||||||
EV Energy | ||||||||||||||||||||||||||||
Combined Predecessors(1) | Partners, L.P. | |||||||||||||||||||||||||||
December 31, | March 31, | March 31, | ||||||||||||||||||||||||||
2001 | 2002 | 2003(2) | 2004 | 2005 | 2006 | 2006 | ||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Balance Sheet Data (at period end): | ||||||||||||||||||||||||||||
Total current assets | $ | 424 | $ | 432 | $ | 6,462 | $ | 11,364 | $ | 19,136 | $ | 11,758 | $ | 5,719 | ||||||||||||||
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization | 1,552 | 2,054 | 46,826 | 46,484 | 57,037 | 57,561 | 87,847 | |||||||||||||||||||||
Other assets | — | — | 3,844 | 953 | 1,990 | 4,014 | 1,300 | |||||||||||||||||||||
Total assets | $ | 1,976 | $ | 2,486 | $ | 57,132 | $ | 58,801 | $ | 78,163 | $ | 73,333 | $ | 94,866 | ||||||||||||||
Total current liabilities | $ | 1,661 | $ | 184 | $ | 14,019 | $ | 8,270 | $ | 19,778 | $ | 11,546 | $ | 5,460 | ||||||||||||||
Long-term debt | 3,050 | 3,050 | 3,050 | 2,850 | 10,500 | 10,350 | — | |||||||||||||||||||||
Other long-term liabilities | — | — | 5,307 | 6,466 | 6,976 | 7,529 | 2,192 | |||||||||||||||||||||
Total liabilities | 4,711 | 3,234 | 22,376 | 17,586 | 37,254 | 29,425 | 7,652 | |||||||||||||||||||||
Owner’s equity (deficit) | (2,735 | ) | (748 | ) | 34,756 | 41,215 | 40,909 | 43,908 | 87,214 | |||||||||||||||||||
Total liabilities and owners equity | $ | 1,976 | $ | 2,486 | $ | 57,132 | $ | 58,801 | $ | 78,163 | $ | 73,333 | $ | 94,866 | ||||||||||||||
(1) | Our predecessors are EV Properties and CGAS. EnerVest is the general partner of EV Properties and the EnerVest partnership that owns CGAS. EV Properties was formed in April 2006 by EnerVest, EV Investors and the EnCap partnerships. In connection with the formation of EV Properties, EnerVest contributed interests in two partnerships, EnerVest Production Partners, Ltd., which owned the Northern Louisiana properties, and EnerVest WV, L.P., which owned the West Virginia properties. The EnCap partnerships contributed $16 million in net cash to EV Properties which was used to purchase the interest of an unaffiliated limited partner in EnerVest WV. In connection with this offering, CGAS formed EV Clinton Properties, and will contribute to it our Appalachian properties in Ohio. The properties CGAS will retain are deep, higher risk exploration properties. The retained assets represent approximately half of the assets owned by CGAS. |
Our predecessors’ combined financial statements include the results of EnerVest Production Partners, EnerVest WV and CGAS, combined as entities under common control. Our pro forma financial statements include adjustments to these historical combined statements to eliminate the results of the properties to be retained by CGAS, and immaterial assets of EnerVest Production Partners that were distributed prior to its acquisition by EV Properties. Our pro forma financial statements also include adjustments to reflect the |
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acquisition of a portion of our Louisiana properties, that we purchased on March 1, 2005, as if the acquisition occurred on January 1, 2005. |
(2) | Includes the results of CGAS since its acquisition in August 2003. |
(3) | Includes the results of an acquisition of oil and gas interests in the Monroe field since the acquisition in March 2005. |
(4) | Restated for the years ended December 31, 2003, 2004 and 2005 to eliminate certain intercompany transactions as described in Note 16 — Restatement onpage F-40 of the Notes to the Combined Financial Statements. |
(5) | Exploration expenses, dry hole costs and impairment of proved properties were incurred by CGAS with respect to the properties which it will not transfer to us. |
(6) | Our pro forma general and administrative expenses do not include the additional costs we would have incurred if we had been a public company in 2005. We estimate that these costs would have been approximately $1.4 million on a pro forma basis for 2005 and $350,000 for the three months ended March 31, 2006. |
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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Weighted | Weighted | Weighted | ||||||||||||||||||||||
Average | Average | Average | ||||||||||||||||||||||
Predecessor Entity | Period Covered | Index | MMBtu/Day | Fixed Price | Floor Price | Cap Price | ||||||||||||||||||
EVWV(1) | 7/2006 - 12/2006 | Dominion Appalachia | 1,000 | $ | 10.240 | |||||||||||||||||||
EVWV(1) | 1/2007 - 12/2007 | Dominion Appalachia | 900 | $ | 10.265 | |||||||||||||||||||
EVWV(1) | 1/2008 - 12/2008 | Dominion Appalachia | 800 | $ | 9.750 | |||||||||||||||||||
CGAS | 1/2006 - 12/2006 | Dominion Appalachia | 2,000 | $ | 10.380 | |||||||||||||||||||
CGAS | 7/2006 - 12/2006 | Dominion Appalachia | 500 | $ | 10.240 | |||||||||||||||||||
CGAS | 1/2007 - 12/2007 | Dominion Appalachia | 2,200 | $ | 10.265 | |||||||||||||||||||
CGAS | 1/2008 - 12/2008 | Dominion Appalachia | 1,900 | $ | 9.750 | |||||||||||||||||||
EVPP(2) | 1/2006 - 3/2006 | NYMEX | 1,000 | $ | 7.110 | $ | 8.390 | |||||||||||||||||
EVPP(2) | 4/2006 - 10/2006 | NYMEX | 1,000 | $ | 5.940 | $ | 7.050 | |||||||||||||||||
EVPP(2) | 2/2006 - 10/2006 | NYMEX | 750 | $ | 9.250 | |||||||||||||||||||
EVPP(2) | 11/2006 - 12/2006 | NYMEX | 1,750 | $ | 10.430 | |||||||||||||||||||
EVPP(2) | 1/2007 - 12/2007 | NYMEX | 1,500 | $ | 9.820 | |||||||||||||||||||
EVPP(2) | 1/2007 - 12/2007 | NYMEX | 500 | $ | 10.000 | |||||||||||||||||||
EVPP(2) | 1/2008 - 12/2008 | NYMEX | 1,500 | $ | 9.360 | |||||||||||||||||||
EVPP(2) | 1/2008 - 12/2008 | NYMEX | 500 | $ | 9.500 |
(1) | EnerVest WV | |
(2) | EnerVest Production Partners |
Weighted | ||||||||||||||||
Average | ||||||||||||||||
Predecessor Entity | Period Covered | Index | BBL/Day | Fixed Price | ||||||||||||
CGAS | 6/2006 - 12/2006 | NYMEX | 125 | $ | 76.400 | |||||||||||
CGAS | 1/2007 - 12/2007 | NYMEX | 125 | $ | 76.400 |
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Three Months Ended | ||||||||
March 31, | ||||||||
2005 | 2006 | |||||||
Production Data: | ||||||||
Oil (MBbls) | 47 | 50 | ||||||
Natural Gas (MMcf) | 893 | 986 | ||||||
Net Production: | ||||||||
Total production (MMcfe) | 1,173 | 1,285 | ||||||
Average daily production (Mcfe/d) | 13,029 | 14,280 | ||||||
Average Sales Price per Unit: | ||||||||
Oil (Bbl) including hedges | $ | 47.18 | $ | 57.03 | ||||
Oil (Bbl) excluding hedges | $ | 47.18 | $ | 58.78 | ||||
Natural gas (Mcf) including hedges | $ | 7.40 | $ | 8.76 | ||||
Natural gas (Mcf) excluding hedges | $ | 6.90 | $ | 8.86 | ||||
Average Unit Costs per Mcfe: | ||||||||
Lease operating expenses | $ | 1.24 | $ | 1.40 | ||||
Depreciation, depletion and amortization | $ | 0.87 | $ | 0.86 | ||||
General and administrative expenses | $ | 0.31 | $ | 0.53 |
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2004 | 2005 | |||||||
Production Data: | ||||||||
Oil (MBbls) | 153 | 174 | ||||||
Natural Gas (MMcf) | 3,589 | 3,901 | ||||||
Net Production: | ||||||||
Total production (MMcfe) | 4,504 | 4,947 | ||||||
Average daily production (Mcfe/d) | 12,341 | 13,554 | ||||||
Average Sales Price per Unit: | ||||||||
Oil (Bbl) | $ | 39.33 | $ | 53.70 | ||||
Natural gas (Mcf) including hedges | $ | 5.70 | $ | 7.33 | ||||
Natural gas (Mcf) excluding hedges | $ | 6.22 | $ | 9.17 | ||||
Average Unit Costs per Mcfe: | ||||||||
Lease operating expenses | $ | 1.47 | $ | 1.46 | ||||
Depreciation, depletion and amortization | $ | 0.92 | $ | 0.89 | ||||
General and administrative expenses | $ | 0.26 | $ | 0.21 |
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• | Increased costs associated with operations of the additional properties we acquired in the Monroe field in 2005; | |
• | The increase costs associated with successful wells drilled by our predecessors in late 2004 and during 2005; and | |
• | A general increase in costs of materials and labor experienced by our predecessors during the period. |
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2003 | 2004 | |||||||
Production Data: | ||||||||
Oil (MBbls) | 67 | 153 | ||||||
Natural Gas (MMcf) | 1,819 | 3,589 | ||||||
Net Production: | ||||||||
Total production (MMcfe) | 2,219 | 4,504 | ||||||
Average daily production (Mcfe/d) | 6,081 | 12,341 | ||||||
Average Sales Price per Unit: | ||||||||
Oil (Bbl) | $ | 24.14 | $ | 39.33 | ||||
Natural gas (Mcf) including hedges | $ | 4.68 | $ | 5.70 | ||||
Natural gas (Mcf) excluding hedges | $ | 4.82 | $ | 6.22 | ||||
Average Unit Costs per Mcfe: | ||||||||
Lease operating expenses | $ | 1.56 | $ | 1.47 | ||||
Depreciation, depletion and amortization | $ | 0.83 | $ | 0.92 | ||||
General and administrative expenses | $ | 0.51 | $ | 0.26 |
• | 2004 production included a full year of production from CGAS, which was acquired in August 2003; | |
• | 2004 production from the West Virginia properties increased 43% compared with 2003, as a result of production enhancement procedures and successful drilling. |
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Payments Due By Period | ||||||||||||||||||||
Contractual | Less Than | One-Three | Three-Five | More Than | ||||||||||||||||
Obligations | Total | One Year | Years | Years | Five Years | |||||||||||||||
Long-term debt(1) | $ | 10,500 | $ | — | $ | — | $ | 10,500 | $ | — | ||||||||||
Other long-term liabilities | $ | 2,752 | $ | — | $ | — | $ | — | $ | 2,752 | ||||||||||
Total contractual obligations | $ | 13,252 | $ | — | $ | — | $ | 10,500 | $ | 2,752 | ||||||||||
(1) | Consists of debt under our credit facility. |
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Three Months Ended | ||||||||
March 31, | ||||||||
2005 | 2006 | |||||||
(Unaudited) | ||||||||
(In thousands) | ||||||||
Revenues: | ||||||||
Natural gas and oil revenues | $ | 4,137 | $ | 5,622 | ||||
Realized gain on natural gas and oil swaps | 200 | 157 | ||||||
Transportation and marketing-related revenues | 959 | 1,660 | ||||||
Total revenues | 5,296 | 7,439 | ||||||
Direct Operating Expenses: | ||||||||
Lease operating expenses | 1,081 | 1,378 | ||||||
Purchased gas cost | 848 | 1,557 | ||||||
Production taxes | 10 | 39 | ||||||
Total direct operating expenses | 1,939 | 2,974 | ||||||
Revenues in excess of direct operating expenses | $ | 3,357 | $ | 4,465 | ||||
Three Months Ended | ||||||||
March 31, | ||||||||
2005 | 2006 | |||||||
Production Data: | ||||||||
Oil (MBbls) | 16 | 13 | ||||||
Natural Gas (MMcf) | 492 | 554 | ||||||
Net Production: | ||||||||
Total production (MMcfe) | 589 | 630 | ||||||
Average daily production (Mcfe/d) | 6,547 | 7,001 | ||||||
Average Sales Price per Unit: | ||||||||
Oil (Bbl) including hedges | $ | 46.76 | $ | 58.89 | ||||
Oil (Bbl) excluding hedges | $ | 46.76 | $ | 58.89 | ||||
Natural gas (Mcf) including hedges | $ | 7.28 | $ | 9.08 | ||||
Natural gas (Mcf) excluding hedges | $ | 6.87 | $ | 8.80 | ||||
Average Unit Costs per Mcfe: | ||||||||
Lease operating expenses per Mcfe | $ | 1.83 | $ | 2.19 |
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Year Ended December 31, | ||||||||
2004 | 2005 | |||||||
(Unaudited) | ||||||||
(In thousands) | ||||||||
Revenues: | ||||||||
Natural gas and oil revenues | $ | 15,468 | $ | 24,009 | ||||
Realized loss on natural gas swaps | (971 | ) | (3,952 | ) | ||||
Transportation and marketing-related revenues | 3,235 | 6,080 | ||||||
Total revenues | 17,732 | 26,137 | ||||||
Direct Operating Expenses: | ||||||||
Lease operating expenses | 4,793 | 5,324 | ||||||
Purchased gas cost | 3,003 | 5,660 | ||||||
Production taxes | 48 | 224 | ||||||
Total direct operating expenses | 7,844 | 11,208 | ||||||
Revenues in excess of direct operating expenses | $ | 9,888 | $ | 14,929 | ||||
Year Ended December 31, | ||||||||
2004 | 2005 | |||||||
Production Data: | ||||||||
Oil (MBbls) | 67 | 61 | ||||||
Natural Gas (MMcf) | 2,139 | 2,273 | ||||||
Net Production: | ||||||||
Total production (MMcfe) | 2,539 | 2,638 | ||||||
Average daily production (Mcfe/d) | 6,955 | 7,229 | ||||||
Average Sales Price per Unit: | ||||||||
Oil (Bbl) including hedges | $ | 36.82 | $ | 53.04 | ||||
Oil (Bbl) excluding hedges | $ | 36.82 | $ | 53.04 | ||||
Natural gas (Mcf) including hedges | $ | 5.63 | $ | 7.40 | ||||
Natural gas (Mcf) excluding hedges | $ | 6.08 | $ | 9.14 | ||||
Average Unit Costs per Mcfe: | ||||||||
Lease operating expenses per Mcfe | $ | 1.89 | $ | 2.02 |
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Year Ended December 31, | ||||||||
2003 | 2004 | |||||||
(Unaudited) | ||||||||
(In thousands) | ||||||||
Revenues: | ||||||||
Natural gas and oil revenues | $ | 6,505 | $ | 15,468 | ||||
Realized loss on natural gas swaps | (242 | ) | (971 | ) | ||||
Transportation and marketing-related revenues | 3,018 | 3,235 | ||||||
Total revenues | 9,281 | 17,732 | ||||||
Direct operating expenses: | ||||||||
Lease operating expenses | 2,487 | 4,793 | ||||||
Purchased gas cost | 2,933 | 3,003 | ||||||
Production taxes | 27 | 48 | ||||||
Total direct operating expenses | 5,447 | 7,844 | ||||||
Revenues in excess of direct operating expenses | $ | 3,834 | $ | 9,888 | ||||
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Year Ended December 31, | ||||||||
2003 | 2004 | |||||||
Production Data: | ||||||||
Oil (MBbls) | 27 | 67 | ||||||
Natural Gas (MMcf) | 1,144 | 2,139 | ||||||
Net Production: | ||||||||
Total production (MMcfe) | 1,306 | 2,539 | ||||||
Average daily production (Mcfe/d) | 3,578 | 6,955 | ||||||
Average Sales Price per Unit: | ||||||||
Oil (Bbl) including hedges | $ | 25.23 | $ | 36.82 | ||||
Oil (Bbl) excluding hedges | $ | 25.23 | $ | 36.82 | ||||
Natural gas (Mcf) including hedges | $ | 4.88 | $ | 5.63 | ||||
Natural gas (Mcf) excluding hedges | $ | 5.09 | $ | 6.08 | ||||
Average Unit Costs per Mcfe: | ||||||||
Lease operating expenses per Mcfe | $ | 1.90 | $ | 1.89 |
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Estimated Net Proved Reserves | ||||||||||||||||
Standardized | ||||||||||||||||
Developed | Undeveloped | Total | Measure(1) | |||||||||||||
(Bcfe) | (In millions) | |||||||||||||||
Appalachian Basin: | ||||||||||||||||
Ohio area | 20.4 | 5.3 | 25.7 | $ | 90.1 | |||||||||||
West Virginia | 8.4 | 0.5 | 8.9 | 25.9 | ||||||||||||
Total | 28.8 | 5.8 | 34.6 | 116.0 | ||||||||||||
Northern Louisiana | 16.6 | — | 16.6 | 45.2 | ||||||||||||
Total | 45.4 | 5.8 | 51.2 | $ | 161.2 | |||||||||||
(1) | Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities.” Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure. |
Average | ||||||||||||||||||||||||
Reserve to | ||||||||||||||||||||||||
Producing | 2005 Production | Production | ||||||||||||||||||||||
Wells | Oil | Gas | Index | |||||||||||||||||||||
Gross | Net | (MBbls) | (MMcf) | MMcfe | (Years)(1) | |||||||||||||||||||
Appalachian Basin: | ||||||||||||||||||||||||
Ohio area | 690 | 583 | 56.4 | 1,064 | 1,403 | 18.4 | ||||||||||||||||||
West Virginia area | 151 | 133 | 4.5 | 441 | 468 | 19.0 | ||||||||||||||||||
Total | 841 | 716 | 60.9 | 1,505 | 1,871 | 18.5 | ||||||||||||||||||
Northern Louisiana | 1,112 | 1,112 | 0.0 | 850 | 850 | 19.5 | ||||||||||||||||||
Total | 1,953 | 1,828 | 60.9 | 2,355 | 2,721 | 18.8 | ||||||||||||||||||
(1) | Reserve production index is calculated by dividing our estimated net equivalent reserves as of December 31, 2005 by our pro forma 2005 production. |
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• | Continually maintain an inventory of proved undeveloped drilling locations, which are sufficient when drilled and completed, to allow us to maintain our production levels for approximately three years; | |
• | Replace and increase our reserves and production over the long term by pursuing acquisitions throughout the continental United States of long-lived producing oil or gas properties with low decline rates, predictable production profiles and relatively low risk drilling opportunities; | |
• | Maintain low levels of indebtedness to permit us to finance opportunistic acquisitions; | |
• | Reduce exposure to commodity price risk through hedging; | |
• | Retain control over the operation of a substantial portion of our production; and | |
• | Focus on controlling the costs of our operations. |
• | Drilling Inventory. We have a substantial inventory of low risk, proved undeveloped drilling locations. During the three years ended December 31, 2005, EnerVest drilled 13 gross (10.0 net) development wells on our oil and gas properties, all but one of which were successfully completed as producers. We have an inventory of 80 proved undeveloped drilling locations, 18 of which we plan to drill during 2006. |
• | Long Life Reserves with Predictable Decline Rates. Our properties have a long reserve to production index, with predictable decline rates. Our estimated net equivalent reserves as of December 31, 2005 divided by our pro forma 2005 production, which we refer to as our reserve production index, was 18.8 years. | |
• | Experienced Management Team. Our management is experienced in oil and gas acquisitions and operations. Our executive officers average over 25 years of industry experience, and over 10 years of experience acquiring and managing oil and gas properties for EnerVest partnerships. | |
• | Strong Financial Position. We will have no long-term debt immediately following the closing of the offering, which will allow us more flexibility in financing acquisitions and development programs. We expect to enter into a bank credit facility at the closing of the offering. | |
• | Relationship with EnerVest. Our relationship with EnerVest will provide us with a wide breadth of operational, technical, risk management and other expertise across a wide geographical range, which will assist us in evaluating acquisition and development opportunities. EnerVest’s primary business is to acquire and manage oil and gas properties for partnerships formed with institutional investors. These partnerships focus on maximizing cash distributions to partners. |
• | EnerVest Production Partners, a subsidiary of EnerVest, acquired our Northern Louisiana properties in 2000 and 2005; |
• | EnerVest WV, a partnership owned by EnerVest and an institutional investor, acquired our Appalachian properties in West Virginia in 2003; and |
• | An EnerVest partnership acquired our Appalachian Ohio area properties in 2003. |
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December 31, | ||||
2005 | ||||
Reserve Data: | ||||
Estimated net proved reserves: | ||||
Natural gas (Bcf) | 44.8 | |||
Oil (MMBbls) | 1.1 | |||
Total (Bcfe) | 51.2 | |||
Proved developed (Bcfe) | 45.4 | |||
Proved undeveloped (Bcfe) | 5.8 | |||
Proved developed reserves as % of total proved reserves | 88.8 | % | ||
Standardized Measure (in millions) | $ | 161.2 |
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Three Months | ||||||||
Year Ended | Ended | |||||||
December 31, | March 31, | |||||||
2005 | 2006 | |||||||
Net Production: | ||||||||
Total production (MMcfe) | 2,721 | 630 | ||||||
Average daily production (Mcfe/d) | 7,453 | 7,001 | ||||||
Average Sales Prices per Mcfe: | ||||||||
Average sales prices (including hedges) | $ | 7.55 | $ | 9.17 | ||||
Average sales prices (excluding hedges) | 9.00 | 8.92 | ||||||
Average Unit Costs per Mcfe: | ||||||||
Lease operating expenses | $ | 1.60 | $ | 1.75 | ||||
General and administrative expenses | 0.61 | 1.02 | ||||||
Depreciation, depletion and amortization | 1.59 | 1.81 |
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Gross Wells | Net Wells | |||||||||||||||||||||||
Oil | Gas | Total | Oil | Gas | Total | |||||||||||||||||||
Appalachian Basin: | ||||||||||||||||||||||||
Operated | 12 | 746 | 758 | 11 | 695 | 706 | ||||||||||||||||||
Non-operated | 6 | 77 | 83 | — | 10 | 10 | ||||||||||||||||||
Northern Louisiana: | ||||||||||||||||||||||||
Operated | — | 1,112 | 1,112 | — | 1,112 | 1,112 | ||||||||||||||||||
Non-operated | — | — | — | — | — | — | ||||||||||||||||||
Total | 18 | 1,935 | 1,953 | 11 | 1,817 | 1,828 | ||||||||||||||||||
Developed Acreage(1) | Undeveloped Acreage(2) | |||||||||||||||
Gross(3) | Net(4) | Gross(3) | Net(4) | |||||||||||||
Appalachian Basin: | ||||||||||||||||
Operated | 21,245 | 20,101 | 60,348 | 54,537 | ||||||||||||
Non-operated | 766 | 317 | 10,564 | 4,130 | ||||||||||||
Northern Louisiana: | ||||||||||||||||
Operated | 1,112 | 1,112 | 97,595 | 77,116 | ||||||||||||
Non-operated | — | — | — | — | ||||||||||||
Total | 23,123 | 21,530 | 168,507 | 135,783 | ||||||||||||
(1) | Developed acres are acres spaced or assigned to productive wells. On our Northern Louisiana properties, there are no spacing requirements. Therefore, one developed acre is assigned to each productive well. | |
(2) | Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves. | |
(3) | A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. | |
(4) | A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. |
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Year Ended | ||||
December 31, | ||||
2005 | ||||
Gross Development Wells(1): | ||||
Productive | 5.0 | |||
Dry | — | |||
Total | 5.0 | |||
Net Development Wells(1): | ||||
Productive | 2.5 | |||
Dry | — | |||
Total | 2.5 | |||
(1) | Does not include 4 gross (3.7 net) exploration wells drilled by our predecessors in Ohio targeting the deeper Knox formation. These wells did not discover commercial reserves at the deeper target, and were completed in the shallow Clinton formation. These wells will be contributed to us. |
December 31, | ||||
2005 | ||||
Reserve Data: | ||||
Estimated net proved reserves: | ||||
Natural gas (Bcf) | 50.9 | |||
Oil (MMBbls) | 1.7 | |||
Total (Bcfe) | 60.9 | |||
Proved developed (Bcfe) | 55.1 | |||
Proved undeveloped (Bcfe) | 5.8 | |||
Proved developed reserves as % of total proved reserves | 90.5 | % | ||
Standardized measure (in millions) | $ | 182.4 |
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Year Ended December 31, | ||||||||||||
2003 | 2004 | 2005 | ||||||||||
Net Production: | ||||||||||||
Oil (MBbl) | 67 | 153 | 174 | |||||||||
Gas (MMcf) | 1,819 | 3,589 | 3,901 | |||||||||
Total production (MMcfe) | 2,219 | 4,504 | 4,947 | |||||||||
Average daily production (Mcfe/d) | 6,081 | 12,341 | 13,554 | |||||||||
Average Sales Prices: | ||||||||||||
Average sales prices (including hedges): | ||||||||||||
Oil (per Bbl) | $ | 24.14 | $ | 39.33 | $ | 53.70 | ||||||
Gas (per Mcf) | 4.68 | 5.70 | 7.33 | |||||||||
Average sales prices (excluding hedges): | ||||||||||||
Oil (per Bbl) | $ | 24.14 | $ | 39.33 | $ | 53.70 | ||||||
Gas (per Mcf) | 4.82 | 6.22 | 9.17 | |||||||||
Average Unit Costs per Mcfe: | ||||||||||||
Lease operating expenses | $ | 1.56 | $ | 1.47 | $ | 1.46 | ||||||
Depreciation, depletion and amortization | 0.83 | 0.92 | 0.89 | |||||||||
General and administrative expenses | 0.51 | 0.26 | 0.21 |
Gross Wells | Net Wells | |||||||||||||||||||||||
Oil | Gas | Total | Oil | Gas | Total | |||||||||||||||||||
Appalachian Basin: | ||||||||||||||||||||||||
Operated | 27 | 862 | 889 | 18 | 764 | 782 | ||||||||||||||||||
Non-operated | 18 | 212 | 230 | 3 | 22 | 25 | ||||||||||||||||||
Northern Louisiana: | ||||||||||||||||||||||||
Operated | — | 1,112 | 1,112 | — | 1,112 | 1,112 | ||||||||||||||||||
Non-operated | — | — | — | — | — | — | ||||||||||||||||||
Total | 45 | 2,186 | 2,231 | 21 | 1,898 | 1,919 | ||||||||||||||||||
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Developed Acreage(1) | Undeveloped Acreage(2) | |||||||||||||||
Gross(3) | Net(4) | Gross(3) | Net(4) | |||||||||||||
Appalachian Basin: | ||||||||||||||||
Operated | 29,885 | 26,085 | 293,339 | 256,526 | ||||||||||||
Non-operated | 766 | 317 | 10,564 | 4,130 | ||||||||||||
Northern Louisiana: | ||||||||||||||||
Operated | 1,112 | 1,112 | 97,595 | 77,116 | ||||||||||||
Non-operated | — | — | — | — | ||||||||||||
Total | 31,763 | 27,514 | 401,498 | 337,772 | ||||||||||||
(1) | Developed acres are acres spaced or assigned to productive wells. On our Northern Louisiana properties, there are not any spacing requirements. Therefore, only one developed acre is assigned to each productive well. | |
(2) | Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves. | |
(3) | A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. | |
(4) | A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. |
Year Ended | ||||
December 31, | ||||
2005 | ||||
Gross wells: | ||||
Productive | 27.0 | |||
Dry | 7.0 | |||
Total | 34.0 | |||
Net Development Wells: | ||||
Productive | 15.4 | |||
Dry | 3.2 | |||
Total | 18.6 | |||
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• | faster connection of newly drilled wells to the existing system; | |
• | control pipeline operating pressures and capacity to maximize our production; | |
• | control compression costs and fuel use; | |
• | maintain system integrity; | |
• | control the monthly nominations on the receiving pipelines to prevent imbalances and penalties; and | |
• | closely track sales volumes and receipts to assure all production values are realized. |
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• | require the acquisition of various permits before drilling commences; | |
• | restrict the types, quantities and concentration of various substances that can be released into the environment in connection with natural gas and oil drilling, production and transportation activities; | |
• | limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas; and | |
• | require remedial measures to mitigate pollution from former and ongoing operations, such as site restoration, pit closure and plugging of abandoned wells. |
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• | the location of wells; | |
• | the method of drilling and casing wells; | |
• | the surface use and restoration of properties upon which wells are drilled; | |
• | the plugging and abandoning of wells; and | |
• | notice to surface owners and other third parties. |
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• | sell all or substantially all of our assets; | |
• | merge or consolidate; | |
• | dissolve or liquidate; | |
• | make or consent to a general assignment for the benefit of creditors; | |
• | file or consent to the filing of any bankruptcy, insolvency or reorganization petition for relief under the United States Bankruptcy Code or otherwise such relief from debtor or protection from creditors; or | |
• | take various actions similar to the foregoing. |
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Name | Age | Position with EV Management | ||||
John B. Walker | 60 | Chairman and Chief Executive Officer | ||||
Mark A. Houser | 44 | President, Chief Operating Officer and Director | ||||
Michael E. Mercer | 48 | Senior Vice President and Chief Financial Officer | ||||
Kathryn S. MacAskie | 50 | Senior Vice President of Acquisitions and Divestitures | ||||
George Lindahl III | 59 | Director nominee | ||||
Gary R. Petersen | 59 | Director nominee |
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• | each person who then will beneficially own 5% or more of the then outstanding units; | |
• | all of the directors and director nominees of EV Management; | |
• | each named executive officer of EV Management; and | |
• | all directors, director nominees and officers of EV Management as a group. |
Percentage of | ||||||||||||||||||||||||
Total Common | ||||||||||||||||||||||||
Percentage of | and | |||||||||||||||||||||||
Common Units | Percentage of | Subordinated | Subordinated | Subordinated | ||||||||||||||||||||
to be | Common Units to | Units to be | Units to be | Units to be | ||||||||||||||||||||
Name and Address | Beneficially | be Beneficially | Beneficially | Beneficially | Beneficially | |||||||||||||||||||
of Beneficial Owner(1) | Owned | Owned | Owned | Owned | Owned | |||||||||||||||||||
Principal Stockholders(2): | ||||||||||||||||||||||||
EnerVest(3) | 506,883 | 11.3 | % | 2,663,859 | 85.9 | % | 41.7 | % | ||||||||||||||||
EV Investors(4) | — | — | 155,000 | 5.0 | % | 2.0 | % | |||||||||||||||||
CGAS(5) | 343,238 | 7.6 | % | 1,698,884 | 54.8 | % | 26.9 | % | ||||||||||||||||
EnCap partnerships(6) | 88,117 | 2.0 | % | 436,141 | 14.1 | % | 6.9 | % | ||||||||||||||||
1100 Louisiana, Suite 3150 | ||||||||||||||||||||||||
Houston, Texas 77002 | ||||||||||||||||||||||||
Director, Director | ||||||||||||||||||||||||
Nominees and Officers: | ||||||||||||||||||||||||
John B. Walker(7) | 506,883 | 11.3 | % | 2,663,859 | 85.9 | % | 41.7 | % | ||||||||||||||||
Mark A. Houser | — | — | — | |||||||||||||||||||||
Michael E. Mercer | — | — | — | |||||||||||||||||||||
Kathryn S. MacAskie | — | — | — | |||||||||||||||||||||
George Lindahl III | — | — | — | |||||||||||||||||||||
Gary R. Petersen(6) | 88,117 | 2.0 | % | 436,141 | 14.1 | % | 6.9 | % | ||||||||||||||||
All directors, director nominees and executive officers as a group (4 persons) | 595,000 | 13.2 | % | 3,100,000 | 100 | % | 48.7 | % |
(1) | Unless otherwise indicated, the address for all beneficial owners in this table is 1001 Fannin Street, Suite 900, Houston, Texas 77002. | |
(2) | If the underwriters exercise their over-allotment option to purchase common units, we will proportionately redeem from EnerVest, CGAS and the EnCap partnerships the same number of common units. | |
(3) | Includes the 163,645 common units and 809,975 subordinated units owned by EnerVest plus the common units and subordinated units owned by EV Investors and CGAS. As discussed in notes 4 and 5, EnerVest may be deemed to be the beneficial owner of their units. EnerVest is a Texas limited partnership. Mr. John B. Walker, by virtue of his ownership of EnerVest and his position on the board of directors of EnerVest’s general partner, may be deemed to beneficially own common and subordinated units beneficially owned by EnerVest. Mr. Walker disclaims beneficial ownership of the common and subordinated units owned by EnerVest. | |
(4) | EnerVest, as the general partner of EV Investors, has the power to direct the voting and disposition of the subordinated units owned by EV Investors, and may therefore be deemed to beneficially own such units. The ownership of EV Investors is described below. |
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(5) | CGAS is owned by EnerVest partnerships. EnerVest, as the general partner of the EnerVest partnerships that owns CGAS has the power to direct the voting and disposition of the common units and subordinated units owned by CGAS, and may therefore be deemed to beneficially own such units. | |
(6) | Represents 49,181 common units and 243,423 subordinated units owned by EnCap Energy Capital Fund V, L.P. and 38,936 common units and 192,718 subordinated units owned by EnCap Energy Capital Fund V-B, L.P. EnCap Equity Fund V GP, L.P., as the general partner of each of EnCap Energy Capital Fund V, L.P. and EnCap Energy Capital Fund V-B, L.P., EnCap Investments L.P., as the general partner of EnCap Equity Fund V GP, L.P., EnCap Investments GP, L.L.C., as the general partner of EnCap Investments L.P., RNBD GP LLC, as the sole member of EnCap Investments GP, L.L.C., and David B. Miller, Gary R. Petersen, D. Martin Phillips, and Robert L. Zorich, as the members of RNBD GP LLC may be deemed to share voting and dispositive control over the subordinated units and common units owned by EnCap Energy Capital Fund V, L.P. and EnCap Energy Capital Fund V-B, L.P. Each of EnCap Equity Fund V GP, L.P., EnCap Investments L.P., EnCap Investments GP, L.L.C., RNBD GP LLC, David B. Miller, Gary R. Petersen, D. Martin Phillips, and Robert L. Zorich disclaim beneficial ownership of the reported securities in excess of such entity’s or person’s respective pecuniary interest in the securities. | |
(7) | Mr. Walker does not own directly any common units or subordinated units. Includes all of the units beneficially owned by EnerVest. As described in note 3, Mr. Walker may be deemed to beneficially own units beneficially owned by EnerVest. Mr. Walker disclaims beneficial ownership of such units. |
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Consideration received by EnerVest for the contribution of the interests in EV Properties | 163,645 common units; 809,975 subordinated units; $16.53 million in cash from the proceeds of this offering. EnerVest will own a 71.25% interest in our general partner. | |
Consideration to be received by EV Investors for its interest in EV Properties | 155,000 subordinated units. EV Investors will own a 5.00% interest in our general partner. | |
Consideration received by CGAS. CGAS is owned by a limited partnership. EnerVest is the general partner of this partnership and has 25.75% interest in the partnership | 343,238 common units; 1,698,884 subordinated units; and $34.76 million in cash. | |
Consideration received by the EnCap partnerships for their interests in EV Properties | 88,117 common units; 436,141 subordinated units; $8.90 million in cash from the proceeds of this offering. The EnCap partnerships will own a 23.75% interest in our general partner. |
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Distributions of available cash to our general partner and its affiliates | We will generally make cash distributions 98% to our unitholders pro rata and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 25% of the distributions above the highest target distribution level. | |
Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, | ||
• EnerVest would receive distributions of $1,557,792 on its common and subordinated units; | ||
• EV Investors would receive distributions of $248,000 on its subordinated units; | ||
• CGAS would receive distributions of $3,267,395 on its common and subordinated units; | ||
• The EnCap partnerships would receive distributions of $838,813 through its common and subordinated units; and | ||
• our general partner would receive distributions of $248,000 on its 2% general partner interest. | ||
Payments to our general partner and its affiliates | We will pay EnerVest for the provision of various general and administrative services it performs for our benefit. For further information regarding the administrative fee, please read “Certain Relationship and Related Party Transactions — Omnibus Agreement” beginning on page 121. We will also enter into a contract operating agreement with EnerVest Operating, a subsidiary of EnerVest, pursuant to which EnerVest Operating will act as operator of the wells we own and are entitled to operate. We will pay the subsidiary for these services. Please see “Certain Relationships and Related Party Transactions” beginning on page 119. | |
Withdrawal or removal of our general partner | If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement — Withdrawal or Removal of the General Partner” beginning on page 139. |
Liquidation | Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances. |
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• | our obligation to pay EnerVest a monthly fee of $90,000 for providing us general and administrative and all other services with respect to our existing business and operations; |
• | our obligation to reimburse EnerVest for any insurance coverage expenses it incurs with respect to our business and operations; and | |
• | EnerVest’s obligation to indemnify us for certain liabilities and our obligation to indemnify EnerVest for certain liabilities. |
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• | Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its owners and affiliates (including EnerVest, EV Investors and the EnCap partnerships on the one hand, and our partnership and our limited partners, on the other hand). In addition, many of the officers and directors of EV Management serve in similar capacities with EnerVest or the EnCap partnerships and their respective affiliates, which may lead to additional conflicts of interest. The directors and officers of EV Management have fiduciary duties to manage EV Management and our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders. | |
• | Whenever a conflict arises between our general partner or its owners and affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty. | |
• | Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is: |
• | approved by the conflicts committee, although our general partner is not obligated to seek such approval; | |
• | approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates although, not required; | |
• | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or | |
• | fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
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• | provides that the general partner shall not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed that the decision was in the best interests of our partnership; | |
• | generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by the general partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be advantageous or beneficial to us; and | |
• | provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct. |
• | the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations; | |
• | the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities; | |
• | the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets; | |
• | the negotiation, execution and performance of any contracts, conveyances or other instruments; | |
• | the distribution of our cash; | |
• | the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring; | |
• | the maintenance of insurance for our benefit and the benefit of our partners; | |
• | the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships; |
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• | the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation; | |
• | the indemnification of any person against liabilities and contingencies to the extent permitted by law; | |
• | the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and | |
• | the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner. |
• | amount and timing of asset purchases and sales; | |
• | cash expenditures; | |
• | borrowings; | |
• | the issuance of additional units; and | |
• | the creation, reduction or increase of reserves in any quarter. |
• | enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or | |
• | hastening the expiration of the subordination period. |
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State law fiduciary duty standards | Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present. | |
The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners. | ||
Partnership agreement modified standards | Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held. | |
In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct. |
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Special provisions regarding affiliated transactions. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be: | ||
• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or | ||
• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us). | ||
If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held. |
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• | surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges; | |
• | special charges for services requested by a common unitholder; and | |
• | other similar fees or charges. |
• | represents that the transferee has the capacity, power and authority to become bound by our partnership agreement; | |
• | automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and | |
• | gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering. |
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• | with regard to distributions of available cash, please read “How We Will Make Cash Distributions” beginning on page 47; |
• | with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties” beginning on page 122; |
• | with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units” beginning on page 130; and |
• | with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences” beginning on page 146. |
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• | during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and | |
• | after the subordination period, the approval of a majority of the common units and Class B units, if any, voting as a class. |
Issuance of additional units | No approval right. |
Amendment of the partnership agreement | Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement” beginning on page 135. |
Merger of our partnership or the sale of all or substantially all of our assets | Unit majority in certain circumstances. Please read “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets” beginning on page 137. |
Dissolution of our partnership | Unit majority. Please read “— Termination and Dissolution” beginning on page 138. |
Continuation of our business upon dissolution | Unit majority. Please read “— Termination and Dissolution” beginning on page 138. |
Withdrawal of the general partner | Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and their affiliates, is required for the withdrawal of our general partner prior to December 31, 2016 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of the General Partner” beginning on page 139. |
Removal of the general partner | Not less than 662/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of the General Partner” beginning on page 139. |
Transfer of the general partner interest | Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or |
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consolidation with or into, or sale of all or substantially all of its assets, to such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2016. See “— Transfer of General Partner Interest” beginning on page 140. |
Transfer of incentive distribution rights | Except for transfers to an affiliate or another person as part of our general partner’s merger or consolidation, sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder, the approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to December 31, 2016. Please read “— Transfer of Incentive Distribution Rights” beginning on page 140. |
Transfer of ownership interests in our general partner | No approval required at any time. Please read “— Transfer of Ownership Interests in the General Partner” beginning on page 140. |
• | to remove or replace the general partner; | |
• | to approve some amendments to the partnership agreement; or | |
• | to take other action under the partnership agreement; |
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• | enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or | |
• | enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option. |
• | a change in our name, the location of our principal place of our business, our registered agent or our registered office; | |
• | the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement; | |
• | a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating partnership nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes; | |
• | an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed; | |
• | an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities, including any amendment that our general partner determines is necessary or appropriate in connection with: |
• | the adjustments of the minimum quarterly distribution, first target distribution and second target distribution in connection with the reset of our general partner’s incentive distribution rights as described under “How We Will Make Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels;” or | |
• | the implementation of the provisions relating to our general partner’s right to reset its incentive distribution rights in exchange for Class B units; and | |
• | any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities, provided that, any such modifications and related issuance of partnership securities have received approval by a majority of the members of the conflicts committee of our general partner; |
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• | any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone; | |
• | an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement; | |
• | any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement; | |
• | a change in our fiscal year or taxable year and related changes; | |
• | conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or | |
• | any other amendments substantially similar to any of the matters described in the clauses above. |
• | do not adversely affect the limited partners (or any particular class of limited partners) in any material respect; | |
• | are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute; | |
• | are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading; | |
• | are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or | |
• | are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement. |
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• | the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority; | |
• | there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law; | |
• | the entry of a decree of judicial dissolution of our partnership; or | |
• | the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor. |
• | the action would not result in the loss of limited liability of any limited partner; and | |
• | neither our partnership, our operating partnership nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue. |
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• | the subordination period will end, and all outstanding subordinated units will immediately convert into common units on aone-for-one basis; | |
• | any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and | |
• | our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time. |
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• | an affiliate of our general partner (other than an individual); or | |
• | another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity, |
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• | the subordination period will end and all outstanding subordinated units will immediately convert into common units on aone-for-one basis; | |
• | any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and |
• | our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time. |
• | the average offering price of common units for the 20 trading days preceding the purchase; and |
• | the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the purchase. |
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• | our general partner; | |
• | any departing general partner; | |
• | any person who is or was an affiliate of or owner of an equity interest in a general partner or any departing general partner; | |
• | any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points; |
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• | any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and | |
• | any person designated by our general partner. |
• | a current list of the name and last known address of each partner; | |
• | a copy of our tax returns; | |
• | information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner; | |
• | copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed; | |
• | information regarding the status of our business and financial condition; and | |
• | any other information regarding our affairs as is just and reasonable. |
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• | 1% of the total number of the securities outstanding; or | |
• | the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale. |
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• | the underwriters’ option to purchase additional units is not exercised; and | |
• | the underwriters exercise their option to purchase additional units in full. |
Units Owned Immediately | ||||||||||||||||
After Exercise of | ||||||||||||||||
Underwriters’ Option and | ||||||||||||||||
Units Owned Immediately | Related Unit Redemption | |||||||||||||||
After This Offering | Assuming | |||||||||||||||
Assuming | Underwriters’ | |||||||||||||||
Underwriters’ | Option is | |||||||||||||||
Option is | Exercised | |||||||||||||||
Name of Selling Unitholder | Not Exercised | Percent(1) | in Full | Percent(1) | ||||||||||||
EnerVest | 163,645 | 3.6 | % | 2,750 | * | |||||||||||
CGAS | 343,238 | 7.6 | % | 5,769 | * | |||||||||||
The EnCap partnerships | 88,117 | 2.0 | % | 1,481 | * |
* | Less than 1%. | |
(1) | Percentage of total common units outstanding. |
• | whether the investment is prudent under Section 404(a)(1)(B) of ERISA; | |
• | whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and |
• | whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences — Tax-Exempt Organizations and Other Investors” beginning on page 159. |
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Number of | ||||
Underwriters | Common Units | |||
A.G. Edwards & Sons, Inc. | ||||
Raymond James & Associates, Inc. | ||||
Total | 3,900,000 | |||
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• | the information set forth in this prospectus and otherwise available to the underwriters; | |
• | market conditions for initial public offerings; | |
• | the history and the prospects for the industry in which we compete; | |
• | the ability of our management; | |
• | our prospects for future earnings; | |
• | the present state of our development and our current financial condition; | |
• | the general condition of the securities markets at the time of this offering; and | |
• | the recent market prices of, and the demand for, publicly traded common units of generally comparable entities. |
No Exercise | Full Exercise | |||||||
Per Unit | ||||||||
Total | ||||||||
• | Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum. | |
• | Over-allotment transactions involve sales by the underwriters of the common units in excess of the number of units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of units over-allotted by the underwriters is not greater than the number of units they may purchase in the over-allotment option. In a naked short position, the number of units involved is greater than the number of units in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment optionand/or purchasing common units in the open market. | |
• | Syndicate-covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source |
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of the common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option. If the underwriters sell more common units than could be covered by the over-allotment option, resulting in a naked short position, the position can only be closed out by buying common units in the open market. 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 common units in the open market after pricing that could adversely affect investors who purchase in the offering. |
• | Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate-covering transaction to cover syndicate short positions. |
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• | prices we receive for our oil and gas production; | |
• | our ability to replace the reserves we produce through drilling and property acquisitions; | |
• | our ability to attract the capital; and | |
• | the other matters discussed under “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and elsewhere in this prospectus. |
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Pro Forma as | ||||||||||||||||||||
Pro Forma | Adjusted for | Pro Forma | ||||||||||||||||||
Total | Transaction | Transaction | Offering | Pro Forma | ||||||||||||||||
Combined | Adjustments | Adjustments | Adjustments | as Adjusted | ||||||||||||||||
ASSETS | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 2,609,633 | $ | (2,519,966 | ) | $ | 89,667 | $ | — | $ | 89,667 | |||||||||
Accounts receivable | 6,960,153 | (3,399,934 | ) | 3,560,219 | — | 3,560,219 | ||||||||||||||
Commodity hedge asset | 1,224,877 | 418,043 | 1,642,920 | — | 1,642,920 | |||||||||||||||
Deferred tax asset | 443,155 | (443,155 | ) | — | — | — | ||||||||||||||
Other current assets | 519,726 | (92,989 | ) | 426,737 | — | 426,737 | ||||||||||||||
Total current assets | 11,757,544 | (6,038,001 | ) | 5,719,543 | — | 5,719,543 | ||||||||||||||
Natural gas and oil properties, net | 57,561,379 | (14,558,764 | ) | 43,002,615 | 44,844,134 | 87,846,749 | ||||||||||||||
Property, plant and equipment, net | 514,028 | (300,919 | ) | 213,109 | — | 213,109 | ||||||||||||||
Long-term commodity hedge asset | 1,991,108 | (904,495 | ) | 1,086,613 | — | 1,086,613 | ||||||||||||||
Other assets | 1,508,837 | (1,508,837 | ) | — | — | — | ||||||||||||||
Total assets | $ | 73,332,896 | $ | (23,311,016 | ) | $ | 50,021,880 | $ | 44,844,134 | $ | 94,866,014 | |||||||||
LIABILITIES AND OWNERS’ EQUITY | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable & accrued liabilities | $ | 2,662,120 | $ | (1,322,851 | ) | $ | 1,339,269 | $ | — | $ | 1,339,269 | |||||||||
Due to affiliates | 4,361,694 | (438,362 | ) | 3,923,332 | — | 3,923,332 | ||||||||||||||
Commodity hedge liability | 1,658,489 | (1,460,480 | ) | 198,009 | — | 198,009 | ||||||||||||||
Current income tax payable | 2,623,587 | (2,623,587 | ) | — | — | — | ||||||||||||||
Deferred income tax liability | 201,603 | (201,603 | ) | — | — | — | ||||||||||||||
Other current liabilities | 38,934 | (38,934 | ) | — | — | — | ||||||||||||||
Total current liabilities | 11,546,427 | (6,085,817 | ) | 5,460,610 | — | 5,460,610 | ||||||||||||||
Long-term debt | 10,350,000 | — | 10,350,000 | (10,350,000 | ) | — | ||||||||||||||
Asset retirement obligations | 2,805,650 | (613,909 | ) | 2,191,741 | — | 2,191,741 | ||||||||||||||
Deferred income tax liability | 4,722,612 | (4,722,612 | ) | — | — | — | ||||||||||||||
Owners’ equity | 43,908,207 | (11,888,678 | ) | 32,019,529 | 55,194,134 | 87,213,663 | ||||||||||||||
Total liabilities and owners’ equity | $ | 73,332,896 | $ | (23,311,016 | ) | $ | 50,021,880 | $ | 44,844,134 | $ | 94,866,014 | |||||||||
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UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
For the Year Ended December 31, 2005
Pro Forma | ||||||||||||||||||||
Pro Forma | As Adjusted | Pro Forma | ||||||||||||||||||
Total | Transaction | For Formation | Offering | |||||||||||||||||
Combined | Adjustments | Transactions | Adjustments | Pro Forma | ||||||||||||||||
(As Restated) | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Natural gas and oil revenue | $ | 45,147,909 | $ | (20,655,217 | ) | $ | 24,492,692 | $ | — | $ | 24,492,692 | |||||||||
Realized gain (loss) on natural gas swaps | (7,194,322 | ) | 3,242,190 | (3,952,132 | ) | — | (3,952,132 | ) | ||||||||||||
Transportation and marketing-related revenues | 6,224,787 | (120,255 | ) | 6,104,532 | — | 6,104,532 | ||||||||||||||
Total revenues | 44,178,374 | (17,533,282 | ) | 26,645,092 | — | 26,645,092 | ||||||||||||||
Operating costs and expenses: | ||||||||||||||||||||
Lease operating expenses | 7,235,775 | (1,797,043 | ) | 5,438,732 | (1,085,083 | ) | 4,353,649 | |||||||||||||
Purchased gas cost | 5,659,633 | — | 5,659,633 | — | 5,659,633 | |||||||||||||||
Production taxes | 292,382 | (68,379 | ) | 224,003 | — | 224,003 | ||||||||||||||
Asset retirement obligations accretion expenses | 170,543 | (124,669 | ) | 45,874 | — | 45,874 | ||||||||||||||
Exploration expenses | 2,538,617 | (2,538,617 | ) | — | — | — | ||||||||||||||
Dry hole costs | 530,377 | (530,377 | ) | — | — | — | ||||||||||||||
Impairment of unproved properties | 2,041,401 | (2,041,401 | ) | — | — | — | ||||||||||||||
Depreciation, depletion and amortization | 4,408,981 | (2,327,320 | ) | 2,081,661 | 2,230,641 | 4,312,302 | ||||||||||||||
General and administrative expenses | 899,157 | (227,327 | ) | 671,830 | 1,000,000 | 1,671,830 | ||||||||||||||
Management fees | 116,588 | — | 116,588 | (116,588 | ) | — | ||||||||||||||
Total operating costs and expenses | 23,893,454 | (9,655,133 | ) | 14,238,321 | 2,028,970 | 16,267,291 | ||||||||||||||
Gain (loss) on sale of other property | (172 | ) | 172 | — | — | — | ||||||||||||||
Operating income | 20,284,748 | (7,877,977 | ) | 12,406,771 | (2,028,970 | ) | 10,377,801 | |||||||||||||
Other income (expense), net | (427,676 | ) | (191,928 | ) | (619,604 | ) | 624,161 | 4,557 | ||||||||||||
Income before income taxes | 19,857,072 | (8,069,905 | ) | 11,787,167 | (1,404,809 | ) | 10,382,358 | |||||||||||||
Income tax provision (benefit) | 5,348,953 | (5,348,953 | ) | — | — | — | ||||||||||||||
Equity earnings in investments | 565,312 | (565,312 | ) | — | — | — | ||||||||||||||
Net income | $ | 15,073,431 | $ | (3,286,264 | ) | $ | 11,787,167 | $ | (1,404,809 | ) | $ | 10,382,358 | ||||||||
General partner’s interest in net income | $ | 207,647 | ||||||||||||||||||
Limited partners’ interest in net income | $ | 10,174,711 | ||||||||||||||||||
Net income per limited partner units | ||||||||||||||||||||
Common units (basic) | $ | 1.60 | ||||||||||||||||||
Subordinated units | $ | 0.96 | ||||||||||||||||||
Common units (diluted) | $ | 1.33 | ||||||||||||||||||
Weighted average limited partner units outstanding | ||||||||||||||||||||
Common units (basic) | 4,495,000 | |||||||||||||||||||
Subordinated units | 3,100,000 | |||||||||||||||||||
Common units (diluted) | 7,575,000 |
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Pro Forma as | ||||||||||||||||||||
Pro Forma | Adjusted for | Pro Forma | ||||||||||||||||||
Total | Transaction | Transaction | Offering | Pro Forma | ||||||||||||||||
Combined | Adjustments | Adjustments | Adjustments | as Adjusted | ||||||||||||||||
Revenues: | ||||||||||||||||||||
Natural gas and oil revenues | $ | 11,668,865 | $ | (6,046,706 | ) | $ | 5,622,159 | $ | — | $ | 5,622,159 | |||||||||
Realized gain on natural gas swaps | (189,786 | ) | 347,204 | 157,418 | — | 157,418 | ||||||||||||||
Transportation and marketing-related revenues | 1,679,620 | (19,699 | ) | 1,659,921 | — | 1,659,921 | ||||||||||||||
Total revenues | 13,158,699 | (5,719,201 | ) | 7,439,498 | — | 7,439,498 | ||||||||||||||
Operating costs and expenses: | ||||||||||||||||||||
Lease operating expenses | 1,798,788 | (420,611 | ) | 1,378,177 | (275,847 | ) | 1,102,330 | |||||||||||||
Purchased gas cost | 1,557,497 | — | 1,557,497 | — | 1,557,497 | |||||||||||||||
Production taxes | 52,368 | (13,126 | ) | 39,242 | — | 39,242 | ||||||||||||||
Asset retirement obligations accretion expenses | 44,008 | (31,168 | ) | 12,840 | — | 12,840 | ||||||||||||||
Exploration expenses | 58,458 | (58,458 | ) | — | — | — | ||||||||||||||
Dry hole costs | 149,475 | (149,475 | ) | — | — | — | ||||||||||||||
Depreciation, depletion and amortization | 1,104,760 | (554,016 | ) | 550,744 | 589,909 | 1,140,653 | ||||||||||||||
General and administrative expenses | 640,081 | (247,190 | ) | 392,891 | 250,000 | 642,891 | ||||||||||||||
Management fees | 34,899 | — | 34,899 | (34,899 | ) | — | ||||||||||||||
Total operating costs and expenses | 5,440,334 | (1,474,044 | ) | 3,966,290 | 529,163 | 4,495,453 | ||||||||||||||
Operating income | 7,718,365 | (4,245,157 | ) | 3,473,208 | (529,163 | ) | 2,944,045 | |||||||||||||
Other income (expense), net | (41,415 | ) | (139,984 | ) | (181,399 | ) | 183,939 | 2,540 | ||||||||||||
Income before income taxes | 7,676,950 | (4,385,141 | ) | 3,291,809 | (345,224 | ) | 2,946,585 | |||||||||||||
Income tax provision | 1,545,225 | (1,545,225 | ) | — | — | — | ||||||||||||||
Equity earnings in investments | 90,225 | (90,225 | ) | — | — | — | ||||||||||||||
Net income | $ | 6,221,950 | $ | (2,930,141 | ) | $ | 3,291,809 | $ | (345,224 | ) | $ | 2,946,585 | ||||||||
General partner’s interest in net income | $ | 58,932 | ||||||||||||||||||
Limited partners’ interest in net income | $ | 2,887,653 | ||||||||||||||||||
Net income per limited partner units: | ||||||||||||||||||||
Common units (basic) | $ | 0.40 | ||||||||||||||||||
Subordinated units | $ | 0.35 | ||||||||||||||||||
Common units (diluted) | $ | 0.38 | ||||||||||||||||||
Weighted average limited partner units outstanding: | ||||||||||||||||||||
Common units (basic) | 4,495,000 | |||||||||||||||||||
Subordinated units | 3,100,000 | |||||||||||||||||||
Common units (diluted) | 7,595,000 |
F-5
Table of Contents
1. | General |
2. | Formation Transactions, Structure and Offering |
• | EnerVest Production Partners, Ltd., is a Texas limited partnership(“EnerVest Production Partners”) formed in 2000. EnerVest Production Partners owns oil and gas producing properties in the Monroe field in Northern Louisiana. Prior to April 2006, EnerVest owned, directly or indirectly, all of the general and limited partnership interests in EnerVest Production Partners. |
• | EnerVest WV, L.P. is a Delaware limited partnership(“EnerVest WV”) formed in January 2003. EnerVest WV owns oil and gas producing properties primarily in West Virginia. Prior to April 2006, EnerVest owned a 1% interest in EnerVest WV as general partner and an unaffiliated institutional investor owned a 99% interest as limited partner. |
• | CGAS Exploration, Inc., is an Ohio corporation(“CGAS”) owned by a partnership formed by EnerVest. CGAS was acquired by this partnership in August 2003. EnerVest has a 25.75% interest as general partner in the partnership that owns CGAS, and unaffiliated institutional investors own an aggregate 74.25% interest as limited partners. |
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F-7
Table of Contents
3. | Unaudited Pro Forma Combined Balance Sheet Adjustments as of March 31, 2006 |
Transaction | ||||||||||||||||
(a) | (b) | (c) | Adjustments | |||||||||||||
ASSETS | ||||||||||||||||
Current assets: | ||||||||||||||||
Cash and cash equivalents | $ | — | $ | (2,519,966 | ) | $ | — | $ | (2,519,966 | ) | ||||||
Accounts receivable | 454 | (3,400,388 | ) | — | (3,399,934 | ) | ||||||||||
Commodity hedge asset | — | 418,043 | — | 418,043 | ||||||||||||
Deferred tax asset | — | (443,155 | ) | — | (443,155 | ) | ||||||||||
Other current assets | (1,365 | ) | (91,624 | ) | — | (92,989 | ) | |||||||||
Total current assets | (911 | ) | (6,037,090 | ) | — | (6,038,001 | ) | |||||||||
Natural gas and oil properties, net | (68,052 | ) | (21,782,088 | ) | 7,291,376 | (14,558,764 | ) | |||||||||
Property, plant and equipment, net | — | (300,919 | ) | — | (300,919 | ) | ||||||||||
Long-term commodity hedge asset | — | (904,495 | ) | — | (904,495 | ) | ||||||||||
Other assets | (1,359,800 | ) | (149,037 | ) | — | (1,508,837 | ) | |||||||||
Total assets | $ | (1,428,763 | ) | $ | (29,173,629 | ) | $ | 7,291,376 | $ | (23,311,016 | ) | |||||
LIABILITIES AND OWNERS’ EQUITY | ||||||||||||||||
Current liabilities: | ||||||||||||||||
Accounts payable and accrued liabilities | $ | (366,634 | ) | $ | (956,217 | ) | $ | — | $ | (1,322,851 | ) | |||||
Due to affiliates | (7,885 | ) | (430,477 | ) | — | (438,362 | ) | |||||||||
Commodity hedge liability | — | (1,460,480 | ) | — | (1,460,480 | ) | ||||||||||
Current income tax payable | — | (2,623,587 | ) | — | (2,623,587 | ) | ||||||||||
Deferred income tax liability | — | (201,603 | ) | — | (201,603 | ) | ||||||||||
Other current liabilities | — | (38,934 | ) | — | (38,934 | ) | ||||||||||
Total current liabilities | (374,519 | ) | (5,711,298 | ) | — | (6,085,817 | ) | |||||||||
Long-term debt | — | — | — | — | ||||||||||||
Asset retirement obligations | (50,768 | ) | (563,141 | ) | — | (613,909 | ) | |||||||||
Deferred income tax liability | — | (4,722,612 | ) | — | (4,722,612 | ) | ||||||||||
Owners’ equity | (1,003,476 | ) | (18,176,578 | ) | 7,291,376 | (11,888,678 | ) | |||||||||
Total liabilities and owners’ equity | $ | (1,428,763 | ) | $ | (29,173,629 | ) | $ | 7,291,376 | $ | (23,311,016 | ) | |||||
(a) | Reflects the exclusion of the net assets of EnerVest Production Partners which were distributed to EnerVest in connection with the formation of EV Properties in April 2006. | |
(b) | Reflects the exclusion of the net assets owned by CGAS which are not being contributed to the Partnership. |
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(c) | Reflects the amount by which the net $16.0 million investment made by the EnCap Partnerships into EV Properties exceeds the book value of the existing 99% limited partner interest in EnerVest WV. Such $16.0 million investment was used to purchase the existing 99% limited partner interest in EnerVest WV. |
Offering | ||||||||||||||||||||
(d) | (e) | (f) | (g) | Adjustments | ||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 70,540,000 | $ | (10,350,000 | ) | $ | (60,190,000 | ) | $ | — | ||||||||
Accounts receivable, net | — | — | — | — | — | |||||||||||||||
Commodity hedge asset | — | — | — | — | — | |||||||||||||||
Deferred tax asset | — | — | — | — | — | |||||||||||||||
Other current assets | — | — | — | — | — | |||||||||||||||
Total current assets | — | 70,540,000 | (10,350,000 | ) | (60,190,000 | ) | — | |||||||||||||
Natural gas and oil properties, net | 44,844,134 | — | — | — | 44,844,134 | |||||||||||||||
Property, plant and equipment, net | — | — | — | — | — | |||||||||||||||
Long-term commodity hedge asset | — | — | — | — | — | |||||||||||||||
Other assets | — | — | — | — | — | |||||||||||||||
Total assets | $ | 44,844,134 | $ | 70,540,000 | $ | (10,350,000 | ) | $ | (60,190,000 | ) | $ | 44,844,134 | ||||||||
LIABILITIES AND OWNERS’ EQUITY | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable & accrued liabilities | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
Due to affiliates | — | — | — | — | — | |||||||||||||||
Commodity hedge liability | — | — | — | — | — | |||||||||||||||
Current income tax payable | — | — | — | — | — | |||||||||||||||
Deferred income tax liability | ||||||||||||||||||||
Other current liabilities | — | — | — | — | — | |||||||||||||||
Total current liabilities | — | — | — | — | — | |||||||||||||||
Long-term debt | — | — | (10,350,000 | ) | — | (10,350,000 | ) | |||||||||||||
Asset retirement obligations | — | — | — | — | — | |||||||||||||||
Deferred income tax liability | — | — | — | — | — | |||||||||||||||
Owners’ equity | 44,844,134 | 70,540,000 | — | (60,190,000 | ) | 55,194,134 | ||||||||||||||
Total liabilities and owners’ equity | $ | 44,844,134 | $ | 70,540,000 | $ | (10,350,000 | ) | $ | (60,190,000 | ) | $ | 44,844,134 | ||||||||
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Table of Contents
(d) | Reflects thewrite-up to fair value of the portion of the oil and gas properties contributed by CGAS to the Partnership and attributable to interest in CGAS owned by the third party investors in the institutional partnership that owns CGAS. | |
(e) | Reflects the cash proceeds of $70.5 million from the issuance of 3.9 million common units by the Partnership, net of estimated offering costs of $7.5 million (based on an assumed initial public offering price of $20.00 per common unit, the midpoint of the range of estimated initial public offering prices set forth on the cover page of this Prospectus). Offering costs primarily consist of underwriting discounts and commissions, accounting fees, legal fees and printing expenses. | |
(f) | Reflects the use of a portion of the proceeds of this Offering to repay indebtedness incurred by one of the Combined Predecessor Entities to purchase oil and gas properties. | |
(g) | Reflects the cash distribution to EnerVest, the Encap Partnerships and CGAS of a portion of the proceeds from this Offering. |
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4. | Unaudited Pro Forma Combined Statement of Operations Adjustments for the Year Ended December 31, 2005 |
Transaction Adjustments | Offering Adjustments | Pro Forma | ||||||||||||||||||||||||||||||
(a) | (b) | (c) | (d) | (e) | (f) | (g) | Adjustments | |||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||||||||
Natural gas and oil revenue | $ | (369,805 | ) | $ | (20,769,497 | ) | $ | — | $ | 484,085 | $ | — | $ | — | $ | — | $ | (20,655,217 | ) | |||||||||||||
Realized gain (loss) on natural gas swaps | — | 3,242,190 | — | — | — | — | — | 3,242,190 | ||||||||||||||||||||||||
Transportation and marketing-related revenues | — | (144,200 | ) | — | 23,945 | — | — | — | (120,255 | ) | ||||||||||||||||||||||
Total revenues | (369,805 | ) | (17,671,507 | ) | — | 508,030 | — | — | — | (17,533,282 | ) | |||||||||||||||||||||
Operating costs and expenses: | ||||||||||||||||||||||||||||||||
Lease operating expenses | (131,064 | ) | (1,780,926 | ) | — | 114,947 | — | (1,085,083 | ) | — | (2,882,126 | ) | ||||||||||||||||||||
Production taxes | (22,354 | ) | (46,025 | ) | — | — | — | — | — | (68,379 | ) | |||||||||||||||||||||
Asset retirement obligations accretion expenses | (3,422 | ) | (121,247 | ) | — | — | — | — | — | (124,669 | ) | |||||||||||||||||||||
Exploration expenses | — | (2,538,617 | ) | — | — | — | — | — | (2,538,617 | ) | ||||||||||||||||||||||
Dry hole costs | — | (530,377 | ) | — | — | — | — | — | (530,377 | ) | ||||||||||||||||||||||
Impairment of unproved properties | — | (2,041,401 | ) | — | — | — | — | — | (2,041,401 | ) | ||||||||||||||||||||||
Depreciation, depletion and amortization | (6,999 | ) | (2,772,350 | ) | 350,490 | 101,539 | 2,230,641 | — | — | (96,679 | ) | |||||||||||||||||||||
General and administrative expenses | (26,500 | ) | (200,827 | ) | — | — | — | 1,000,000 | — | 772,673 | ||||||||||||||||||||||
Management fees | — | — | — | — | — | (116,588 | ) | — | (116,588 | ) | ||||||||||||||||||||||
Total operating costs and expenses | (190,339 | ) | (10,031,770 | ) | 350,490 | 216,486 | 2,230,641 | (201,671 | ) | — | (7,626,163 | ) | ||||||||||||||||||||
Gain (loss) on sale of other property | 172 | — | — | — | — | — | — | 172 | ||||||||||||||||||||||||
Operating income | (179,294 | ) | (7,639,737 | ) | (350,490 | ) | 291,544 | (2,230,641 | ) | 201,671 | — | (9,906,947 | ) | |||||||||||||||||||
Other income (expense), net | — | (191,928 | ) | — | — | — | — | 624,161 | 432,233 | |||||||||||||||||||||||
Income before income taxes | (179,294 | ) | (7,831,665 | ) | (350,490 | ) | 291,544 | (2,230,641 | ) | 201,671 | 624,161 | (9,474,714 | ) | |||||||||||||||||||
Provision (benefit) for income taxes | — | (5,348,953 | ) | — | — | — | — | — | (5,348,953 | ) | ||||||||||||||||||||||
Equity earnings in investments | (565,312 | ) | — | — | — | — | — | — | (565,312 | ) | ||||||||||||||||||||||
Net income (loss) | $ | (744,606 | ) | $ | (2,482,712 | ) | $ | (350,490 | ) | $ | 291,544 | $ | (2,230,641 | ) | $ | 201,671 | $ | 624,161 | $ | (4,691,073 | ) | |||||||||||
(a) | Reflects the elimination of revenues and expenses of EnerVest Production Partners attributable to net assets which were distributed to EnerVest in connection with the formation of EV Properties in April 2006. | |
(b) | Reflects the elimination of revenues and expenses of CGAS attributable to net assets which are not being contributed to the Partnership. |
(c) | Reflects incremental depreciation, depletion, and amortization expense attributable to a $6.6 million increase in oil and gas properties resulting from the purchase by EV Properties of the limited partnership interest in EnerVest WV owned by an unaffiliated institutional investor. This limited partnership interest was purchased for $16.0 million using the proceeds of the capital contribution made by the EnCap Partnerships to EV Properties. |
(d) | Reflects revenue and operating income generated from the acquisition of properties in Northern Louisiana prior to the date of acquisition. These properties were acquired on March 1, 2005. |
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(e) | Reflects incremental depletion expense attributable to a $48.7 million increase to oil and gas properties reflecting the interest in the assets contributed by CGAS owned by the third party investors in the institutional partnership that owns CGAS. | |
(f) | Reflects the elimination of management fees charged to EnerVest WV by EnerVest and certain administrative costs charged to EnerVest Production Partners and EnerVest WV for wells operated by EnerVest, and the recognition of general and administrative expenses to be charged to the Partnership by EnerVest under a new services agreement. | |
(g) | Reflects the elimination of $0.6 million of interest expense related to the repayment out of net proceeds of the offering of $10.5 million of indebtedness incurred by one of the Combined Predecessor Entities to purchase oil and gas properties. |
Transaction Adjustments | Offering Adjustments | Pro Forma | ||||||||||||||||||||||||||
(a) | (b) | (c) | (d) | (e) | (f) | Adjustments | ||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||||
Natural gas and oil revenue | $ | (75,101 | ) | $ | (5,971,605 | ) | $ | — | $ | — | $ | — | $ | — | $ | (6,046,706 | ) | |||||||||||
Realized gain on natural gas swaps | — | 347,204 | — | — | — | — | 347,204 | |||||||||||||||||||||
Transportation and marketing- related revenues | — | (19,699 | ) | — | — | — | — | (19,699 | ) | |||||||||||||||||||
Total revenues | (75,101 | ) | (5,644,100 | ) | — | — | — | — | (5,719,201 | ) | ||||||||||||||||||
Operating costs and expenses: | ||||||||||||||||||||||||||||
Lease operating expenses | (25,296 | ) | (395,315 | ) | — | — | (275,847 | ) | — | (696,458 | ) | |||||||||||||||||
Production taxes | (4,184 | ) | (8,942 | ) | — | — | — | — | (13,126 | ) | ||||||||||||||||||
Asset retirement obligations accretion expenses | (856 | ) | (30,312 | ) | — | — | — | — | (31,168 | ) | ||||||||||||||||||
Exploration expenses | — | (58,458 | ) | — | — | — | — | (58,458 | ) | |||||||||||||||||||
Dry hole costs | — | (149,475 | ) | — | — | — | — | (149,475 | ) | |||||||||||||||||||
Depreciation, depletion and amortization | (8,732 | ) | (642,800 | ) | 97,516 | 589,909 | — | — | 35,893 | |||||||||||||||||||
General and administrative expenses | (13,654 | ) | (233,536 | ) | — | — | 250,000 | — | 2,810 | |||||||||||||||||||
Management fees | — | — | — | — | (34,899 | ) | — | (34,899 | ) | |||||||||||||||||||
Total operating costs and expenses | (52,722 | ) | (1,518,838 | ) | 97,516 | 589,909 | (60,746 | ) | — | (944,881 | ) | |||||||||||||||||
Operating income | (22,379 | ) | (4,125,262 | ) | (97,516 | ) | (589,909 | ) | 60,746 | — | (4,774,320 | ) | ||||||||||||||||
Other income (expense), net | — | (139,984 | ) | — | — | — | 183,939 | 43,955 | ||||||||||||||||||||
Income before income taxes | (22,379 | ) | (4,265,246 | ) | (97,516 | ) | (589,909 | ) | 60,746 | 183,939 | (4,730,365 | ) | ||||||||||||||||
Provision for income taxes | — | (1,545,225 | ) | — | — | — | — | (1,545,225 | ) | |||||||||||||||||||
Equity earnings in investments | (90,225 | ) | — | — | — | — | — | (90,225 | ) | |||||||||||||||||||
Net income | $ | (112,604 | ) | $ | (2,720,021 | ) | $ | (97,516 | ) | $ | (589,909 | ) | $ | 60,746 | $ | 183,939 | $ | (3,275,365 | ) | |||||||||
(a) | Reflects the elimination of revenues and expenses of EnerVest Production Partners attributable to net assets which were distributed to EnerVest in connection with the formation of EV Properties in April 2006. |
(b) | Reflects the elimination of revenues and expenses of CGAS attributable to net assets which are not being contributed to the Partnership. |
(c) | Reflects incremental depreciation, depletion, and amortization expense attributable to a $7.3 million increase in oil and gas properties resulting from the purchase by EV Properties of the limited partnership |
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interest in EnerVest WV owned by an unaffiliated institutional investor. This limited partnership interest was purchased for $16.0 million using the proceeds of the capital contribution made by the EnCap Partnerships in EV Properties. |
(d) | Reflects incremental depletion expense attributable to a $44.8 million increase to oil and gas properties reflecting the interest in the assets contributed by CGAS owned by the third party investors in the institutional partnership that owns CGAS. |
(e) | Reflects the elimination of management fees charged to EnerVest WV by EnerVest and certain administrative costs charged to EnerVest Production Partners and EnerVest WV for wells operated by EnerVest, and the recognition of general and administrative expenses to be charged to the Partnership by EnerVest under a new services agreement. |
(f) | Reflects the elimination of $0.2 million of interest expense related to the repayment out of net proceeds of the offering of $10.4 million of indebtedness incurred by one of the Combined Predecessor Entities to purchase oil and gas properties. |
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Table of Contents
6. | Estimated Proved Oil and Gas Reserves |
Total Combined | Pro Forma Adjustments(d) | Pro Forma as Adjusted | ||||||||||||||||||||||||||||||
Natural Gas | Oil | Natural Gas | Oil | Natural Gas | Oil | |||||||||||||||||||||||||||
(Mcf)(a) | (Bbls)(b) | Mcfe(c) | (Mcf)(a) | (Bbls)(b) | (Mcf)(a) | (Bbls)(b) | Mcfe(c) | |||||||||||||||||||||||||
Proved reserves: | ||||||||||||||||||||||||||||||||
Proved reserves, December 31, 2004 | 35,751,831 | 1,484,630 | 44,659,611 | (4,197,947 | ) | (501,744 | ) | 31,553,884 | 982,886 | 37,451,200 | ||||||||||||||||||||||
Purchase of minerals in place | 9,815,775 | — | 9,815,775 | — | — | 9,815,775 | — | 9,815,775 | ||||||||||||||||||||||||
Revision of previous estimates | 2,307,946 | 155,946 | 3,243,622 | (1,589,093 | ) | (139,937 | ) | 718,853 | 16,009 | 814,907 | ||||||||||||||||||||||
Production | (3,900,824 | ) | (174,425 | ) | (4,947,374 | ) | 1,646,978 | 116,066 | (2,253,846 | ) | (58,359 | ) | (2,604,000 | ) | ||||||||||||||||||
Extensions and discoveries | 6,907,893 | 201,892 | 8,119,245 | (1,934,626 | ) | (70,928 | ) | 4,973,267 | 130,964 | 5,759,051 | ||||||||||||||||||||||
Proved reserves, December 31, 2005 | 50,882,621 | 1,668,043 | 60,890,879 | (6,074,688 | ) | (596,543 | ) | 44,807,933 | 1,071,500 | 51,236,933 | ||||||||||||||||||||||
Proved developed reserves: | ||||||||||||||||||||||||||||||||
December 31, 2005 | 45,820,825 | 1,552,561 | 55,136,191 | (6,075,881 | ) | (596,812 | ) | 39,744,944 | 955,749 | 45,479,438 | ||||||||||||||||||||||
(a) | Thousand cubic feet. |
(b) | Barrels. |
(c) | Thousand cubic feet equivalent, barrels are converted to Mcfe based on one barrel of oil to six Mcf of natural gas equivalent. |
(d) | Reflects the exclusion of reserves attributable to the net assets of EnerVest Production Partners which were distributed to EnerVest in connection with the formation of EV Properties in April 2006, the exclusion of reserves attributable to the net assets owned by CGAS which are not being contributed to the Partnership, and an adjustment to reserves attributable to the elimination of certain administrative costs charged to EnerVest Production Partners and EnerVest WV for wells operated by EnerVest by virtue of a new services agreement to be entered into between the Partnership and EnerVest. |
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Table of Contents
7. | Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves |
• | Future revenues were based on year-end oil and gas prices. Future price changes were included only to the extent provided by existing contractual agreements. |
• | Production and development costs were computed using year-end costs assuming no change in present economic conditions. |
• | Future net cash flows were discounted at an annual rate of 10%. |
• | Future income taxes were computed only for the CGAS entity using the approximate statutory tax rate and giving effect to available net operating losses, tax credits and statutory depletion in the combined predecessor presentation. No future income taxes were computed for EnerVest WV or EnerVest Production Partners in accordance with their standing as non-taxable entities in the combined predecessor presentation. No future income taxes were computed in the Pro Forma as Adjusted presentation in accordance with the Partnership’s standing as a non-taxable entity. |
Year Ended December 31, 2005 | ||||||||||||
Total | Pro Forma | Pro Forma as | ||||||||||
Combined | Adjustments(a) | Adjusted | ||||||||||
(in thousands) | ||||||||||||
Estimated future cash inflows: | ||||||||||||
Revenues from sale of oil & gas | $ | 643,848 | $ | (105,045 | ) | $ | 538,803 | |||||
Production costs | (181,962 | ) | 32,265 | (149,697 | ) | |||||||
Development costs | (15,593 | ) | 15 | (15,578 | ) | |||||||
Future net cash flows before income taxes | 446,293 | (72,765 | ) | 373,528 | ||||||||
Future income taxes | (76,033 | ) | 76,033 | — | ||||||||
Future net cash flows | 370,260 | 3,268 | 373,528 | |||||||||
10% annual timing discount | (187,851 | ) | (24,434 | ) | (212,285 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 182,409 | (21,166 | ) | 161,243 | |||||||
(a) | Reflects the exclusion of revenues and expenses attributable to the net assets of EnerVest Production Partners which were distributed to EnerVest in connection with the formation of EV Properties in April 2006, the exclusion of revenues and expenses attributable to the net assets owned by CGAS which are not being contributed to the Partnership, the elimination of future income taxes as computed by CGAS, and an adjustment to revenues and expenses attributable to the elimination of certain administrative costs charged to EnerVest Production Partners and EnerVest WV for wells operated by EnerVest by virtue of a new services agreement to be entered into between the Partnership and EnerVest. |
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Table of Contents
Year Ended December 31, 2005 | ||||||||||||
Combined | Pro Forma | Pro Forma as | ||||||||||
Total | Adjustments (a) | Adjusted | ||||||||||
(In thousands) | ||||||||||||
Beginning of year | $ | 80,772 | $ | (8,681 | ) | 72,091 | ||||||
Sale of oil and gas, net of production costs | (31,259 | ) | 13,310 | (17,949 | ) | |||||||
Purchase of minerals in place | 15,804 | 37 | 15,841 | |||||||||
Extensions and discoveries | 36,668 | (18,571 | ) | 18,097 | ||||||||
Development costs incurred | 5,097 | — | 5,097 | |||||||||
Changes in estimated future development costs | (19,972 | ) | 15 | (19,957 | ) | |||||||
Net changes in prices and production costs | 77,351 | (15,381 | ) | 61,970 | ||||||||
Revisions and other | 33,207 | (15,542 | ) | 17,665 | ||||||||
Changes in income taxes | (24,515 | ) | 24,515 | — | ||||||||
Accretion of 10% timing discount | 9,256 | (868 | ) | 8,388 | ||||||||
End of period | $ | 182,409 | $ | (21,166 | ) | 161,243 | ||||||
(a) | Reflects the exclusion of revenues and expenses attributable to the net assets of EnerVest Production Partners which were distributed to EnerVest in connection with the formation of EV Properties in April 2006, the exclusion of revenues and expenses attributable to the net assets owned by CGAS which are not being contributed to the Partnership, the elimination of future income taxes as computed by CGAS, and an adjustment to revenues and expenses attributable to the elimination of certain administrative costs charged to EnerVest Production Partners and EnerVest WV for wells operated by EnerVest by virtue of a new services agreement to be entered into between the Partnership and EnerVest. |
F-16
Table of Contents
F-17
Table of Contents
December 31, | ||||||||
2004 | 2005 | |||||||
(As Restated, | ||||||||
see Note 16) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 1,671,871 | $ | 7,158,839 | ||||
Accounts receivable-gas and oil sales | 8,560,185 | 8,797,620 | ||||||
Accounts receivable-other | 222,880 | 530,007 | ||||||
Due from affiliates | — | 95,701 | ||||||
Interest and commodity hedge asset-related party | 53,493 | 60,982 | ||||||
Income tax receivable | 463,404 | — | ||||||
Deferred tax asset | 3,912 | 1,875,582 | ||||||
Other current assets | 388,522 | 617,005 | ||||||
Total current assets | 11,364,267 | 19,135,736 | ||||||
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization | 46,483,515 | 57,036,687 | ||||||
Other property, net of accumulated depreciation and amortization | 687,421 | 563,457 | ||||||
Other assets | 265,953 | 1,427,197 | ||||||
Total assets | $ | 58,801,156 | $ | 78,163,077 | ||||
LIABILITIES AND OWNERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued liabilities | $ | 3,261,725 | $ | 5,968,004 | ||||
Due to affiliates | 3,323,809 | 6,386,954 | ||||||
Commodity hedge liability-related party | — | 5,228,445 | ||||||
Commodity hedge liability-third party | 153,707 | 953,955 | ||||||
Advances-related party | 1,135,718 | — | ||||||
Current income tax liability | — | 1,170,573 | ||||||
Other current liabilities | 394,634 | 69,934 | ||||||
Total current liabilities | 8,269,593 | 19,777,865 | ||||||
Asset retirement obligations | 2,049,899 | 2,752,137 | ||||||
Long-term debt | 2,850,000 | 10,500,000 | ||||||
Deferred income tax liability | 4,416,189 | 4,204,945 | ||||||
Long-term commodity hedge liability-related party | — | 18,442 | ||||||
Total liabilities | 17,585,681 | 37,253,389 | ||||||
Commitments and contingencies (See Note 11) | ||||||||
Owners’ equity, excluding accumulated other comprehensive loss | 41,315,689 | 45,177,875 | ||||||
Accumulated other comprehensive loss | (100,214 | ) | (4,268,187 | ) | ||||
Total owners’ equity | 41,215,475 | 40,909,688 | ||||||
Total liabilities and owners’ equity | $ | 58,801,156 | $ | 78,163,077 | ||||
F-18
Table of Contents
(As Defined in Note 1)
Combined Statements of Operations and Comprehensive Income
Year Ended December 31, | ||||||||||||
2003 | 2004 | 2005 | ||||||||||
(As Restated, see Note 16) | ||||||||||||
Revenues: | ||||||||||||
Natural gas and oil revenues | $ | 10,369,684 | $ | 28,336,253 | $ | 45,147,909 | ||||||
Realized loss on natural gas swaps | (242,223 | ) | (1,890,551 | ) | (7,194,322 | ) | ||||||
Transportation and marketing-related revenues | 3,443,082 | 3,437,618 | 6,224,787 | |||||||||
Total revenues | 13,570,543 | 29,883,320 | 44,178,374 | |||||||||
Operating costs and expenses: | ||||||||||||
Lease operating expenses | 3,466,295 | 6,614,651 | 7,235,775 | |||||||||
Purchased gas cost | 2,933,306 | 3,002,779 | 5,659,633 | |||||||||
Production taxes | 64,486 | 119,293 | 292,382 | |||||||||
Asset retirement obligations accretion expense | 67,341 | 160,433 | 170,543 | |||||||||
Exploration expenses | 1,337,713 | 1,281,098 | 2,538,617 | |||||||||
Dry hole costs | — | 439,844 | 530,377 | |||||||||
Impairment of unproved properties | — | 1,415,400 | 2,041,401 | |||||||||
Depreciation, depletion and amortization | 1,836,675 | 4,134,542 | 4,408,981 | |||||||||
General and administrative expenses | 1,069,009 | 1,060,451 | 899,157 | |||||||||
Management fees | 69,173 | 94,352 | 116,588 | |||||||||
Total operating costs and expenses | 10,843,998 | 18,322,843 | 23,893,454 | |||||||||
Gain (loss) on sale of other property | 30,191 | 130,227 | (172 | ) | ||||||||
Operating income | 2,756,736 | 11,690,704 | 20,284,748 | |||||||||
Other income (expense), net: | ||||||||||||
Interest and financing expense-third party | (126,345 | ) | (157,442 | ) | (625,151 | ) | ||||||
Interest and financing expense-related party | — | (169,140 | ) | (6,993 | ) | |||||||
Other income, net | 360,630 | 208,700 | 204,468 | |||||||||
Total other income (expense), net | 234,285 | (117,882 | ) | (427,676 | ) | |||||||
Income before income tax provision | 2,991,021 | 11,572,822 | 19,857,072 | |||||||||
Income tax provision | 317,234 | 2,521,821 | 5,348,953 | |||||||||
Equity earnings (loss) in investments | 3,028 | (620,447 | ) | 565,312 | ||||||||
Net income | 2,676,815 | 8,430,554 | 15,073,431 | |||||||||
Other comprehensive loss | — | (100,214 | ) | (4,167,973 | ) | |||||||
Comprehensive income | $ | 2,676,815 | $ | 8,330,340 | $ | 10,905,458 | ||||||
F-19
Table of Contents
Year Ended December 31, | ||||||||||||
2003 | 2004 | 2005 | ||||||||||
(As Restated, | ||||||||||||
see Note 16) | ||||||||||||
Cash flows from operating activities: | ||||||||||||
Net income | $ | 2,676,815 | $ | 8,430,554 | $ | 15,073,431 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Loss (gain) on sale of other property | (30,191 | ) | (130,227 | ) | 172 | |||||||
Impairment of unproved properties | — | 1,415,400 | 2,041,401 | |||||||||
Asset retirement obligations accretion expense | 67,341 | 160,433 | 170,543 | |||||||||
Depreciation, depletion, and amortization | 1,836,675 | 4,134,542 | 4,408,981 | |||||||||
Dry hole cost | — | 439,844 | 530,377 | |||||||||
Equity earnings (loss) in investments, net of distribution | (3,028 | ) | 632,862 | (242,834 | ) | |||||||
Other expense | 25,017 | — | — | |||||||||
Deferred income tax expense (benefit) | 280,591 | 1,850,225 | (211,244 | ) | ||||||||
Increase in accounts receivable | (1,231,434 | ) | (3,874,370 | ) | (544,562 | ) | ||||||
Increase in due from affiliates | — | — | (95,701 | ) | ||||||||
Decrease (increase) in income tax receivable | — | (463,404 | ) | 463,404 | ||||||||
Increase in other current assets | (65,909 | ) | (77,825 | ) | (228,483 | ) | ||||||
Increase in accounts payable and accrued liabilities | 504,741 | 1,774,704 | 2,706,279 | |||||||||
(Decrease) increase in due to affiliates | (651,272 | ) | 2,055,279 | 3,061,575 | ||||||||
Increase in current tax liability | — | — | 1,170,573 | |||||||||
(Decrease) increase in other current liabilities | (27,603 | ) | 356,323 | (324,700 | ) | |||||||
Net cash provided by operating activities | 3,381,743 | 16,704,340 | 27,979,212 | |||||||||
Cash flows from investing activities: | ||||||||||||
Development of oil and gas properties | (2,053,668 | ) | (5,410,169 | ) | (5,627,371 | ) | ||||||
Acquisition of oil and gas properties | (8,382,698 | ) | (282,482 | ) | (11,223,397 | ) | ||||||
Cash acquired from CGAS | 2,429,315 | — | — | |||||||||
Acquisition of other properties | (300,000 | ) | (11,630 | ) | (38,373 | ) | ||||||
Property sales proceeds | 77,731 | 2,379,500 | 10,700 | |||||||||
Investment in equity investee | (246,842 | ) | (496,575 | ) | (918,411 | ) | ||||||
Net cash used in investing activities | (8,476,162 | ) | (3,821,356 | ) | (17,796,852 | ) | ||||||
Cash flows from financing activities: | ||||||||||||
Repayment of advance-related party | (773,264 | ) | (10,091,018 | ) | (1,135,718 | ) | ||||||
Debt borrowings | — | — | 8,650,000 | |||||||||
Contributions by partners | 9,022,930 | — | 2,028,500 | |||||||||
Distribution to partners and dividends paid | (2,231,030 | ) | (2,068,730 | ) | (14,238,174 | ) | ||||||
Net cash provided by (used in) financing activities | 6,018,636 | (12,159,748 | ) | (4,695,392 | ) | |||||||
Net increase in cash and cash equivalents | 924,217 | 723,236 | 5,486,968 | |||||||||
Cash and cash equivalents at beginning of year | 24,418 | 948,635 | 1,671,871 | |||||||||
Cash and cash equivalents at end of year | $ | 948,635 | $ | 1,671,871 | $ | 7,158,839 | ||||||
Supplemental schedule of cash flow information: | ||||||||||||
Cash paid for interest | $ | 126,345 | $ | 291,483 | $ | 569,441 | ||||||
Cash paid for income taxes | $ | 25,000 | $ | 1,135,000 | $ | 3,921,000 | ||||||
Non-cash contribution of CGAS net assets | $ | 23,605,473 | $ | — | $ | — | ||||||
Non-cash debt reduction | $ | — | $ | (200,000 | ) | $ | (1,000,000 | ) | ||||
F-20
Table of Contents
(As Defined in Note 1)
For the Years Ended December 31, 2003, 2004 and 2005
Owners’ | ||||||||||||
Equity | ||||||||||||
Excluding | ||||||||||||
Accumulated | Accumulated | |||||||||||
Other | Other | Total | ||||||||||
Comprehensive | Comprehensive | Owners’ | ||||||||||
Loss | Loss | Equity | ||||||||||
Balance January 1, 2003 | $ | (747,475 | ) | — | $ | (747,475 | ) | |||||
Contribution of EnerVest WV | 8,800,000 | 8,800,000 | ||||||||||
Contribution of CGAS | 26,034,788 | — | 26,034,788 | |||||||||
Contributions | 222,930 | — | 222,930 | |||||||||
Distributions | (2,231,030 | ) | — | (2,231,030 | ) | |||||||
Net income | 2,676,815 | — | 2,676,815 | |||||||||
Balance December 31, 2003 | 34,756,028 | — | 34,756,028 | |||||||||
Contributions (Restated) | 197,837 | — | 197,837 | |||||||||
Distributions (Restated) | (2,068,730 | ) | — | (2,068,730 | ) | |||||||
Unrealized gain (loss) on derivatives | — | (1,875,895 | ) | (1,875,895 | ) | |||||||
Reclassification adjustment into earnings | — | 1,775,681 | 1,775,681 | |||||||||
Net income | 8,430,554 | — | 8,430,554 | |||||||||
Balance December 31, 2004 | 41,315,689 | (100,214 | ) | 41,215,475 | ||||||||
Contributions | 3,028,500 | — | 3,028,500 | |||||||||
Distributions | (5,185,823 | ) | — | (5,185,823 | ) | |||||||
Dividends | (9,053,922 | ) | — | (9,053,922 | ) | |||||||
Unrealized gain (loss) on derivatives | — | (8,390,610 | ) | (8,390,610 | ) | |||||||
Reclassification adjustment into earnings | — | 4,222,637 | 4,222,637 | |||||||||
Net income | 15,073,431 | — | 15,073,431 | |||||||||
Balance December 31, 2005 | $ | 45,177,875 | (4,268,187 | ) | $ | 40,909,688 | ||||||
F-21
Table of Contents
1. | Organization |
• | EnerVest Production Partners, Ltd., is a Texas limited partnership(“EnerVest Production Partners”) formed in 2000. EnerVest Production Partners owns oil and gas producing properties in the Monroe field in Northern Louisiana. Prior to April 2006, EnerVest owned, directly or indirectly, all of the general and limited partnership interests in EnerVest Production Partners. | |
• | EnerVest WV, L.P. is a Delaware limited partnership(“EnerVest WV”) formed in 2003. EnerVest WV owns oil and gas producing properties primarily in West Virginia. Prior to April 2006, EnerVest owned a 1% interest in EnerVest WV as general partner and an unaffiliated institutional investor owned a 99% interest as limited partner. | |
• | CGAS Exploration, Inc., is an Ohio corporation(“CGAS”) owned by a partnership formed by EnerVest. CGAS was acquired by this partnership in August 2003. EnerVest has a 25.75% interest as general partner in the partnership that owns CGAS, and unaffiliated institutional investors own an aggregate 74.25% interest as limited partners. |
F-22
Table of Contents
2. | Summary of Significant Accounting Policies |
F-23
Table of Contents
F-24
Table of Contents
December 31, | ||||||||
2004 | 2005 | |||||||
Total Assets | $ | 2,217,953 | $ | 6,474,897 | ||||
Total Liabilities | 589,235 | 2,138,322 | ||||||
Net Income (Loss) | $ | (1,296,817 | ) | $ | 1,099,493 |
F-25
Table of Contents
F-26
Table of Contents
F-27
Table of Contents
3. | Oil and Gas Acquisition |
4. | Details of Balance Sheet Accounts |
December 31, | ||||||||
2004 | 2005 | |||||||
Due from Affiliates | ||||||||
EnerVest Operating, L.L.C.(a) | $ | — | $ | 95,701 | ||||
$ | — | $ | 95,701 | |||||
Due to Affiliates | ||||||||
EnerVest Acquisitions, L.P.(b) | $ | 1,775,680 | $ | 4,223,250 | ||||
EnerVest Operating, L.L.C.(c) | 775,108 | 87,759 | ||||||
EnerVest Management Partners, L.P.(d) | 765,136 | 2,003,672 | ||||||
EnerVest Olanta, L.P.(e) | — | 64,388 | ||||||
EnerVest Texoma, L.P. | 7,885 | 7,885 | ||||||
$ | 3,323,809 | $ | 6,386,954 | |||||
Other Assets | ||||||||
Equity method investments in affiliates(f) | $ | 113,581 | $ | 1,274,825 | ||||
Equity method investments in independent third parties | 99,950 | 99,950 | ||||||
Escrowed deposits(g) | 52,287 | 52,287 | ||||||
Other assets | 135 | 135 | ||||||
$ | 265,953 | $ | 1,427,197 | |||||
Accounts Payable and Accrued Liabilities | ||||||||
Accrued liabilities(h) | $ | 172,493 | $ | 171,595 | ||||
Trade payables(i) | 3,089,232 | 5,796,409 | ||||||
$ | 3,261,725 | $ | 5,968,004 | |||||
(a) | Net receivable for undistributed oil and gas sales proceeds and operating expenses from operator. | |
(b) | Payable for intercompany hedge liability incurred and unsettled at year end. | |
(c) | Accrued liabilities for costs paid on behalf of CGAS and amounts due for capital and operating expenditures made on behalf of EnerVest WV. | |
(d) | Payables for interest rate expense and general and administrative expenses paid on behalf of EnerVest Production Partners, and interest rate hedge liability incurred and unsettled at year end. |
F-28
Table of Contents
(e) | Payable for intercompany hedge liability incurred and unsettled at year end. | |
(f) | See Note 6 — Related Party Transactions. | |
(g) | Plugging and abandonment deposits collected from other working interest owners. | |
(h) | Period end accrued general and administrative liabilities. | |
(i) | Consists primarily of royalty and accounts payable trade payables. |
5. | Asset Retirement Obligations |
Amount | ||||
Asset retirement obligations, January 1, 2003 | $ | 79,907 | ||
Plus: Accretion expense | 67,341 | |||
Liabilities incurred | 2,184,808 | |||
Asset retirement obligations, December 31, 2003 | 2,332,056 | |||
Plus: Accretion expense | 160,433 | |||
Liabilities incurred | 13,206 | |||
Revisions in estimated cash flows | (455,796 | ) | ||
Asset retirement obligations, December 31, 2004 | 2,049,899 | |||
Plus: Accretion expense | 170,543 | |||
Liabilities incurred | 502,366 | |||
Revisions in estimated cash flows | 29,329 | |||
Asset retirement obligations, December 31, 2005 | $ | 2,752,137 | ||
F-29
Table of Contents
6. | Related Party Transactions |
7. | Income Taxes |
Years Ended December 31, | ||||||||||||
Income Tax Provision | 2003 | 2004 | 2005 | |||||||||
Current income tax provision | $ | 36,643 | $ | 671,596 | $ | 5,560,197 | ||||||
Deferred income tax provision | 280,591 | 1,850,225 | (211,244 | ) | ||||||||
Total income tax provision | $ | 317,234 | $ | 2,521,821 | $ | 5,348,953 | ||||||
F-30
Table of Contents
Year Ended December 31, | ||||||||||||
2003 | 2004 | 2005 | ||||||||||
Income before income tax provision | $ | 2,991,021 | $ | 11,572,822 | $ | 19,857,072 | ||||||
Less: Income not subject to taxes | (1,541,752 | ) | (2,366,111 | ) | (4,582,076 | ) | ||||||
Pretax income subject to taxes | 1,449,269 | 9,206,711 | 15,274,996 | |||||||||
Statutory rate | 34 | % | 34 | % | 34 | % | ||||||
Income tax expense at statutory rate | 492,751 | 3,130,282 | 5,193,499 | |||||||||
Reconciling items: | ||||||||||||
State income taxes net of federal benefit | — | — | 678,322 | |||||||||
Percentage depletion in excess of basis | (175,517 | ) | (609,329 | ) | (448,401 | ) | ||||||
Other permanent items | — | 868 | (74,467 | ) | ||||||||
Income tax provision | $ | 317,234 | $ | 2,521,821 | $ | 5,348,953 | ||||||
F-31
Table of Contents
December 31, | ||||||||
2004 | 2005 | |||||||
Deferred tax assets: | ||||||||
Depletion carryforward | $ | — | $ | — | ||||
Net operating loss carryforward | 176,800 | 154,700 | ||||||
Derivative instruments | — | 1,871,670 | ||||||
AMT credit | — | — | ||||||
Total assets | 176,800 | 2,026,370 | ||||||
Deferred tax liabilities: | ||||||||
Derivative instruments | (18,187 | ) | — | |||||
Oil & gas property and equipment | (4,570,890 | ) | (4,355,733 | ) | ||||
Total liabilities | (4,589,077 | ) | (4,355,733 | ) | ||||
Total deferred tax liability | (4,412,277 | ) | (2,329,363 | ) | ||||
Reflected in the accompanying balance sheet as: | ||||||||
Current deferred tax asset | 3,912 | 1,875,582 | ||||||
Non-current deferred tax liability | (4,416,189 | ) | (4,204,945 | ) | ||||
$ | (4,412,277 | ) | $ | (2,329,363 | ) | |||
8. | Risk Management |
F-32
Table of Contents
Hedged | Weighted | Weighted | Weighted | |||||||||||||||||||||
Predecessor | Volume (Bbl | Average | Average | Average | ||||||||||||||||||||
Entity | Period Covered | Hedged Product | Index | or MMBtu) | Fixed Price | Floor Price | Cap Price | |||||||||||||||||
CGAS | Costless Collars-Year 2006 | Crude Oil | WTI | 182,500 | $ | $ | 45.000 | $ | 61.000 | |||||||||||||||
CGAS | SWAP Contracts-Year 2006 | Crude Oil | WTI | 55,200 | 63.350 | |||||||||||||||||||
CGAS | Costless Collars-Year 2006 | Natural Gas | Dominion Appalachia | 360,000 | 7.700 | 8.910 | ||||||||||||||||||
CGAS | Costless Collars-Year 2006 | Natural Gas | Dominion Appalachia | 364,000 | 6.220 | 7.300 | ||||||||||||||||||
CGAS | SWAP Contracts-Year 2006 | Natural Gas | Dominion Appalachia | 552,000 | 8.515 | |||||||||||||||||||
CGAS | SWAP Contracts-Year 2006 | Natural Gas | Dominion Appalachia | 730,000 | 10.380 | |||||||||||||||||||
CGAS | SWAP Contracts-Year 2007 | Natural Gas | Dominion Appalachia | 365,000 | 10.625 | |||||||||||||||||||
EnerVest Production Partners | Costless Collars-Year 2006 | Natural Gas | NYMEX | 90,000 | 7.110 | 8.390 | ||||||||||||||||||
EnerVest Production Partners | Costless Collars-Year 2006 | Natural Gas | NYMEX | 214,000 | 5.940 | 7.050 |
F-33
Table of Contents
Quantity | ||||||||||||||||||||
Predecessor | Hedged | (Principal | Swap | |||||||||||||||||
Entity | Period Covered | Product | Index | Balance) | Rate | |||||||||||||||
EVPP* | SWAP Contracts - January 2006 | Interest Rate | LIBOR | 8,352,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - February 2006 | Interest Rate | LIBOR | 8,288,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - March 2006 | Interest Rate | LIBOR | 8,224,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - April 2006 | Interest Rate | LIBOR | 8,160,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - May 2006 | Interest Rate | LIBOR | 8,096,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - June 2006 | Interest Rate | LIBOR | 8,032,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - July 2006 | Interest Rate | LIBOR | 7,968,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - August 2006 | Interest Rate | LIBOR | 7,904,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - September 2006 | Interest Rate | LIBOR | 7,840,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - October 2006 | Interest Rate | LIBOR | 7,776,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - November 2006 | Interest Rate | LIBOR | 7,712,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - December 2006 | Interest Rate | LIBOR | 7,648,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - January 2007 | Interest Rate | LIBOR | 7,584,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - February 2007 | Interest Rate | LIBOR | 7,520,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - March 2007 | Interest Rate | LIBOR | 7,456,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - April 2007 | Interest Rate | LIBOR | 7,392,000 | 4.20% | |||||||||||||||
EVPP* | SWAP Contracts - May 2007 | Interest Rate | LIBOR | 7,328,000 | 4.20% |
9. | Debt |
F-34
Table of Contents
10. | Major Customers |
11. | Commitments and Contingencies |
12. | Supplementary Information on Oil and Gas Activities |
Years Ended December 31, | ||||||||||||
2003 | 2004 | 2005 | ||||||||||
Costs incurred in oil and gas producing activities: | ||||||||||||
Acquisition of proved properties | $ | 36,165,065 | $ | — | $ | 10,778,477 | ||||||
Acquisition of unproved properties | 6,025,261 | 282,482 | 444,920 | |||||||||
Development of oil & gas properties | 2,053,668 | 4,970,324 | 5,096,994 | |||||||||
Exploration costs | 1,337,713 | 1,720,942 | 3,068,994 | |||||||||
Asset retirement costs incurred and revised | 2,254,134 | (442,590 | ) | 531,695 | ||||||||
Total | $ | 47,835,841 | $ | 6,531,158 | $ | 19,921,080 | ||||||
F-35
Table of Contents
December 31, | ||||||||
2004 | 2005 | |||||||
Capitalized costs related to oil and gas producing activities: | ||||||||
Evaluated properties | ||||||||
Proved properties | $ | 46,906,322 | $ | 65,245,112 | ||||
Unproved properties | 5,257,032 | 1,497,845 | ||||||
Accumulated depreciation, depletion and amortization | (5,679,839 | ) | (9,706,270 | ) | ||||
Net capitalized costs | $ | 46,483,515 | $ | 57,036,687 | ||||
13. | Estimated Proved Oil and Gas Reserves (Unaudited) |
F-36
Table of Contents
Natural Gas | Oil | |||||||||||
(Mcf)(1) | (Bbls)(2) | Mcfe(3) | ||||||||||
Proved reserves: | ||||||||||||
Proved reserves, January 1, 2003 | 9,471,607 | 7,507 | 9,516,649 | |||||||||
Purchase of minerals in place | 31,436,704 | 1,392,449 | 39,791,398 | |||||||||
Revision of previous estimates | (2,007,465 | ) | 11,108 | (1,940,817 | ) | |||||||
Production | (1,818,643 | ) | (66,806 | ) | (2,219,479 | ) | ||||||
Extensions and discoveries | 1,225,092 | 2,702 | 1,241,302 | |||||||||
Proved reserves, December 31, 2003 | 38,307,295 | 1,346,960 | 46,389,053 | |||||||||
Purchase of minerals in place | — | — | — | |||||||||
Revision of previous estimates | (809,624 | ) | 223,359 | 530,531 | ||||||||
Production | (3,589,313 | ) | (152,529 | ) | (4,504,487 | ) | ||||||
Extensions and discoveries | 1,843,473 | 66,840 | 2,244,512 | |||||||||
Proved reserves, December 31, 2004 | 35,751,831 | 1,484,630 | 44,659,609 | |||||||||
Purchase of minerals in place | 9,815,775 | — | 9,815,775 | |||||||||
Revision of previous estimates | 2,307,946 | 155,946 | 3,243,621 | |||||||||
Production | (3,900,824 | ) | (174,425 | ) | (4,947,374 | ) | ||||||
Extensions and discoveries | 6,907,893 | 201,892 | 8,119,247 | |||||||||
Proved reserves, December 31, 2005 | 50,882,621 | 1,668,043 | 60,890,878 | |||||||||
Proved developed reserves: | ||||||||||||
December 31, 2003 | 37,196,480 | 1,338,292 | 45,226,232 | |||||||||
December 31, 2004 | 35,197,927 | 1,478,534 | 44,069,131 | |||||||||
December 31, 2005 | 45,820,825 | 1,552,561 | 55,136,191 | |||||||||
(1) | Thousand cubic feet. | |
(2) | Barrels. | |
(3) | Thousand cubic feet equivalent, barrels are converted to Mcfe based on one barrel of oil to six Mcf of natural gas equivalent. |
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Table of Contents
14. | Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) |
• | Future revenues were based on year-end oil and gas prices. Future price changes were included only to the extent provided by existing contractual agreements. | |
• | Production and development costs were computed using year-end costs assuming no change in present economic conditions. | |
• | Future net cash flows were discounted at an annual rate of 10%. | |
• | Future income taxes were computed only for the CGAS entity using the approximate statutory tax rate and giving effect to available net operating losses, tax credits and statutory depletion. No future income taxes were computed for EnerVest WV or EnerVest Production Partners in accordance with their standing as non-taxable entities. |
Years Ended December 31, | ||||||||||||
2003 | 2004 | 2005 | ||||||||||
(In thousands) | ||||||||||||
Estimated future cash inflows: | ||||||||||||
Revenues from sale of oil & gas | $ | 278,957 | $ | 298,572 | $ | 643,848 | ||||||
Production costs | (93,972 | ) | (105,108 | ) | (181,962 | ) | ||||||
Development costs | (1,547 | ) | (719 | ) | (15,593 | ) | ||||||
Future net cash flows before income taxes | 183,438 | 192,745 | 446,293 | |||||||||
Future income taxes | (30,820 | ) | (32,531 | ) | (76,033 | ) | ||||||
Future net cash flows | 152,618 | 160,214 | 370,260 | |||||||||
10% annual timing discount | (78,385 | ) | (79,442 | ) | (187,851 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 74,233 | $ | 80,772 | $ | 182,409 | ||||||
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Table of Contents
Years Ended December 31, | ||||||||||||
2003 | 2004 | 2005 | ||||||||||
(In thousands) | ||||||||||||
Beginning of year | $ | 8,324 | $ | 74,233 | $ | 80,772 | ||||||
Sale of oil and gas, net of production costs | (6,624 | ) | (19,642 | ) | (31,259 | ) | ||||||
Purchase of minerals in place | 65,094 | — | 15,804 | |||||||||
Extensions and discoveries | 5,984 | 10,971 | 36,668 | |||||||||
Development costs incurred | 2,054 | 4,970 | 5,097 | |||||||||
Changes in estimated future development costs | (2,138 | ) | (4,142 | ) | (19,972 | ) | ||||||
Net changes in prices and production costs | 14,591 | 8,188 | 77,351 | |||||||||
Revisions and other | (17,244 | ) | 269 | 33,207 | ||||||||
Changes in income taxes | — | (1,499 | ) | (24,515 | ) | |||||||
Accretion of 10% timing discount | 4,192 | 7,424 | 9,256 | |||||||||
End of period | $ | 74,233 | $ | 80,772 | $ | 182,409 | ||||||
15. | Subsequent Events |
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Table of Contents
16. | Restatement |
2003 | 2004 | 2005 | ||||||||||||||||||||||
As | As | As | ||||||||||||||||||||||
Previously | As | Previously | As | Previously | As | |||||||||||||||||||
Reported | Restated | Reported | Restated | Reported | Restated | |||||||||||||||||||
At December 31, 2005 | ||||||||||||||||||||||||
Combined balance sheet: | ||||||||||||||||||||||||
Accounts receivable — gas and oil sales | 9,001,913 | 8,797,620 | ||||||||||||||||||||||
Due to affiliates | 6,591,247 | 6,386,954 | ||||||||||||||||||||||
For the years ended December 31, 2003, 2004 and 2005: | ||||||||||||||||||||||||
Combined statements of operations and comprehensive income: | ||||||||||||||||||||||||
Transportation and marketing-related revenues | 3,658,065 | 3,443,082 | 3,636,920 | 3,437,618 | 8,392,164 | 6,224,787 | ||||||||||||||||||
Total Revenues | 13,785,526 | 13,570,543 | 30,082,622 | 29,883,320 | 46,345,751 | 44,178,374 | ||||||||||||||||||
Lease operating expenses | 3,681,278 | 3,466,295 | 6,813,953 | 6,614,651 | 7,710,628 | 7,235,775 | ||||||||||||||||||
Purchased gas cost | 7,352,157 | 5,659,633 | ||||||||||||||||||||||
Total Operating Costs and Expenses | 11,058,981 | 10,843,998 | 18,522,145 | 18,322,843 | 26,060,831 | 23,893,454 | ||||||||||||||||||
Other comprehensive loss | (4,382,662 | ) | (4,167,973 | ) | ||||||||||||||||||||
Comprehensive income | 10,690,769 | 10,905,458 | ||||||||||||||||||||||
Combined statement of cash flows: | ||||||||||||||||||||||||
Increase in accounts receivable | (748,855 | ) | (544,562 | ) | ||||||||||||||||||||
Increase in accounts payable and accrued liabilities | 961,475 | 2,706,279 | ||||||||||||||||||||||
Increase in due to affiliates | 5,010,672 | 3,061,575 | ||||||||||||||||||||||
Combined statement of changes in owners’ equity: | ||||||||||||||||||||||||
Contributions | 200,000 | 197,837 | ||||||||||||||||||||||
Distributions | (2,070,893 | ) | (2,068,730 | ) |
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Table of Contents
March 31, | ||||||||
2006 | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 2,609,633 | ||||||
Accounts receivable-gas and oil sales | 6,678,924 | |||||||
Accounts receivable-other | 281,229 | |||||||
Interest and commodity hedge asset-related party | 682,174 | |||||||
Commodity hedge asset-third party | 542,703 | |||||||
Deferred tax asset | 443,155 | |||||||
Other current assets | 519,726 | |||||||
Total current assets | 11,757,544 | |||||||
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization | 57,561,379 | |||||||
Other property, net of accumulated depreciation and amortization | 514,028 | |||||||
Long-term commodity hedge asset-related party | 1,439,638 | |||||||
Long-term commodity hedge asset-third party | 551,470 | |||||||
Other assets | 1,508,837 | |||||||
Total assets | $ | 73,332,896 | ||||||
LIABILITIES AND OWNERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued liabilities | $ | 2,662,120 | ||||||
Due to affiliates | 4,361,694 | |||||||
Commodity hedge liability-related party | 1,486,289 | |||||||
Commodity hedge liability-third party | 172,200 | |||||||
Current income tax liability | 2,623,587 | |||||||
Deferred income tax liability | 201,603 | |||||||
Other current liabilities | 38,934 | |||||||
Total current liabilities | 11,546,427 | |||||||
Asset retirement obligations | 2,805,650 | |||||||
Long-term debt | 10,350,000 | |||||||
Deferred income tax liability | 4,722,612 | |||||||
Total liabilities | 29,424,689 | |||||||
Commitments and contingencies (See Note 8) | ||||||||
Owners’ equity, excluding accumulated other comprehensive income | 42,538,527 | |||||||
Accumulated other comprehensive income | 1,369,680 | |||||||
Total owners’ equity | 43,908,207 | |||||||
Total liabilities and owners’ equity | $ | 73,332,896 | ||||||
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Table of Contents
(As Defined in Note 1)
Unaudited Condensed Combined Statements of Operations and Comprehensive Income
Three Months Ended | ||||||||
March 31, | ||||||||
2005 | 2006 | |||||||
Revenues: | ||||||||
Natural gas and oil revenues | $ | 8,361,596 | $ | 11,668,865 | ||||
Realized gain (loss) on natural gas swaps | 444,059 | (189,786 | ) | |||||
Transportation and marketing-related revenues | 1,003,205 | 1,679,620 | ||||||
Total revenues | 9,808,860 | 13,158,699 | ||||||
Operating costs and expenses: | ||||||||
Lease operating expenses | 1,459,683 | 1,798,788 | ||||||
Purchased gas cost | 848,022 | 1,557,497 | ||||||
Production taxes | 25,735 | 52,368 | ||||||
Asset retirement obligations accretion expense | 42,611 | 44,008 | ||||||
Exploration expenses | 877,982 | 58,458 | ||||||
Dry hole costs | — | 149,475 | ||||||
Depreciation, depletion and amortization | 1,020,694 | 1,104,760 | ||||||
General and administrative expenses | 341,100 | 640,081 | ||||||
Management fees | 27,965 | 34,899 | ||||||
Total operating costs and expenses | 4,643,792 | 5,440,334 | ||||||
Operating income | 5,165,068 | 7,718,365 | ||||||
Other expense, net: | ||||||||
Interest and financing expense-third party | (36,927 | ) | (183,939 | ) | ||||
Interest and financing expense-related party | (509 | ) | — | |||||
Other income (expense), net | (173,500 | ) | 142,524 | |||||
Total other expense, net | (210,936 | ) | (41,415 | ) | ||||
Income before income tax provision | 4,954,132 | 7,676,950 | ||||||
Income tax provision | 1,421,406 | 1,545,225 | ||||||
Equity earnings in investments | 388,815 | 90,225 | ||||||
Net income | 3,921,541 | 6,221,950 | ||||||
Other comprehensive income (loss) | (3,166,826 | ) | 5,637,867 | |||||
Comprehensive income | $ | 754,715 | $ | 11,859,817 | ||||
F-42
Table of Contents
(As Defined in Note 1)
Unaudited Condensed Combined Statements of Cash Flows
Three Months Ended | ||||||||
March 31, | ||||||||
2005 | 2006 | |||||||
Cash flows from operating activities: | ||||||||
Net income | $ | 3,921,541 | $ | 6,221,950 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Asset retirement obligations accretion expense | 42,611 | 44,008 | ||||||
Depreciation, depletion, and amortization | 1,020,694 | 1,104,760 | ||||||
Dry hole cost | — | 149,475 | ||||||
Equity earnings in investments, net of distribution | (379,450 | ) | (59,510 | ) | ||||
Deferred income tax expense | 1,421,406 | 92,211 | ||||||
Decrease in accounts receivable | 1,283,471 | 2,367,474 | ||||||
Decrease in due from affiliates | — | 95,701 | ||||||
Increase in income tax receivable | (357 | ) | — | |||||
Decrease in other current assets | 19,831 | 97,279 | ||||||
Decrease in other assets | — | 3,200 | ||||||
Decrease in accounts payable and accrued liabilities | (85,940 | ) | (3,533,323 | ) | ||||
Decrease in due to affiliates | (549,885 | ) | (2,098,962 | ) | ||||
Increase in current tax liability | — | 1,453,014 | ||||||
Decrease in other current liabilities | (383,661 | ) | (31,000 | ) | ||||
Net cash provided by operating activities | 6,310,261 | 5,906,277 | ||||||
Cash flows from investing activities: | ||||||||
Development of oil and gas properties | (1,638,419 | ) | (1,418,855 | ) | ||||
Acquisition of oil and gas properties | (10,719,976 | ) | — | |||||
Property sales proceeds | 5,500 | — | ||||||
Investment in equity investee | (121,582 | ) | (25,330 | ) | ||||
Net cash used in investing activities | (12,474,477 | ) | (1,444,185 | ) | ||||
Cash flows from financing activities: | ||||||||
Repayment of advance-related party | (1,135,718 | ) | — | |||||
Debt borrowings | 8,650,000 | — | ||||||
Contributions by partners | 2,028,500 | — | ||||||
Distribution to partners and dividends paid | (4,212,517 | ) | (9,011,298 | ) | ||||
Net cash provided by (used in) financing activities | 5,330,265 | (9,011,298 | ) | |||||
Net decrease in cash and cash equivalents | (833,951 | ) | (4,549,206 | ) | ||||
Cash and cash equivalents at beginning of period | 1,671,871 | 7,158,839 | ||||||
Cash and cash equivalents at end of period | $ | 837,920 | $ | 2,609,633 | ||||
Supplemental schedule of cash flow information: | ||||||||
Cash paid for interest | $ | 36,870 | $ | 187,866 | ||||
Cash paid for income taxes | $ | — | $ | 235,000 | ||||
Non-cash debt reduction | $ | — | $ | 150,000 |
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Table of Contents
(As Defined in Note 1)
Unaudited Condensed Combined Statements of Changes in Owners’ Equity
For the Three Months Ended March 31, 2006
Owners’ | ||||||||||||
Equity | ||||||||||||
Excluding | Accumulated | |||||||||||
Other | Other | Total | ||||||||||
Comprehensive | Comprehensive | Owners’ | ||||||||||
Loss | Loss | Equity | ||||||||||
Balance January 1, 2006 | $ | 45,177,875 | $ | (4,268,187 | ) | $ | 40,909,688 | |||||
Contributions | 150,000 | — | 150,000 | |||||||||
Distributions | (2,505,151 | ) | — | (2,505,151 | ) | |||||||
Dividends | (6,506,147 | ) | — | (6,506,147 | ) | |||||||
Unrealized gain on derivatives | — | 5,533,591 | 5,533,591 | |||||||||
Reclassification adjustment into earnings | — | 104,276 | 104,276 | |||||||||
Net income | 6,221,950 | — | 6,221,950 | |||||||||
Balance March 31, 2006 | $ | 42,538,527 | $ | 1,369,680 | $ | 43,908,207 | ||||||
F-44
Table of Contents
1. | Organization |
• | EnerVest Production Partners, Ltd., is a Texas limited partnership (“EnerVest Production Partners”) formed in 2000. EnerVest Production Partners owns oil and gas producing properties in the Monroe field in Northern Louisiana. Prior to April 2006, EnerVest owned, directly or indirectly, all of the general and limited partnership interests in EnerVest Production Partners. |
• | EnerVest WV, L.P. is a Delaware limited partnership (“EnerVest WV”) formed in 2003. EnerVest WV owns oil and gas producing properties primarily in West Virginia. Prior to April 2006, EnerVest owned a 1% interest in EnerVest WV as general partner and an unaffiliated institutional investor owned a 99% interest as limited partner. |
• | CGAS Exploration, Inc., is an Ohio corporation (“CGAS”) owned by a partnership formed by EnerVest. CGAS was acquired by this partnership in August 2003. EnerVest has a 25.75% interest as general partner in the partnership that owns CGAS, and unaffiliated institutional investors own an aggregate 74.25% interest as limited partners. |
F-45
Table of Contents
2. | Oil and Gas Acquisition |
3. | Oil and Gas Properties |
F-46
Table of Contents
4. | Asset Retirement Obligations |
Asset retirement obligations, December 31, 2005 | $ | 2,752,137 | ||
Plus: Accretion expense | 44,008 | |||
Liabilities incurred | 9,505 | |||
Asset retirement obligations, March 31, 2006 | $ | 2,805,650 | ||
5. | Related Party Transactions |
March 31, | ||||
2006 | ||||
Total assets | $ | 6,835,222 | ||
Total liabilities | 3,333,605 | |||
Net income | 111,669 |
F-47
Table of Contents
6. | Risk Management |
Weighted | Weighted | Weighted | ||||||||||||||||||||
Hedged | Average | Average | Average | |||||||||||||||||||
Predecessor | Hedged | Volume (Bbl | Fixed | Floor | Ceiling | |||||||||||||||||
Entity | Period Covered | Product | Index | or MMBtu) | Price | Price | Price | |||||||||||||||
CGAS | Costless Collars- Year 2006 | Crude Oil | WTI | 137,500 | $ | $ | 45.000 | $ | 61.000 | |||||||||||||
CGAS | SWAP Contracts- Year 2006 | Crude Oil | WTI | 55,200 | 63.350 | |||||||||||||||||
CGAS | Costless Collars- Year 2006 | Natural Gas | Dominion Appalachia | 364,000 | 6.220 | 7.300 | ||||||||||||||||
CGAS | SWAP Contracts- Year 2006 | Natural Gas | Dominion Appalachia | 552,000 | 8.515 | |||||||||||||||||
CGAS | SWAP Contracts- Year 2006 | Natural Gas | Dominion Appalachia | 61,000 | 9.670 | |||||||||||||||||
CGAS | SWAP Contracts- Year 2006 | Natural Gas | Dominion Appalachia | 184,000 | 10.240 | |||||||||||||||||
CGAS | SWAP Contracts- Year 2006 | Natural Gas | Dominion Appalachia | 550,000 | $ | 10.380 | ||||||||||||||||
CGAS | SWAP Contracts- Year 2007 | Natural Gas | Dominion Appalachia | 365,000 | 10.625 | |||||||||||||||||
CGAS | SWAP Contracts- Year 2007 | Natural Gas | Dominion Appalachia | 1,679,000 | 10.265 | |||||||||||||||||
CGAS | SWAP Contracts- Year 2008 | Natural Gas | Dominion Appalachia | 1,720,200 | 9.750 | |||||||||||||||||
EVWV* | SWAP Contracts- Year 2006 | Natural Gas | Dominion Appalachia | 184,000 | 10.240 |
F-48
Table of Contents
Weighted | Weighted | Weighted | ||||||||||||||||||||
Hedged | Average | Average | Average | |||||||||||||||||||
Predecessor | Hedged | Volume (Bbl | Fixed | Floor | Ceiling | |||||||||||||||||
Entity | Period Covered | Product | Index | or MMBtu) | Price | Price | Price | |||||||||||||||
EVWV* | SWAP Contracts- Year 2007 | Natural Gas | Dominion Appalachia | 328,500 | 10.265 | |||||||||||||||||
EVWV* | SWAP Contracts- Year 2008 | Natural Gas | Dominion Appalachia | 292,800 | 9.750 | |||||||||||||||||
EVPP** | Costless Collars- Year 2006 | Natural Gas | NYMEX | 214,000 | $ | 5.940 | $ | 7.050 | ||||||||||||||
EVPP** | SWAP Contracts- Year 2006 | Natural Gas | NYMEX | 160,500 | 9.250 | |||||||||||||||||
EVPP** | SWAP Contracts- Year 2006 | Natural Gas | NYMEX | 106,750 | 10.430 | |||||||||||||||||
EVPP** | SWAP Contracts- Year 2007 | Natural Gas | NYMEX | 547,500 | 9.820 | |||||||||||||||||
EVPP** | SWAP Contracts- Year 2008 | Natural Gas | NYMEX | 549,000 | 9.360 |
Quantity | ||||||||||||||
Predecessor | Hedged | (Principal | Swap | |||||||||||
Entity | Period Covered | Product | Index | Balance) | Rate | |||||||||
EVPP* | SWAP Contracts - March 2006 | Interest Rate | LIBOR | 8,224,000 | 4.20% | |||||||||
EVPP* | SWAP Contracts - April 2006 | Interest Rate | LIBOR | 8,160,000 | 4.20% | |||||||||
EVPP* | SWAP Contracts - May 2006 | Interest Rate | LIBOR | 8,096,000 | 4.20% | |||||||||
EVPP* | SWAP Contracts - June 2006 | Interest Rate | LIBOR | 8,032,000 | 4.20% | |||||||||
EVPP* | SWAP Contracts - July 2006 | Interest Rate | LIBOR | 7,968,000 | 4.20% |
F-49
Table of Contents
Quantity | ||||||||||||||
Predecessor | Hedged | (Principal | Swap | |||||||||||
Entity | Period Covered | Product | Index | Balance) | Rate | |||||||||
EVPP* | SWAP Contracts - August 2006 | Interest Rate | LIBOR | 7,904,000 | 4.20% | |||||||||
EVPP* | SWAP Contracts - September 2006 | Interest Rate | LIBOR | 7,840,000 | 4.20% | |||||||||
EVPP* | SWAP Contracts - October 2006 | Interest Rate | LIBOR | 7,776,000 | 4.20% | |||||||||
EVPP* | SWAP Contracts - November 2006 | Interest Rate | LIBOR | 7,712,000 | 4.20% | |||||||||
EVPP* | SWAP Contracts - December 2006 | Interest Rate | LIBOR | 7,648,000 | 4.20% | |||||||||
EVPP* | SWAP Contracts - January 2007 | Interest Rate | LIBOR | 7,584,000 | 4.20% | |||||||||
EVPP* | SWAP Contracts - February 2007 | Interest Rate | LIBOR | 7,520,000 | 4.20% | |||||||||
EVPP* | SWAP Contracts - March 2007 | Interest Rate | LIBOR | 7,456,000 | 4.20% | |||||||||
EVPP* | SWAP Contracts - April 2007 | Interest Rate | LIBOR | 7,392,000 | 4.20% | |||||||||
EVPP* | SWAP Contracts - May 2007 | Interest Rate | LIBOR | 7,328,000 | 4.20% |
7. | Debt |
8. | Commitments and Contingencies |
9. | New Accounting Pronouncements |
F-50
Table of Contents
10. | Subsequent Event |
F-51
Table of Contents
F-52
Table of Contents
Assets | ||||
Cash | $ | 1,000 | ||
Total assets | $ | 1,000 | ||
Partners’ Equity | ||||
Partners’ capital: | ||||
Limited partner | $ | 990 | ||
General partner | 10 | |||
Total partners’ capital | $ | 1,000 | ||
F-53
Table of Contents
(1) | Organization |
F-54
Table of Contents
F-55
Table of Contents
Assets | ||||
Cash | $ | 990 | ||
Investment in EV Energy Partners, L.P. | 10 | |||
Total Assets | $ | 1,000 | ||
Partners’ Equity | ||||
Partners’ capital: | ||||
Limited Partner | $ | 990 | ||
General Partner | 10 | |||
Total partners’ capital | $ | 1,000 | ||
F-56
Table of Contents
(1) | Organization |
F-57
Table of Contents
Agreement of Limited Partnership
EV Energy Partners, L.P.
, 2006
Table of Contents
Page | ||||||
ARTICLE I. Definitions | A-1 | |||||
Section 1.1 | Definitions | A-1 | ||||
Section 1.2 | Construction | A-16 | ||||
ARTICLE II. Organization | A-16 | |||||
Section 2.1 | Formation | A-16 | ||||
Section 2.2 | Name | A-17 | ||||
Section 2.3 | Registered Office; Registered Agent; Principal Office; Other Offices | A-17 | ||||
Section 2.4 | Purpose and Business | A-17 | ||||
Section 2.5 | Powers | A-17 | ||||
Section 2.6 | Power of Attorney | A-17 | ||||
Section 2.7 | Term | A-18 | ||||
Section 2.8 | Title to Partnership Assets | A-18 | ||||
ARTICLE III. Rights of Limited Partners | A-19 | |||||
Section 3.1 | Limitation of Liability | A-19 | ||||
Section 3.2 | Management of Business | A-19 | ||||
Section 3.3 | Outside Activities of the Limited Partners | A-19 | ||||
Section 3.4 | Rights of Limited Partners | A-19 | ||||
ARTICLE IV. Certificates; Record Holders; Transfer of Partnership Interests; Redemption of Partnership Interests | A-20 | |||||
Section 4.1 | Certificates | A-20 | ||||
Section 4.2 | Mutilated, Destroyed, Lost or Stolen Certificates | A-20 | ||||
Section 4.3 | Record Holders | A-21 | ||||
Section 4.4 | Transfer Generally | A-21 | ||||
Section 4.5 | Registration and Transfer of Limited Partner Interests | A-22 | ||||
Section 4.6 | Transfer of the General Partner’s General Partner Interest | A-22 | ||||
Section 4.7 | Transfer of Incentive Distribution Rights | A-23 | ||||
Section 4.8 | Restrictions on Transfers | A-23 | ||||
Section 4.9 | Citizenship Certificates; Non-citizen Assignees | A-24 | ||||
Section 4.10 | Redemption of Partnership Interests of Non-citizen Assignees | A-25 | ||||
ARTICLE V. Capital Contributions and Issuance of Partnership Interests | A-25 | |||||
Section 5.1 | Organizational Contributions | A-25 | ||||
Section 5.2 | Contributions by the General Partner and its Affiliates and [EnCap] | A-26 | ||||
Section 5.3 | Contributions by Initial Limited Partners | A-26 | ||||
Section 5.4 | Interest and Withdrawal | A-27 | ||||
Section 5.5 | Capital Accounts | A-27 | ||||
Section 5.6 | Issuances of Additional Partnership Securities | A-29 | ||||
Section 5.7 | Conversion of Subordinated Units | A-30 | ||||
Section 5.8 | Limited Preemptive Right | A-31 |
A-i
Table of Contents
Page | ||||||
Section 5.9 | Splits and Combinations | A-32 | ||||
Section 5.10 | Fully Paid and Non-Assessable Nature of Limited Partner Interests | A-32 | ||||
Section 5.11 | Issuance of Class B Units in Connection with Reset of Incentive Distribution Rights | A-32 | ||||
ARTICLE VI. Allocations and Distributions | A-34 | |||||
Section 6.1 | Allocations for Capital Account Purposes | A-34 | ||||
Section 6.2 | Allocations for Tax Purposes | A-40 | ||||
Section 6.3 | Requirement and Characterization of Distributions; Distributions to Record Holders | A-42 | ||||
Section 6.4 | Distributions of Available Cash from Operating Surplus | A-42 | ||||
Section 6.5 | Distributions of Available Cash from Capital Surplus | A-44 | ||||
Section 6.6 | Adjustment of Minimum Quarterly Distribution and Target Distribution Levels | A-44 | ||||
Section 6.7 | Special Provisions Relating to the Holders of Subordinated Units and Class B Units | A-44 | ||||
Section 6.8 | Special Provisions Relating to the Holders of Incentive Distribution Rights | A-45 | ||||
Section 6.9 | Entity-Level Taxation | A-45 | ||||
ARTICLE VII. Management and Operation of Business | A-46 | |||||
Section 7.1 | Management | A-46 | ||||
Section 7.2 | Certificate of Limited Partnership | A-47 | ||||
Section 7.3 | Restrictions on the General Partner’s Authority | A-48 | ||||
Section 7.4 | Reimbursement of the General Partner | A-48 | ||||
Section 7.5 | Outside Activities | A-49 | ||||
Section 7.6 | Loans from the General Partner; Loans or Contributions from the Partnership or Group Members | A-50 | ||||
Section 7.7 | Indemnification | A-50 | ||||
Section 7.8 | Liability of Indemnitees | A-51 | ||||
Section 7.9 | Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties | A-52 | ||||
Section 7.10 | Other Matters Concerning the General Partner | A-53 | ||||
Section 7.11 | Purchase or Sale of Partnership Securities | A-53 | ||||
Section 7.12 | Registration Rights of the General Partner and its Affiliates | A-54 | ||||
Section 7.13 | Reliance by Third Parties | A-56 | ||||
ARTICLE VIII. Books, Records, Accounting and Reports | A-57 | |||||
Section 8.1 | Records and Accounting | A-57 | ||||
Section 8.2 | Fiscal Year | A-57 | ||||
Section 8.3 | Reports | A-57 | ||||
ARTICLE IX. Tax Matters | A-57 | |||||
Section 9.1 | Tax Returns and Information | A-57 | ||||
Section 9.2 | Tax Elections | A-57 | ||||
Section 9.3 | Tax Controversies | A-58 | ||||
Section 9.4 | Withholding | A-58 |
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ARTICLE X. Admission of Partners | A-58 | |||||
Section 10.1 | Admission of Limited Partners | A-58 | ||||
Section 10.2 | Admission of Successor General Partner | A-59 | ||||
Section 10.3 | Amendment of Agreement and Certificate of Limited Partnership | A-59 | ||||
ARTICLE XI. Withdrawal or Removal of Partners | A-59 | |||||
Section 11.1 | Withdrawal of the General Partner | A-59 | ||||
Section 11.2 | Removal of the General Partner | A-60 | ||||
Section 11.3 | Interest of Departing General Partner and Successor General Partner | A-61 | ||||
Section 11.4 | Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages | A-62 | ||||
Section 11.5 | Withdrawal of Limited Partners | A-62 | ||||
ARTICLE XII. Dissolution and Liquidation | A-62 | |||||
Section 12.1 | Dissolution | A-62 | ||||
Section 12.2 | Continuation of the Business of the Partnership After Dissolution | A-62 | ||||
Section 12.3 | Liquidator | A-63 | ||||
Section 12.4 | Liquidation | A-63 | ||||
Section 12.5 | Cancellation of Certificate of Limited Partnership | A-64 | ||||
Section 12.6 | Return of Contributions | �� | A-64 | |||
Section 12.7 | Waiver of Partition | A-64 | ||||
Section 12.8 | Capital Account Restoration | A-64 | ||||
ARTICLE XIII. Amendment of Partnership Agreement; Meetings; Record Date | A-64 | |||||
Section 13.1 | Amendments to be Adopted Solely by the General Partner | A-64 | ||||
Section 13.2 | Amendment Procedures | A-65 | ||||
Section 13.3 | Amendment Requirements | A-66 | ||||
Section 13.4 | Special Meetings | A-66 | ||||
Section 13.5 | Notice of a Meeting | A-67 | ||||
Section 13.6 | Record Date | A-67 | ||||
Section 13.7 | Adjournment | A-67 | ||||
Section 13.8 | Waiver of Notice; Approval of Meeting; Approval of Minutes | A-67 | ||||
Section 13.9 | Quorum and Voting | A-67 | ||||
Section 13.10 | Conduct of a Meeting | A-68 | ||||
Section 13.11 | Action Without a Meeting | A-68 | ||||
Section 13.12 | Right to Vote and Related Matters | A-68 | ||||
ARTICLE XIV. Merger, Consolidation or Conversion | A-69 | |||||
Section 14.1 | Authority | A-69 | ||||
Section 14.2 | Procedure for Merger, Consolidation or Conversion | A-69 | ||||
Section 14.3 | Approval by Limited Partners | A-70 | ||||
Section 14.4 | Certificate of Merger | A-71 | ||||
Section 14.5 | Effect of Merger, Consolidation or Conversion | A-71 |
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ARTICLE XV. Right to Acquire Limited Partner Interests | A-72 | |||||
Section 15.1 | Right to Acquire Limited Partner Interests | A-72 | ||||
ARTICLE XVI. General Provisions | A-73 | |||||
Section 16.1 | Addresses and Notices | A-73 | ||||
Section 16.2 | Further Action | A-74 | ||||
Section 16.3 | Binding Effect | A-74 | ||||
Section 16.4 | Integration | A-74 | ||||
Section 16.5 | Creditors | A-74 | ||||
Section 16.6 | Waiver | A-74 | ||||
Section 16.7 | Third-Party Beneficiaries | A-74 | ||||
Section 16.8 | Counterparts | A-74 | ||||
Section 16.9 | Applicable Law | A-74 | ||||
Section 16.10 | Invalidity of Provisions | A-74 | ||||
Section 16.11 | Consent of Partners | A-74 | ||||
Section 16.12 | Facsimile Signatures | A-74 |
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Agreement of Limited Partnership
of
EV Energy Partners, L.P.
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Certificates; Record Holders;
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By: | EV MANAGEMENT, L.L.C. its General Partner |
By: |
LTD.
By: | EnerVest Management GP, L.C., its General Partner |
By: |
By: | EV MANAGEMENT, L.L.C. its general partner |
By: |
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Representing Limited Partner Interests
in
EV Energy Partners, L.P.
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Dated: _ _ | EV Energy Partners, L.P. | |
Countersigned and Registered by: | ||
By: _ _ | ||
By: _ _ | ||
as Transfer Agent and Registrar |
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TEN COM — as tenants in common | UNIF GIFT/TRANSFERS MIN ACT | |
Custodian | ||
TEN ENT — as tenants by the entireties | (Cust) (Minor) under Uniform Gifts/Transfers to CD | |
JT TEN — as joint tenants with right of survivorship | Minors Act (state) | |
and not as tenants in common |
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EV Energy Partners, L.P.
(Please print or typewrite name and address of Assignee) | (Please insert Social Security or other identifying number of Assignee) |
Date: _ _ | NOTE: This signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change. | |
SIGNATURES MUST BE GUARANTEED BY A MEMBER OF THE FIRM OF THE NATIONAL ASSOCIATION OF SECURITIES DEALER, INC. OR BY A COMMERCIAL BANK OR TRUST COMPANY SIGNATURE(S) GUARANTEED | (Signature) | |
(Signature) |
Exhibit A-1
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• | Bbl — One stock tank barrel, or 42 US gallons liquid volume, of crude oil or other liquid hydrocarbons. | |
• | Bcf — One billion cubic feet of natural gas. | |
• | Bcfe — One billion cubic feet of natural gas equivalent. | |
• | BOE — One barrel of oil equivalent, converting gas to oil at the ratio of 6 Mcf of gas to 1 Bbl of oil. | |
• | MBbl — One thousand Bbls. | |
• | Mcf — One thousand cubic feet of natural gas. | |
• | Mcfe — One thousand cubic feet of natural gas equivalent. | |
• | MMBbl — One million Bbls of oil or other liquid hydrocarbons. | |
• | MMcf — One million cubic feet of natural gas. | |
• | MBOE — One thousand BOE. | |
• | MMBOE — One million BOE. |
• | Gross oil and gas wells or acres — Our gross wells or gross acres represent the total number of wells or acres in which we own a working interest. | |
• | Net oil and gas wells or acres — Determined by multiplying “gross” oil and natural gas wells or acres by the working interest that we own in such wells or acres represented by the underlying properties. |
• | Standardized measure of proved reserves — A measure of the present value of estimated future net cash flows to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized Measure does not give effect to derivative transactions. Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure. |
• | Proved reserves — The estimated quantities of crude oil, natural gas and natural gas liquids which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing economic and operating conditions. |
• | Proved oil and gas reserves — Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include |
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consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. |
• | Proved developed reserves — Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. | |
• | Proved undeveloped reserves — Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. |
• | Finding costs — Our finding costs compare the amount we spent to acquire, explore and develop our oil and gas properties, explore for oil and gas and to drill and complete wells during a period, with the increases in reserves during the period. This amount is calculated by dividing the net change in our evaluated oil and property costs during a period by the change in proved reserves plus production over the same period. Our finding costs as of December 31 of any year represent the average finding costs over the three-year period ending December 31 of that year. |
• | Reserve to production index — A measure of the productive life of an oil and gas property or a group of oil and gas properties, expressed in years. Reserve production index for the year ended December 31, 2005 equals our pro forma estimated net equivalent reserves attributable to a property or group of properties as of December 31, 2005 divided by our pro forma 2005 production. Reserve to production index is sometimes referred to as reserve life. |
• | Royalty interest — A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the interest provides, a specific portion of oil and natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and natural gas. A royalty interest owner has no right to consent to or approve the operation and development of the property, while the owners of the working interests have the exclusive right to exploit the mineral on the land. | |
• | Working interest — A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring |
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the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and drilling and other major activities in connection with the development and operation of a property. |
• | Seismic data — Oil and gas companies use seismic data as their principal source of information to locate oil and gas deposits, both to aid in exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones which digitize and record the reflected waves. Computers are then used to process the raw data to develop an image of underground formations. |
• | Adjusted operating surplus — For any period, operating surplus generated during that period is adjusted to: |
• | Available cash — For any quarter ending prior to liquidation: |
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• | Capital account — The capital account maintained for a partner under the partnership agreement. The capital account of a partner for a general partner interest, a common unit, a subordinated unit, a Class B unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that general partner interest, common unit, subordinated unit, Class B unit, incentive distribution right or other partnership interest were the only interest in EV Energy Partners, L.P. held by that partner since the date which that general partner interest, common unit, subordinated unit, Class B unit, incentive distribution right or other partnership interest was first issued. |
• | Capital surplus — All available cash distributed by us from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of the initial public offering equals the operating surplus as of the end of the quarter before that distribution. Any excess available cash will be deemed to be capital surplus. | |
• | Closing price — The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way, in either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in theover-the-counter market, as reported by the Nasdaq National Stock Market or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by our board of directors. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by our board of directors. | |
• | Common unit arrearage — The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period. | |
• | Current market price — For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date. | |
• | Interim capital transactions — The following transactions if they occur prior to liquidation: |
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• | Operating expenditures — All of our cash expenditures and cash expenditures of our subsidiaries, including, without limitation, taxes, reimbursements of our general partner, interest payments, repayment of working capital borrowings, and non-pro rata repurchases of units, subject to the following: |
• | Operating surplus — For any period prior to liquidation, on a cumulative basis and without duplication: |
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• | Subordination period — The subordination period will extend from the closing of the initial public offering until the first to occur of: |
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AUSTIN OFFICE: | MAIN OFFICE: | HOUSTON OFFICE: | ||
9601 AMBERGLEN BLVD., SUITE 117 | 306 WEST 7TH STREET, SUITE 302 | 1000 LOUISIANA, SUITE 625 | ||
AUSTIN, TEXAS 78729 | FORT WORTH , TEXAS 76102-4987 | HOUSTON, TEXAS 77002-5008 | ||
(512)249-7000 | (817) 336-2461 | (713) 651-9944 | ||
FAX(512) 233-2618 | FAX (817) 877-3728 | FAX (713) 651-9980 |
Re: | Evaluation Summary — SEC |
Proved | Proved | |||||||||||||||||
Developed | Developed | Proved | Total | |||||||||||||||
Producing | Non-Producing | Undeveloped | Proved | |||||||||||||||
Net Reserves | ||||||||||||||||||
Oil | - Mbbl | 955.2 | 0.5 | 115.8 | 1,071.5 | |||||||||||||
Gas | - MMcf | 39,486.6 | 258.4 | 5,063.0 | 44,807.9 | |||||||||||||
NGL | - Mbbl | 0.0 | 0.0 | 0.0 | 0.0 | |||||||||||||
Revenue | ||||||||||||||||||
Oil | - M$ | 55,354.8 | 29.2 | 6,706.6 | 62,090.6 | |||||||||||||
Gas | - M$ | 415,458.9 | 2,843.5 | 58,410.3 | 476,712.6 | |||||||||||||
NGL | - M$ | 0.0 | 0.0 | 0.0 | 0.0 | |||||||||||||
Hedge | - M$ | 0.0 | 0.0 | 0.0 | 0.0 | |||||||||||||
Other Revenue | - M$ | 0.0 | 0.0 | 0.0 | 0.0 | |||||||||||||
Severance Taxes | - M$ | 5,134.8 | 5.6 | 382.1 | 5,522.4 | |||||||||||||
Ad Valorem Taxes | - M$ | 11,373.7 | 0.0 | 145.9 | 11,519.6 | |||||||||||||
Operating Expenses | - M$ | 125,456.2 | 370.5 | 6,828.1 | 132,654.9 | |||||||||||||
Workover Expenses | - M$ | 0.0 | 0.0 | 0.0 | 0.0 | |||||||||||||
Misc. | - M$ | 0.0 | 0.0 | 0.0 | 0.0 | |||||||||||||
Other Deductions | - M$ | 0.0 | 0.0 | 0.0 | 0.0 | |||||||||||||
Investments | - M$ | 0.0 | 25.0 | 15,553.7 | 15,578.7 | |||||||||||||
Net Cash Flows | - M$ | 328,848.9 | 2,471.5 | 42,207.1 | 373,527.6 | |||||||||||||
Discounted @ 10% | - M$ | 142,804.9 | 1,192.2 | 17,245.7 | 161,242.8 |
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Prospectus Summary | 1 | |||
Risk Factors | 24 | |||
Use of Proceeds | 44 | |||
Capitalization | 45 | |||
Dilution | 46 | |||
How We Will Make Cash Distributions | 47 | |||
Our Cash Distribution Policy and Restrictions on Distributions | 57 | |||
Selected Historical and Pro Forma Financial and Operating Data | 73 | |||
Management’s Discussions and Analysis of Financial Condition and Results of Operations | 76 | |||
Business | 93 | |||
Management | 111 | |||
Security Ownership of Certain Beneficial Owners and Management | 117 | |||
Certain Relationships and Related Party Transactions | 119 | |||
Conflicts of Interest and Fiduciary Duties | 122 | |||
Description of the Common Units | 130 | |||
The Partnership Agreement | 132 | |||
Units Eligible for Future Sale | 145 | |||
Material Tax Consequences | 146 | |||
Selling Unitholders | 163 | |||
Investment in US by Employee Benefit Plans | 163 | |||
Underwriting | 165 | |||
Validity of the Common Units | 168 | |||
Experts | 168 | |||
Where You Can Find More Information | 168 | |||
Forward-Looking Statements | 168 | |||
Index to Financial Statements | F-1 | |||
Appendix A — Agreement of Limited Partnership of EV Energy Partners, L.P. | A-1 | |||
Appendix B — Glossary of Terms | B-1 | |||
Appendix C — Summary Reserve Report | C-1 |
Limited Partnership Interests
Raymond James
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Item 13. | Other Expenses of Issuance and Distribution. |
SEC registration fee | $ | 10,078 | ||
NASD filing fee | 9,919 | |||
NASDAQ listing fee | 100,000 | |||
Printing and engraving expenses | 300,000 | |||
Fees and expenses of legal counsel | 1,000,000 | |||
Accounting fees and expenses | 500,000 | |||
Transfer agent and registrar fees | 5,000 | |||
Miscellaneous | 75,003 | |||
Total | $ | 2,000,000 | ||
Item 14. | Indemnification of Officers and Members of Our Board of Directors. |
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 Limited Partnership of EV Energy Partners, L.P.** | |||
3 | .2 | — | Form of Amended and Restated Limited Partnership Agreement of EV Energy Partners, L.P. (included as Appendix A to the Prospectus and including specimen unit certificate for the common units) | |||
3 | .3 | — | Certificate of Limited Partnership of EV Energy GP, L.P.** | |||
3 | .4 | — | Form of First Amended and Restated Limited Partnership Agreement of EV Energy GP, L.P.* | |||
3 | .5 | — | Certificate of Formation of EV Management, LLC** | |||
3 | .6 | — | Form of Amended and Restated Limited Liability Agreement of EV Management, LLC** |
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Exhibit | ||||||
Number | Description | |||||
5 | .1 | — | Opinion of Haynes and Boone, LLP as to the legality of the securities being registered** | |||
8 | .1 | — | Opinion of Haynes and Boone, LLP relating to tax matters* | |||
10 | .1 | — | Form of Credit Agreement* | |||
10 | .2 | — | EV Energy Partners, LP Long-Term Incentive Plan | |||
10 | .3 | — | Contribution Agreement* | |||
10 | .4 | — | Omnibus Agreement* | |||
10 | .5 | — | Contract Operating Agreement* | |||
10 | .6 | — | Gas Purchase Agreement between Excelon Energy Company and CGAS Exploration, Inc. dated September 14, 2005 | |||
10 | .7 | — | Term sheet between Riley Natural Gas Company and EnerVest WV, LP dated October 11, 2005 | |||
10 | .8 | — | Base Contract for Purchase of Natural Gas-EOG between WPS Energy Services, Inc. and CGAS Exploration, Inc. dated October 9, 2003 | |||
10 | .9 | — | Base Contract for the Sale and Purchase of Natural Gas between EnerVest Monroe Marketing, Ltd. and Cargas Operating Company dated July 1, 2001 | |||
10 | .10 | — | Base Contract for the Sale and Purchase of Natural Gas between EnerVest Monroe Marketing, Ltd. and Cargas Operating Company dated July 1, 2001 | |||
21 | .1 | — | List of Subsidiaries of EV Energy Partners, L.P. | |||
23 | .1 | — | Consent of Cawley, Gillespie & Associates, Inc. | |||
23 | .2 | — | Consent of Deloitte & Touche LLP | |||
23 | .3 | — | Consent of Haynes and Boone, LLP (contained in Exhibit 5.1)** | |||
23 | .4 | — | Consent of Haynes and Boone, LLP (contained in Exhibit 8.1)* | |||
23 | .5 | — | Powers of Attorney (contained on the signature page)** | |||
99 | .1 | — | Consent of Nominee for Director for Mr. Petersen | |||
99 | .2 | — | Consent of Nominee for Director for Mr. Lindahl III |
* | To be filed by amendment. |
** | Previously filed. |
Item 17. | Undertakings. |
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By: | /s/ Michael E. Mercer |
Signature | Title with EV Management, LLC | Date | ||||
/s/ John B. Walker* John B. Walker | Director, Chief Executive Officer (principal executive officer) | July 13, 2006 | ||||
/s/ Mark A. Houser* Mark A. Houser | Director, Chief Operating Officer (principal operating officer) | July 13, 2006 | ||||
/s/ Michael E. Mercer Michael E. Mercer | Chief Financial Officer (principal accounting officer) | July 13, 2006 | ||||
* /s/ Michael E. Mercer Michael E. Mercer Attorney-in-fact |
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Number | Description | |||||
1 | .1 | — | Form of Underwriting Agreement* | |||
3 | .1 | — | Certificate of Limited Partnership of EV Energy Partners, L.P.** | |||
3 | .2 | — | Form of Amended and Restated Limited Partnership Agreement of EV Energy Partners, L.P. (included as Appendix A to the Prospectus and including specimen unit certificate for the common units) | |||
3 | .3 | — | Certificate of Limited Partnership of EV Energy GP, L.P.** | |||
3 | .4 | — | Form of First Amended and Restated Limited Partnership Agreement of EV Energy GP, L.P.* | |||
3 | .5 | — | Certificate of Formation of EV Management, LLC** | |||
3 | .6 | — | Form of Amended and Restated Limited Liability Agreement of EV Management, LLC** | |||
5 | .1 | — | Opinion of Haynes and Boone, LLP as to the legality of the securities being registered** | |||
8 | .1 | — | Opinion of Haynes and Boone, LLP relating to tax matters* | |||
10 | .1 | — | Form of Credit Agreement* | |||
10 | .2 | — | EV Energy Partners, LP Long-Term Incentive Plan | |||
10 | .3 | — | Contribution Agreement* | |||
10 | .4 | — | Omnibus Agreement* | |||
10 | .5 | — | Contract Operating Agreement* | |||
10 | .6 | — | Gas Purchase Agreement between Excelon Energy Company and CGAS Exploration, Inc. dated September 14, 2005 | |||
10 | .7 | — | Term sheet between Riley Natural Gas Company and EnerVest WV, LP dated October 11, 2005 | |||
10 | .8 | — | Base Contract for Purchase of Natural Gas-EOG between WPS Energy Services, Inc. and CGAS Exploration, Inc. dated October 9, 2003 | |||
10 | .9 | — | Base Contract for the Sale and Purchase of Natural Gas between EnerVest Monroe Marketing, Ltd. and Cargas Operating Company dated July 1, 2001 | |||
10 | .10 | — | Base Contract for the Sale and Purchase of Natural Gas between EnerVest Monroe Marketing, Ltd. and Cargas Operating Company dated July 1, 2001 | |||
21 | .1 | — | List of Subsidiaries of EV Energy Partners, L.P. | |||
23 | .1 | — | Consent of Cawley, Gillespie & Associates, Inc. | |||
23 | .2 | — | Consent of Deloitte & Touche LLP | |||
23 | .3 | — | Consent of Haynes and Boone, LLP (contained in Exhibit 5.1)** | |||
23 | .4 | — | Consent of Haynes and Boone, LLP (contained in Exhibit 8.1)* | |||
23 | .5 | — | Powers of Attorney (contained on the signature page)** | |||
99 | .1 | — | Consent of Nominee for Director for Mr. Petersen | |||
99 | .2 | — | Consent of Nominee for Director for Mr. Lindahl III |
* | To be filed by amendment. |
** | Previously filed. |