UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10–K

 

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2011

 

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission File Number

001-33024

 

EV Energy Partners, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware
(State or other jurisdiction of incorporation or organization) 
  20–4745690
(I.R.S. Employer Identification No.)
     
1001 Fannin, Suite 800, Houston, Texas
(Address of principal executive offices) 
  77002
(Zip Code)

 

Registrant’s telephone number, including area code: (713) 651-1144

 

Securities registered pursuant to Section 12(b) of the Act:

 

Common Units Representing Limited Partner Interests   NASDAQ Stock Market LLC
(Title of each class)   (Name of each exchange on which registered)

  

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well–known seasoned issuer, as defined in Rule 405 of the Securities Act. YES þ NO ¨

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES ¨ NO þ

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES þ NO ¨

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES þ NO ¨

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III or any amendment to the Form 10–K. ¨

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b–2 of the Exchange Act. Check one:

 

Large accelerated filer þ   Accelerated filer ¨
     
Non-accelerated filer ¨   Smaller reporting company ¨

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act).

YES ¨ NO þ

 

The aggregate market value of the common units held by non–affiliates at June 30, 2011 based on the closing price on the NASDAQ Global Market on June 30, 2011 was $1,732,236,663.

 

As of February 17, 2012, the registrant had 38,447,350 common units outstanding.

  

 

 

 
 

 

Table of Contents 

 

PART I.
     
Item 1. Business 5
Item 1A. Risk Factors 25
Item 1B. Unresolved Staff Comments 43
Item 2. Properties 44
Item 3. Legal Proceedings 44
Item 4. Mine Safety Disclosures 44
     
PART II
     
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 45
Item 6. Selected Financial Data 48
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 49
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 61
Item 8. Financial Statements and Supplementary Data 63
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 91
Item 9A. Controls and Procedures 91
Item 9B. Other Information 91
     
PART III
     
Item 10. Directors, Executive Officers and Corporate Governance 92
Item 11. Executive Compensation 97
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 110
Item 13. Certain Relationships and Related Transactions, and Director Independence 111
Item 14. Principal Accounting Fees and Services 115
     
PART IV
     
Item 15. Exhibits, Financial Statement Schedules 116
     
Signatures   120

 

1
 

 

GLOSSARY OF OIL AND NATURAL GAS TERMS

 

Bbl. One stock tank barrel or 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.

 

Bcf. One billion cubic feet of natural gas.

 

Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

 

Btu. A British thermal unit is a measurement of the heat generating capacity of natural gas. One Btu is the heat required to raise the temperature of a one–pound mass of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

 

Completion. Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.

 

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

 

Developed oil and gas reserves. Reserves of any category that can be expected to be recovered:

 

·through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, and

 

·through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

 

·gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves;

 

·drill, fracture, stimulate and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly;

 

·acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

 

·provide improved recovery systems.

 

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

Dry hole or well. An exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

 

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

 

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

 

2
 

 

Mcf. One thousand cubic feet of natural gas.

 

Mcfe. One thousand cubic feet of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six Mcf of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six Mcf of natural gas.

 

MMBbls. One million barrels of oil or other liquid hydrocarbons.

 

MMBtu. One million British thermal units.

 

MMcf. One million cubic feet of natural gas.

 

Natural gas liquids. The hydrocarbon liquids contained within natural gas.

 

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

 

NYMEX. The New York Mercantile Exchange.

 

Oil. Crude oil and condensate.

 

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

 

·costs of labor to operate the wells and related equipment and facilities;

 

·repairs and maintenance;

 

·materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities;

 

·property taxes and insurance applicable to proved properties and wells and related equipment and facilities; and

 

·severance taxes.

 

Productive well. An exploratory, development or extension well that is not a dry well.

 

Proved reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

 

Reserves. Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

 

3
 

 

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

 

Standardized measure. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”), without giving effect to non–property related expenses such as certain general and administrative expenses, debt service and future federal income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes.

 

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

 

Undeveloped oil and gas reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

 

Workover. Operations on a producing well to restore or increase production.

 

4
 

 

PART I

 

ITEM 1. BUSINESS

 

Overview

 

EV Energy Partners, L.P. (“we,” “our,” “us” or the “Partnership”) is a publicly held Delaware limited partnership that engages in the acquisition, development and production of oil and natural gas properties. Our general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited partnership, and the general partner of our general partner is EV Management, LLC (“EV Management”), a Delaware limited liability company. EV Management is a wholly owned subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited partnership. EnerVest and its affiliates have a significant interest in us through their 71.25% ownership of EV Energy GP which, in turn, owns a 2% general partner interest in us and all of our incentive distribution rights (“IDRs”).

 

Our common units are traded on the NASDAQ Global Market under the symbol “EVEP.” Our business activities are primarily conducted through wholly owned subsidiaries.

 

We operate in one reportable segment engaged in the acquisition, development and production of oil and natural gas properties. As of December 31, 2011, our properties were located in the Barnett Shale, the Appalachian Basin (which includes the Utica Shale), the Mid–Continent areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the San Juan Basin, the Monroe Field in Northern Louisiana, the Permian Basin, Central and East Texas (which includes the Austin Chalk area), and Michigan.

 

We have grown our reserves and production substantially since the beginning of 2010. Since January 1, 2010, we have completed 12 acquisitions for an aggregate purchase price of $1.0 billion. The estimated net proved reserves at December 31, 2011 attributable to these acquisitions were 789 Bcfe, representing 69% of our December 31, 2011 net proved reserves on an Mcfe basis. These acquisitions also provided us a new core operating area in the Barnett Shale and significant growth in our Mid–Continent area and Appalachian Basin, including significant interests prospective for the Utica Shale in Ohio. These acquisitions increased the amount and percentage of our net proved reserves that are undeveloped, which will increase our capital expenditures to develop these reserves, primarily through drilling and completion activities.

 

Oil and natural gas reserve information is derived from our reserve report prepared by Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), our independent reserve engineers. All of our proved oil and natural gas reserves are located in the United States. The following table summarizes information about our proved oil and natural gas reserves by geographic region as of December 31, 2011:

 

  Estimated Net Proved Reserves 
  Oil
(MMBbls)
  Natural Gas
(Bcf)
  Natural 
Gas Liquids
(MMBbls)
  Bcfe 

PV–10 (1)

($ in millions)

 
                
Barnett Shale  1.3   467.4   28.7   647.4  $623.4 
Appalachian Basin  5.1   95.8      126.4   244.2 
Mid–Continent area  3.5   51.1   1.5   81.2   159.0 
San Juan Basin  1.3   40.2   3.5   68.6   86.6 
Monroe Field     60.9      60.9   22.0 
Permian Basin  0.7   20.2   5.0   54.1   104.9 
Central and East Texas  3.2   28.1   2.2   60.9   148.7 
Michigan     44.9      44.9   28.3 
Total  15.1   808.6   40.9   1,144.4  $1,417.1 

 

 

(1)At December 31, 2011, our standardized measure of discounted future net cash flows was $1,406.1 million. Because we are a limited partnership, we made no provision for federal income taxes in the calculation of standardized measure; however, we made a provision for future obligations under the Texas gross margin tax. The present value of future net pre–tax cash flows attributable to estimated net proved reserves, discounted at 10% per annum (“PV–10”), is a computation of the standardized measure of discounted future net cash flows on a pre–tax basis. PV–10 is computed on the same basis as standardized measure but does not include a provision for federal income taxes or the Texas gross margin tax. PV–10 is considered a non–GAAP financial measure under the regulations of the Securities and Exchange Commission (the “SEC”). We believe PV–10 to be an important measure for evaluating the relative significance of our oil and natural gas properties. We further believe investors and creditors may utilize our PV–10 as a basis for comparison of the relative size and value of our reserves to other companies. PV–10, however, is not a substitute for the standardized measure. Our PV–10 measure and the standardized measure do not purport to present the fair value of our oil and natural gas reserves.

 

5
 

 

The table below provides a reconciliation of PV–10 to the standardized measure at December 31, 2011 (dollars in millions):

 

PV–10 $1,417.1 
Future Texas gross margin taxes, discounted at 10%  (11.0)
Standardized measure $1,406.1 

 

Developments in 2011

 

Acquisitions

 

On November 1, 2011, we acquired oil and natural gas properties in the Mid–Continent area for $74.3 million, subject to customary purchase price adjustments.

 

On December 1, 2011, we, along with certain institutional partnerships managed by EnerVest, acquired oil and natural gas properties in the Barnett Shale. We acquired a 31.02% proportional interest in these properties for $75.7 million, subject to customary purchase price adjustments.

 

On December 20, 2011, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Barnett Shale. We acquired a 31.63% proportional interest in these properties for $271.4 million, subject to customary purchase price adjustments.

 

In addition to the acquisitions described above, we also made the following smaller acquisitions:

 

·we, along with certain institutional partnerships managed by EnerVest, acquired a proportional 31.02% interest in oil and natural gas properties in Barnett Shale for an aggregate purchase price of $17.3 million; and

 

·we acquired oil and natural gas properties in the Appalachian Basin from certain institutional partnerships managed by EnerVest for $31.1 million, subject to customary purchase price adjustments.

 

Other

 

In March 2011, we closed a public offering of 3.45 million common units at an offering price of $44.42 per common unit. We received net proceeds of $149.8 million, including a contribution of $3.0 million by our general partner to maintain its 2% interest in us. We used a portion of the net proceeds to repay indebtedness outstanding under our credit facility.

 

In March 2011, we issued $300.0 million in aggregate principal amount of 8.0% senior unsecured notes due 2019. We received net proceeds of $291.5 million, after deducting the discount of $7.5 million and offering expenses of $1.0 million. We used the net proceeds to repay indebtedness outstanding under our credit facility.

 

In April 2011, we entered into a second amended and restated $1.0 billion credit facility that expires in April 2016. The facility requires the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.25 to 1.0. The borrowing base is subject to scheduled redeterminations every six months beginning October 1, 2011. As of December 31, 2011, the borrowing base is $800.0 million.

 

6
 

 

In December 2011, EV Energy GP notified us that it had made an IDR reset election as defined in our partnership agreement. Under the IDR reset election, EV Energy GP relinquished its right to receive incentive distribution payments based on the minimum quarterly and target cash distribution levels set at the time of our public offering. The minimum quarterly distribution was increased from $0.40 to $0.7615 and the levels at which the IDRs participate in distributions were reset at higher amounts based on current common unit distribution rates and a formula in the partnership agreement. In connection with the IDR reset election, EV Energy GP was issued 3.9 million Class B units. The IDR reset election became effective and the Class B units were issued on December 12, 2011. Each Class B unit will become convertible into one common unit at the election of the holder of the Class B units at any time after December 12, 2012. Under the terms of the partnership agreement, the IDR reset election does not affect EV Energy GP’s interest in us (which will remain at 2%), and EV Energy GP is not required to make an additional contribution in connection with the IDR reset election.

 

In December 2011, we entered into a Purchase and Sale Agreement and a Development Agreement with Total E&P USA, Inc. (“Total”), a subsidiary of Total S.A., and Chesapeake Energy Corporation (“Chesapeake”), whereby Total acquired an undivided 25% interest in approximately 619,000 net acres in the Utica Shale and agreed to fund certain future development costs.  Of this acreage, approximately 542,000 net acres were sold by Chesapeake, approximately 73,250 net acres were sold by institutional partnerships managed by EnerVest and approximately 3,750 net acres were sold by us.  We received $4.2 million in cash for our acres.  We continue to own working interests in these acres.  Our portion of future development costs to be carried by Total is $9.9 million, which we anticipate receiving by the end of 2014.  We also contributed $0.5 million for a 9% interest in an entity that will own the midstream infrastructure related to production primarily generated from the assets.

 

In 2011, we and certain institutional partnerships managed by EnerVest carved out 7.5% overriding royalty interests ("ORRI") from 315,000 net (419,000 gross) acres (the "Underlying Properties") in Ohio, which we believe may be prospective for the Utica Shale, and contributed the ORRI to a newly formed limited partnership.  EnerVest is the general partner of this partnership.  The ORRI will entitle the partnership to an average approximate 5.64% of the gross revenues from the Underlying Properties.  We own a 48% limited partner interest in the partnership.

 

Developments in 2012

 

On February 7, 2012, we, along with certain institutional partnerships managed by EnerVest, had a second closing on the oil and natural gas properties in the Barnett Shale that we acquired in December 2011. We acquired a 31.63% proportional interest in these properties for $28.7 million, subject to customary purchase price adjustments.

 

In February 2012, we closed a public offering of 4.025 million common units at an offering price of $67.95 per common unit. We received net proceeds from this offering of $268.2 million, including a contribution of $5.4 million by our general partner to maintain its 2% interest in us. We expect to incur offering expenses of approximately $0.2 million. We used the net proceeds to repay indebtedness outstanding under our credit facility. As of February 17, 2012, indebtedness outstanding under our credit facility was $420.0 million.

 

Business Strategy

 

Our primary business objective is to manage our oil and natural gas properties for the purpose of generating cash flows and providing stability and growth of distributions per unit for the long–term benefit of our unitholders. To meet this objective, we intend to execute the following business strategies:

 

·Pursue acquisitions of long–lived producing oil and natural gas properties with relatively low decline rates, predictable production profiles, and low– risk development opportunities

 

Our acquisition program targets oil and natural gas properties that we believe will generate attractive risk-adjusted expected rates of return and that will be financially accretive. These acquisitions are characterized by long–lived production, relatively low decline rates and predictable production profiles, as well as low–risk development opportunities. As part of this strategy, we continually seek to optimize our asset portfolio, which may include the divestiture of noncore assets.

 

Our active acquisition efforts may involve our participation in auction processes, as well as situations in which we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We finance acquisitions with a combination of cash flow from operations, borrowings under our senior secured credit facility and funds from equity and debt offerings. We also acquire interests in properties alongside the institutional partnerships managed by EnerVest, which has allowed us to participate in much larger acquisitions than would otherwise be available to us.

 

7
 

 

·Reduce cash flow volatility and exposure to commodity price and interest rate risk through commodity price and interest rate derivatives

 

Changes in oil, natural gas and natural gas liquids prices may cause our revenues and cash flows to be volatile. We enter into various derivative contracts intended to achieve more predictable cash flow and to reduce our exposure to fluctuations in the prices of oil, natural gas and natural gas liquids. We currently maintain derivative contracts for a significant portion of our oil, natural gas and natural gas liquids production.

 

Our commodity derivatives are primarily in the form of swaps and collars that are designed to provide a fixed price (swaps) or range of prices between a price floor and a price ceiling (collars) that we will receive. Without the use of these commodity derivatives, we would be exposed to the full range of price fluctuations. In addition, we enter into interest rate swaps to minimize the effects of fluctuations in interest rates.

 

·Maximize asset value and cash flow stability through our operating and technical expertise

 

We seek to maintain an inventory of drilling and development projects to maintain and grow our production from our capital development program. EnerVest operates properties representing approximately 93% of our estimated net proved reserves as of December 31, 2011. Our development program is focused on lower–risk, repeatable drilling opportunities to maintain and grow cash flow.

 

·Maintain focus on controlling the costs of our operations

 

We focus on controlling the operating costs of our properties. We manage our operating costs by using advanced technologies and integrating the knowledge, expertise and experience of our management teams as well as the managerial and technical staff of EnerVest. Regarding our non–operated properties, we proactively engage with the operators to ensure disciplined and cost focused operations are being implemented.

 

·Maintain conservative levels of indebtedness to reduce risk and facilitate acquisition opportunities

 

Since our initial public offering in 2006, we have financed approximately 60% of our $1.8 billion of oil and natural gas property acquisitions with free cash flow and the issuance of common units in public and private offerings. We seek to maintain sufficient liquidity not only for our operating positions but also to maintain flexibility in financing our acquisitions.

 

·Pursue monetization alternatives for all or a portion of our working interest position in the Utica Shale

 

We hold a significant position of approximately 150,000 net working interest acres in Ohio that we believe may be prospective for the Utica Shale. During 2012, we intend to pursue alternatives for the sale or monetization of all or a portion of these net working interest acres.

 

Competitive Strengths

 

We believe that we are well positioned to achieve our primary business objective and to execute our strategies because of the following competitive strengths:

 

·Geographically diversified asset base characterized by long–life reserves and predictable decline rates

 

We own a diversified portfolio of oil and natural gas properties, producing from multiple formations in eight producing basins with an average reserve life of 19 years. Our properties have well understood geologic features and relatively predictable production profiles.

 

·Significant inventory of low–risk development opportunities

 

We have a significant inventory of development projects in our core areas of operation. At December 31, 2011, we had 1,800 identified gross drilling locations, of which approximately 1,000 were proved undeveloped drilling locations and the remainder were unproved drilling locations. In 2011, we drilled a total of 169 gross (32.3 net) wells with a 95% gross success rate. Our development program is focused on lower risk drilling opportunities to maintain and increase production.

 

8
 

 

·Relationship with EnerVest

 

Our relationship with EnerVest provides us with a wide breadth of operational, financial, technical, risk management and other expertise across a broad geographical range, which assists us in evaluating acquisition and development opportunities. In addition, we believe that our relationship with EnerVest allows us to participate in much larger acquisitions than would otherwise be available to us.

 

·Experienced management, operating and technical teams

 

Our executive officers and key employees have on average over 25 years of experience in the oil and natural gas industry and over ten years of experience acquiring and managing oil and natural gas properties for EnerVest partnerships.

 

·Substantial hedging through 2015 at attractive average prices

 

By removing the price volatility from a significant portion of our production, we have mitigated, but not eliminated, the potential effects of changing commodity prices on our cash flow from operations for the hedged periods.

 

Our Relationship with EnerVest

 

Our general partner is EV Energy GP, and its general partner is EV Management, which is a wholly owned subsidiary of EnerVest. Through our omnibus agreement, EnerVest agrees to make available its personnel to permit us to carry on our business. We therefore benefit from the technical expertise of EnerVest, which we believe would generally not otherwise be available to a company of our size.

 

EnerVest’s principal business is to act as general partner or manager of EnerVest partnerships that were formed to acquire, explore, develop and produce oil and natural gas properties. A primary investment objective of the EnerVest partnerships is to make periodic cash distributions. EnerVest was formed in 1992, and has acquired for its own account and for the EnerVest partnerships oil and natural gas properties for a total purchase price of more than $6.0 billion, which includes over $1.8 billion related to our acquisitions of oil and natural gas properties. EnerVest acts as an operator of over 20,000 oil and natural gas wells in 12 states.

 

While our relationship with EnerVest is a significant attribute, it is also a source of potential conflicts. For example, we have acquired oil and natural gas properties from partnerships formed by EnerVest and partnerships in which EnerVest has an interest, and we may do so in the future. We have also acquired interests in oil and natural gas properties in conjunction with institutional partnerships managed by EnerVest. In these acquisitions, we and the institutional partnerships managed by EnerVest each acquire an interest in all of the properties subject to the acquisition. The purchase is allocated among us and the institutional partnerships managed by EnerVest based on the interest acquired. In the future, it is possible that we would vary the manner in which we jointly acquire oil and natural gas properties with the institutional partnerships managed by EnerVest.

 

EnerVest currently operates properties representing 93% of our proved oil and gas reserves as of December 31, 2011. The EnerVest partnerships own interests in the oil and gas properties in which we own interests and which are operated by EnerVest. The properties are primarily located in the Barnett Shale, Central and East Texas and the Appalachian Basin, and these properties represent approximately 67% of our net proved reserves at December 31, 2011. The investment strategy of the EnerVest partnerships is to typically divest their properties in three to five years, while our strategy contemplates holding such properties for a longer term. If the EnerVest partnerships were to sell their interests in these properties to a person not affiliated with EnerVest, we may not have a sufficient working interest to cause EnerVest to remain operator of the property. The EnerVest partnerships are under no obligation to us with respect to their sale of the properties they own.

 

EnerVest is not restricted from competing with us. It may acquire, develop or dispose of oil and natural gas properties or other assets in the future without any obligation to offer us the opportunity to purchase or participate in the development of those assets. In addition, the principal business of the EnerVest partnerships is to acquire and develop oil and natural gas properties. The agreement for one of the current EnerVest partnerships, however, provides that if EnerVest becomes aware, other than in its capacity as an owner of our general partner, of acquisition opportunities that are suitable for purchase by the EnerVest partnership, EnerVest must first offer those opportunities to that EnerVest partnership, in which case we would be offered the opportunities only if the EnerVest partnerships chose not to pursue the acquisition. EnerVest’s obligation to offer acquisition opportunities to its existing EnerVest partnership will not apply to acquisition opportunities which we generate internally, and EnerVest has agreed with us that for so long as it controls our general partner it will not enter into any agreements which would limit our ability to pursue acquisition opportunities that we generate internally.

 

9
 

 

Our Areas of Operation

 

At December 31, 2011, our properties were located in the Barnett Shale, the Appalachian Basin (which includes the Utica Shale), the Mid–Continent areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the San Juan Basin, the Monroe Field in Northern Louisiana, the Permian Basin, Central and East Texas (which includes the Austin Chalk area), and Michigan.

 

Barnett Shale

 

We, along with certain institutional partnerships managed by EnerVest, acquired our Barnett Shale properties in December 2010, June 2011, September 2011 and December 2011. The properties are primarily located in Denton, Parker, Tarrant and Wise counties in Northern Texas. Our portion of the estimated net proved reserves as of December 31, 2011 was 647.4 Bcfe, 72% of which is natural gas. During 2011, we drilled 35 gross wells, all of which were successfully completed. EnerVest operates wells representing 100% of our estimated net proved reserves in this area, and we own an average 29% working interest in 976 gross productive wells.

 

Appalachian Basin (including the Utica Shale)

 

We acquired our Appalachian Basin properties at our formation, and we acquired additional properties in the Appalachian Basin, primarily in West Virginia, in December 2007, September 2008, November 2009, March 2010, June 2010, August 2011 and October 2011. Our activities are concentrated in the Ohio and West Virginia areas of the Appalachian Basin. Our Ohio area properties are producing primarily from the Knox and Clinton formations and other Devonian age sands in 41 counties in Eastern Ohio and 11 counties in Western Pennsylvania. Our West Virginia area properties are producing primarily from the Balltown, Benson and Big Injun formations in 23 counties in North Central West Virginia. Our estimated net proved reserves as of December 31, 2011 were 126.4 Bcfe, 76% of which is natural gas. During 2011, we drilled 33 gross wells, 26 of which were successfully completed. EnerVest operates wells representing 92% of our estimated net proved reserves in this area, and we own an average 41% working interest in 8,670 gross productive wells.

 

Primarily through acquisitions completed in 2009 and 2010, we hold approximately 150,000 net working interest acres and an approximate 2% average ORRI in approximately 880,000 gross acres in the State of Ohio which we believe may be prospective for the Utica Shale. In addition, partnerships managed by EnerVest own acreage which may be prospective for the Utica Shale. The Utica Shale is an Ordovician-age shale that extends under much of the eastern United States. The most prospective area of the Utica Shale is in eastern Ohio, where it is located at depths ranging from 5,000 to 11,000 feet deep. The Point Pleasant carbonate member, located directly under the Utica Shale, is commonly included when referring to the Utica Shale. The Utica Shale is expected to have three separate areas that produce dry natural gas, wet natural gas (natural gas with natural gas liquids), and oil. Horizontal drilling and hydraulic fracturing are required to allow production of hydrocarbons at economic rates. The first commercial production from the Utica Shale in eastern Ohio was achieved in 2011, and industry drilling activity is increasing.

 

We and EnerVest have not completed, as operator, any wells targeting the Utica Shale, although we have participated in several wells drilled by others. At December 31, 2011, our estimated net proved reserves in the Utica Shale were not material to us. Exploration and development activities targeting the Utica Shale are in the early stages, and it is possible that our estimates of the acreage in Ohio that we believe is prospective for the Utica Shale may change, perhaps materially, as additional exploration and development activities are conducted in the area.

 

We do not expect to fully develop our Utica Shale properties for our account. In 2012, we plan to drill, with EnerVest as operator, between three and five gross wells targeting the Utica Shale, one of which we are currently drilling. During 2012, we intend to pursue alternatives for the monetization of all or a portion or our working interest acres related to the Utica Shale. Such monetization could take many forms, and we cannot at this time predict the type of transaction or transactions we may enter into or the type or amount of consideration we may receive. We may not be successful in our efforts to monetize the Utica Shale properties, it may take longer to complete a transaction than we expect, or we may decide not to monetize all or a portion of the Utica Shall properties on this time frame.

 

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Mid–Continent Area

 

We acquired our Mid–Continent area properties in December 2006, August 2008, September 2008, September 2010 and November 2011. The properties are primarily located in 47 counties in Oklahoma, 17 counties in Texas, four parishes in North Louisiana, one county in Kansas and six counties in Arkansas. Our estimated net proved reserves as of December 31, 2011 were 81.2 Bcfe, 63% of which is natural gas. During 2011, we drilled 82 gross wells, all of which were successfully completed. EnerVest operates wells representing 33% of our estimated net proved reserves in this area, and we own an average 12% working interest in 1,864 gross productive wells.

 

San Juan Basin

 

We acquired our San Juan Basin properties in September 2008, July 2010 and December 2010. The properties are primarily located in Rio Arriba County, New Mexico and La Plata County in Colorado. Our estimated net proved reserves as of December 31, 2011 were 68.6 Bcfe, 59% of which is natural gas. During 2011, we drilled two gross wells, one of which was successfully completed. EnerVest operates wells representing 94% of our estimated net proved reserves in this area, and we own an average 71% working interest in 227 gross productive wells.

 

Monroe Field

 

We acquired our Monroe Field properties at our formation, and we acquired additional properties in the Monroe Field in March 2007. The properties are primarily located in two parishes in Northeast Louisiana. Our estimated net proved reserves as of December 31, 2011 were 60.9 Bcfe, 100% of which is natural gas. During 2011, we drilled one well, which was successfully completed. EnerVest operates wells representing 100% of our estimated net proved reserves in this area, and we own an average 100% working interest in 3,930 gross productive wells.

 

Permian Basin

 

We acquired our Permian Basin properties in October 2007. The properties are primarily located in the Yates, Seven Rivers, Queen, Morrow, Clear Fork and Wichita Albany formations in four counties in New Mexico and Texas. Our estimated net proved reserves as of December 31, 2011 were 54.1Bcfe, 37% of which is natural gas. During 2011, we did not drill any wells. EnerVest operates wells representing 99% of our estimated net proved reserves in this area, and we own an average 93% working interest in 160 gross productive wells.

 

Central and East Texas

 

We, along with certain institutional partnerships managed by EnerVest, acquired our Central and East Texas properties in June 2007, May 2008, August 2008, July 2009, September 2009 and October 2010. The properties produce primarily from the Austin Chalk formation and are located in 30 counties in Central and East Texas. Our portion of the estimated net proved reserves as of December 31, 2011 was 60.9 Bcfe, 46% of which is natural gas. During 2011, we drilled 16 gross wells, 15 of which were successfully completed. EnerVest operates wells representing 93% of our estimated net proved reserves in this area, and we own an average 12% working interest in 1,829 gross productive wells.

 

Michigan

 

We acquired our Michigan properties in January 2007, and we acquired additional properties in Michigan in August 2008. The properties are located in the Antrim Shale reservoir in Otsego and Montmorency counties in northern Michigan. Our estimated net proved reserves as of December 31, 2011 were 44.9 Bcfe, 100% of which is natural gas. During 2011, we did not drill any wells. EnerVest operates wells representing 99% of our estimated net proved reserves in this area, and we have an average 84% working interest in 370 gross productive wells.

 

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Our Oil and Natural Gas Data

 

Our Reserves

 

The following table presents our estimated net proved oil and natural gas reserves at December 31, 2011:

 

  Oil
(MMBbls)
  Natural Gas
(Bcf)
  Natural 
Gas Liquids
(MMBbls)
  Bcfe 
Proved reserves:                
Developed  11.7   557.4   25.4   779.7 
Undeveloped  3.4   251.2   15.5   364.7 
Total  15.1   808.6   40.9   1,144.4 

 

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are 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 for recompletion. See “Glossary of Oil and Natural Gas Terms.”

 

All proved undeveloped locations conform to the SEC rules defining proved undeveloped locations. None of our proved undeveloped reserves as of December 31, 2011 have remained undeveloped for more than five years. We do not have any reserves that would be classified as synthetic oil or synthetic natural gas.

 

Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production, both of which provide accurate forecasts. Non–producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. These methods provide accurate forecasts due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

 

The data in the above table represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. Please read “Risk Factors” in Item 1A.

 

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, 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%. Because we are a limited partnership which passes through our taxable income to our unitholders, we have made no provisions for federal income taxes in the calculation of standardized measure; however, we have made a provision for future obligations under the Texas gross margin tax. Standardized measure does not give effect to derivative transactions. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

 

Our Proved Undeveloped Reserves

 

We annually review all proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. We expect to convert our PUDs to proved developed reserves within five years of the date they are first booked as PUDs, except for 2.4% of our PUDs that require sidetracks of existing producing wells, in which case the development will occur when existing production ceases. At December 31, 2011, we had 364.7 Bcfe of PUDs compared with 239.3 Bcfe of PUDs at December 31, 2010. The increase in PUDs at December 31, 2011 compared with December 31, 2010 is primarily attributable to 154.8 Bcfe of PUDs from our 2011 acquisitions of oil and natural gas properties, partially offset by the conversion of 30.9 Bcfe, or approximately 13%, of PUDs to proved developed reserves. In 2011, we spent approximately $25.7 million related to the development of our PUDs.

 

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Internal Controls Applicable to our Reserve Estimates

 

Our policies and procedures regarding internal controls over the recording of our oil and natural gas reserves is structured to objectively and accurately estimate our oil and natural gas reserves quantities and present values in compliance with both accounting principles generally accepted in the United States and the SEC’s regulations.  Compliance with these rules and regulations is the responsibility of our Senior Vice President of Acquisitions, who is also our principal engineer. He has over 27 years of experience in the oil and natural gas industry, with exposure to reserves and reserve related valuations and issues during most of this time, and is a qualified reserves estimator (“QRE”), as defined by the standards of the Society of Petroleum Engineers. Further professional qualifications include a Bachelor of Science, Master of Science and Ph.D. in Petroleum Engineering, extensive internal and external reserve training, asset evaluation and management, and he is a registered professional engineer in the state of Texas. In addition, our principal engineer is an active participant in industry reserve seminars, professional industry groups, is a member of the Society of Petroleum Engineers, spent 13 years as an SPE Technical Editor and has authored several technical papers.

 

Our controls over reserve estimates included retaining Cawley Gillespie as our independent petroleum engineers. We provided information about our oil and natural gas properties, including production profiles, prices and costs, to Cawley Gillespie and they prepared their own estimates of our oil and natural gas reserves attributable to our properties. All of the information regarding reserves in this annual report on Form 10–K is derived from the report of Cawley Gillespie, which is included as an exhibit to this annual report on Form 10–K. The principal engineer at Cawley Gillespie responsible for preparing our reserve estimates is W. Todd Brooker, a Senior Vice President and Principal with Cawley Gillespie. Mr. Brooker is a licensed professional engineer in the state of Texas (license #83462) with over 20 years of experience in petroleum engineering.

 

We and EnerVest maintain an internal staff of petroleum engineers, geoscience professionals and petroleum landmen who work closely with Cawley Gillespie to ensure the integrity, accuracy and timeliness of data furnished to Cawley Gillespie in their reserves estimation process. Our Senior Vice President of Acquisitions reviews and approves the reserve information compiled by our internal staff. Our technical team meets regularly with representatives of Cawley Gillespie to review properties and discuss the methods and assumptions used by Cawley Gillespie in their preparation of the year end reserves estimates. Our technical team and Senior Vice President of Acquisitions also meet regularly to review the methods and assumptions used by Cawley Gillespie in their preparation of the year end reserves estimates.

 

The audit committee of our board of directors meets with management, including the Senior Vice President of Acquisitions, to discuss matters and policies related to our oil and natural gas reserves.

 

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Our Productive Wells

 

The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2011. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of productive wells in which we have a working interest, regardless of our percentage interest. A net well is not a physical well, but is a concept that reflects the actual total working interest we hold in a given well. We compute the number of net wells we own by totaling the percentage interests we hold in all our gross wells.

 

Our wells may produce both oil and natural gas. We classify a well as an oil well if the net equivalent production of oil was greater than natural gas for the well.

 

  Gross Wells  Net Wells 
  Oil  Natural
Gas
  Total  Oil  Natural
Gas
  Total 
Barnett Shale:                        
Operated  12   932   944   4   272   276 
Non–operated     32   32      2   2 
Appalachian Basin:                        
Operated  1,153   6,650   7,803   506   2,840   3,346 
Non–operated  46   821   867   8   165   173 
Mid–Continent area:                        
Operated  108   239   347   84   181   265 
Non–operated  622   895   1,517   52   112   164 
San Juan Basin:                        
Operated  20   143   163   20   138   158 
Non–operated  16   48   64   1   9   10 
Monroe Field:                        
Operated     3,930   3,930      3,930   3,930 
Non–operated                  
Permian Basin                        
Operated  7   145   152   7   140   147 
Non–operated  3   5   8      2   2 
Central and East Texas:                        
Operated  686   797   1,483   157   111   268 
Non–operated  17   329   346   1   15   16 
Michigan:                        
Operated     345   345      309   309 
Non–operated     25   25      8   8 
Total (1)  2,690   15,336   18,026   840   8,234   9,074 

 

 

(1)In addition, we own small royalty interests in over 1,000 wells.

 

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Our Developed and Undeveloped Acreage

 

The following table sets forth information relating to our leasehold acreage as of December 31, 2011:

 

  Developed Acreage  Undeveloped Acreage 
  Gross  Net  Gross  Net 
Barnett Shale  94,230   26,571   19,213   5,307 
Appalachian Basin  1,049,276   491,786   450,378   156,137 
Mid–Continent area  395,456   112,161   29,873   8,599 
San Juan Basin  102,591   35,574   43,857   34,342 
Monroe Field (1)  6,169   6,169   172,163   147,484 
Permian Basin  11,781   11,366   1,560   412 
Central and East Texas  1,041,294   107,398   16,690   2,199 
Michigan  27,457   25,822       
Total  2,728,254   816,847   733,734   354,480 

 

 

(1)  There are no spacing requirements on substantially all of the wells on our Monroe Field properties; therefore, one developed acre is assigned to each productive well for which there is no spacing unit assigned.

 

Substantially all of our developed and undeveloped acreage is held by production, which means that as long as our wells on the acreage continue to produce, we will continue to hold the leases. The leases in which we hold an interest that are not held by production are not material to us.

Title to Properties

 

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Our properties are subject to customary royalty and other interests, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect our carrying value of the properties.

 

Production by Field

 

The following table sets forth our production for 2011 and 2010 from the Barnett Shale, which is the only field for which our estimated net proved reserves at December 31, 2011 attributable to the field represented 15% or more of our total estimated net proved reserves at December 31, 2011:

 

  Year Ended December 31, 
  2011  2010 
  Oil
(MBbls)
  Natural
Gas (Mcf)
  Natural
Gas
Liquids
(MBbls)
  Oil
(MBbls)
  Natural
Gas (Mcf)
  Natural
Gas
Liquids
(MBbls)
 
                         
Barnett Shale (1)  12   6,812   411      38    

 

 

(1)We acquired our interests in the Barnett Shale in December 2010, June 2011, September 2011 and December 2011. Our production information includes production from the acquired interests in the Barnett Shale from the date of acquisition.

 

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Our Drilling Activity

 

We intend to concentrate our drilling activity on low risk development drilling opportunities. The number and types of wells we drill will vary depending on the amount of funds we have available for drilling, the cost of each well, the size of the fractional working interests we acquire in each well, the estimated recoverable reserves attributable to each well and the accessibility to the well site.

 

The following table summarizes our approximate gross and net interest in development wells completed by us during 2011, 2010 and 2009, regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

 

  Year Ended December 31, 
  2011  2010  2009 
Gross wells:            
Productive  160.0   52.0   30.0 
Dry  9.0   3.0    
Total  169.0   55.0   30.0 
Net wells:            
Productive  29.9   7.9   6.1 
Dry  2.4   1.2    
Total  32.3   9.1   6.1 

 

As of December 31, 2011, we were participating in the drilling of five gross (0.6 net) development wells.

 

We drilled 21 gross (6.9 net) exploratory wells in 2011, 14 of which were successfully completed as producers. We drilled three gross (0.3 net) exploratory wells in 2010, two of which were successfully completed as producers. We did not drill any exploratory wells in 2009.

 

Well Operations

 

We have entered into operating agreements with EnerVest. Under these operating agreements, EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest, if our interest entitles us to control the appointment of the operator of the well, gathering system or production facilities. As contract operator, EnerVest designs and manages the drilling and completion of our wells and manages the day to day operating and maintenance activities for our wells.

 

Under these operating agreements, EnerVest has established a joint account for each well in which we have an interest. We are required to pay our working interest share of amounts charged to the joint account. The joint account is charged with all direct expenses incurred in the operation of our wells and related gathering systems and production facilities. The determination of which direct expenses can be charged to the joint account and the manner of charging direct expenses to the joint account for our wells is done in accordance with the Council of Petroleum Accountants Societies (“COPAS”) model form of accounting procedure.

 

Under the COPAS model form, direct expenses include the costs of third party services performed on our properties and wells, as well as gathering and other equipment used on our properties. In addition, direct expenses include the allocable share of the cost of services performed on our properties and wells by EnerVest employees. The allocation of the cost of EnerVest employees who perform services on our properties is based on time sheets maintained by EnerVest’s employees. Direct expenses charged to the joint account also include an amount determined by EnerVest to be the fair rental value of facilities owned by EnerVest and used in the operation of our properties.

 

Principal Customers, Marketing Arrangements and Delivery Commitments

 

The market for our oil, natural gas and natural gas liquids production depends on factors beyond our control, including the extent of domestic production and imports of oil, natural gas and natural gas liquids, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil, natural gas and natural gas liquids, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

 

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Our oil, natural gas and natural gas liquids production is sold to a variety of purchasers. The terms of sale under the majority of existing contracts are short–term, usually one year or less in duration. The prices received for oil, natural gas and natural gas liquids sales are generally tied to monthly or daily indices as quoted in industry publications.

 

In 2011, 2010 and 2009, no customer accounted for greater than 10% of our consolidated oil, natural gas and natural gas liquids revenues. We believe that the loss of a major customer would have a temporary effect on our revenues but that over time, we would be able to replace our major customers.

 

We do not have any delivery commitments that are material to us.

 

Competition

 

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil and natural gas companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

 

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

 

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and there can be no assurances that we will be able to compete satisfactorily when attempting to make further acquisitions.

 

Seasonal Nature of Business

 

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations primarily in certain areas of the Appalachian Basin, the San Juan Basin and Michigan. As a result, we generally perform the majority of our drilling in these areas during the summer and autumn months. In addition, the Monroe Field properties in Louisiana are subject to flooding. These seasonal anomalies can pose challenges for meeting our drilling objectives and increase competition for equipment, supplies and personnel during the drilling season, which could lead to shortages and increased costs or delay our operations. Generally demand for natural gas is higher in summer and winter months. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter natural gas requirements during off–peak months. This can also lessen seasonal demand fluctuations.

 

Environmental, Health and Safety Matters and Regulation

 

Our operations are subject to stringent and complex federal, state and local laws and regulations that govern the protection of the environment as well as the discharge of materials into the environment. These laws and regulations may, among other things:

 

·require the acquisition of various permits before drilling commences;

 

·require the installation of pollution control equipment in connection with operations;

 

·place restrictions or regulations upon the use or disposal of the material utilized in on our operations;

 

·restrict the types, quantities and concentrations of various substances that can be released into the environment or used in connection with drilling, production and transportation activities;

 

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·limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

 

·require remedial measures to mitigate pollution from former and ongoing operations, such as site restoration, pit closure and plugging of abandoned wells; and

 

·require the expenditure of significant amounts in connection with worker health and safety.

 

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry has recently been the subject of increased legislation and regulatory attention with respect to environmental matters.

 

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

 

Solid and Hazardous Waste Handling

 

The federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous solid waste. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, we generate waste as a routine part of our operations that may be subject to RCRA. Although a substantial amount of the waste generated in our operations are regulated as non–hazardous solid waste rather than hazardous waste, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non–hazardous or exempt waste or categorize some non–hazardous or exempt waste as hazardous in the future. Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.

 

Comprehensive Environmental Response, Compensation and Liability Act

 

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called potentially responsible parties include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the Environmental Protection Agency, or EPA, and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

 

Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages.

 

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

 

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Clean Water Act

 

The Federal Water Pollution Control Act, also known as the “Clean Water Act” and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non–compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and cleanup and response costs.

 

Safe Drinking Water Act and Hydraulic Fracturing

 

Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except for fracturing activities involving the use of diesel). Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, there have been recent developments at the federal and state levels that could result in regulation of hydraulic fracturing becoming more stringent and costly. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with interim results of the study anticipated to be available by late 2012, and final results anticipated in 2014. In December 2011, the EPA also published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming; this study remains subject to review and public comment.

 

In addition, a committee of the U.S. House of Representatives conducted an investigation of hydraulic fracturing practices. Moreover, legislation was introduced in prior sessions of Congress to provide for federal regulation of hydraulic fracturing by eliminating the current exemption in the Safe Drinking Water Act, and, further, to require disclosure of the chemicals used in the fracturing process, and similar legislation could be introduced in the current session of Congress that convened on January 3, 2011. Also, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has imposed a de facto moratorium on the issuance of permits for high-volume, horizontal hydraulic until state-administered environmental studies are finalized; the public comment period on the revised draft of the environmental impact closed on January 11, 2012, Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed and Wyoming has adopted legislation requiring drilling operators conducting hydraulic fracturing activities in that state to publicly disclose the chemicals used in the fracturing process. If new laws or regulations imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where we conduct business, we could incur substantial compliance costs and such requirements could adversely delay or restrict our ability to conduct fracturing activities on our assets.

 

Oil Pollution Act

 

The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain "responsible parties" related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable "responsible party" includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.

 

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Air Emissions  

 

Our operations are subject to the federal Clean Air Act, or CAA, and analogous state laws and local ordinances governing the control of emissions from sources of air pollution. The CAA and analogous state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (or toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forego construction, modification or operation of certain air emission sources.

 

On July 28, 2011, the EPA proposed a rule to subject oil and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and the National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs under the Clean Air Act, and to impose new and amended requirements under both programs. Under the proposal, the EPA would, among other things, amend standards applicable to natural gas processing plants and would expand the NSPS to include all oil and natural gas operations, imposing requirements on those operations. The EPA is also proposing NSPS standards for completions of hydraulically fracturing natural gas wells. The proposed standards include the reduced emission completion techniques. The NESHAPS proposal includes maximum achievable control technology, or MACT, standards for certain glycol dehydrators and storage vessels, and revises applicability provisions, alternative test protocols and the availability of the startup, shutdown and maintenance exemption. The EPA is under a court order to finalize the rules, with the current deadline of April 3, 2012. Should these rules become final and applicable to our operations, they could result in increased operating and compliance costs, increased regulatory burdens and delays in our operations.

 

National Environmental Policy Act

 

Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act, or NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

 

Climate Change Legislation

 

More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted in the future and could cause us to incur material expenses in complying with them. The EPA has been moving forward to regulate GHGs as pollutants under the CAA and has already adopted rules establishing GHG emission limits from motor vehicles beginning with the 2012 model year. As a result, the EPA, as of January 2, 2011, requires the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs in a multi-step process, with the largest sources first subject to permitting. Some states, regions and localities have adopted or have considered programs to address GHG emissions. In addition, both houses of Congress actively considered legislation to reduce emissions of greenhouse gases and many states have adopted or considered measures to establish GHG emissions reduction levels, often involving the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs would work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances. Federal efforts at a cap and trade program appear to not be moving forward in Congress. Some members of Congress have publicly indicated an intention to introduce legislation to curb EPA’s regulatory authority over GHGs. Depending on the regulatory reach of new CAA legislation implementing regulations or new EPA and/or state, regional or local rules restricting the emission of GHGs, we could incur significant costs to control our emissions and comply with regulatory requirements. In addition, in October 2009, the EPA has adopted a mandatory GHG emissions reporting program which imposes reporting and monitoring requirements on various industries and in November 2010, expanded this GHG reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. Significant financial expenditures could be required to comply with the monitoring, recordkeeping and reporting requirements under the EPA's GHG reporting program.  We do not believe, however, that our compliance with applicable monitoring, recordkeeping and reporting requirements under GHG reporting program as recently amended will have a material adverse effect on our results of operations or financial position.

 

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Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. Moreover, the federal, regional, state and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

 

Endangered Species Act

 

The Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations on oil and natural gas leases that have species that are listed and species that could be listed as threatened or endangered under the act. The U.S. Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material restrictions to our use of the land and may materially delay or prohibit land access for oil and natural gas development. It also may adversely impact the value of the affected leases.

 

OSHA and Other Laws and Regulation 

 

We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right–to–know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

 

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the years ended December 31, 2011, 2010 and 2009. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2012 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact our business activities, financial condition, results of operations or ability to pay distributions to our unitholders.

 

Other Regulation of the Oil and Natural Gas Industry

 

The oil and natural gas industry is extensively regulated by numerous federal, state, local and tribal authorities. Rules and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, frequently increasing the regulatory burden and the potential for financial sanctions for noncompliance. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

 

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

 

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Drilling and Production

 

Statutes, rules and regulations affecting exploration and production undergo constant review and often are amended, expanded and reinterpreted, making the prediction of future costs or the impact of regulatory compliance to new laws and statute difficult. The regulatory burden on the oil and natural gas industry increases its cost of doing business and, consequently, affects its profitability. Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:

 

·the location of wells;

 

·the method of drilling, completing and operating 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.

 

State and federal regulations are generally intended to prevent waste of oil and natural gas, protect correlative rights to produce oil and natural gas between owners in a common reservoir or formation, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and natural gas plants operated by other companies that provide midstream services to us are also subject to the jurisdiction of various federal, state and local authorities, which can affect our operations. State laws also regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. States in the Appalachian Basin have taken up consideration of forced pooling. Other states rely on voluntary pooling of lands and leases.

 

States generally impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within its jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

 

In addition, many states and some tribal nations have enacted surface damage statutes (“SDAs”). These laws are designed to compensate for damage caused by oil and natural gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and require specific payments to be made in connection with exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

 

We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut–in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

 

If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non–discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management (the “BLM”), Bureau of ocean Energy Management, Bureau of Safety and Environmental Enforcement, Bureau of Indian Affairs, tribal or other appropriate federal, state and/or Indian tribal agencies.

 

The Mineral Leasing Act of 1920 (the “Mineral Act”) prohibits ownership of any direct or indirect interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign entity except through equity ownership in an entity formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States. If these restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney General. We qualify as an entity formed under the laws of the United States or of any U.S. State or territory. Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non–reciprocal countries, there are presently no such designations in effect. It is possible that our unitholders may be citizens of foreign countries that are determined to be non–reciprocal countries under the Mineral Act. In such event, any federal onshore oil and natural gas leases held by us could be subject to cancellation based on such determination.

 

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Federal Natural Gas Regulation

 

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act as well as under Section 311 of the Natural Gas Policy Act.

 

Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis. FERC has announced several important transportation related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000, concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC’s pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

 

FERC has also issued several other generally pro–competitive policy statements and initiatives affecting rates and other aspects of pipeline transportation of natural gas. On May 31, 2005, FERC generally reaffirmed its policy of allowing interstate pipelines to selectively discount their rates in order to meet competition from other interstate pipelines. On June 15, 2006, the FERC issued an order in which it declined to establish uniform standards for natural gas quality and interchangeability, opting instead for a pipeline–by–pipeline approach. On June 19, 2006, in order to facilitate development of new storage capacity, FERC established criteria to allow providers to charge market–based (i.e. negotiated) rates for storage services. On June 19, 2008, the FERC removed the rate ceiling on short–term releases by shippers of interstate pipeline transportation capacity.

 

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

 

State Natural Gas Regulation

 

Various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

 

Hydraulic Fracturing

 

Our Barnett Shale and Utica Shale properties, and most of our other properties, are subject to hydraulic fracturing procedures as the process is required to economically develop the properties. The hydraulic fracturing process is integral to our drilling and completion costs in these areas and typically represent up to 60% of the total drilling/completion costs per well.

 

We diligently review best practices and industry standards, and comply with all regulatory requirements in the protection of these potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time, and disposing of all non–commercially produced fluids in certified disposal wells at depths below the potable water sources.

 

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In compliance with laws enacted in various states, we will disclose hydraulic fracturing data to the appropriate chemical registry. These laws generally require disclosure for each chemical ingredient that is subject to the requirements of OSHA regulations, as well as the total volume of water used in the hydraulic fracturing treatment.

 

There have not been any material incidents, citations or suits related to our hydraulic fracturing activities involving violations of environmental laws and regulations.

 

Other Regulation

 

In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our unitholders.

 

Insurance

 

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies that include coverage for control of well, general liability (includes sudden and accidental pollution), physical damage to our oil and gas natural properties, auto liability, worker's compensation and employer's liability, among other things.

 

Currently, we have general liability insurance coverage up to $1.0 million per occurrence, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy limits and in most cases, deductibles that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, we maintain $90.0 million in excess liability coverage, which is in addition to and triggered if the general liability per occurrence limit is reached.

 

We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, we believe our general liability and excess liability insurance policies would cover third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies.

 

We re–evaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to self–insure or maintain only catastrophic coverage for certain risks in the future.

 

Employees

 

EV Management, the general partner of our general partner, has six full time employees and two executive officers who spend a significant amount of their time on our operations. At December 31, 2011, EnerVest, the sole member of EV Management, had approximately 775 full–time employees, including over 65 geologists, engineers and land professionals. To carry out our operations, EnerVest employs the people who will provide direct support to our operations. None of these employees are covered by collective bargaining agreements. We consider EV Management’s relationship with its employees to be good, and EnerVest considers its relationship with its employees to be good.

 

Offices

 

We do not have any material owned or leased property (other than our interests in oil and gas properties). Under our omnibus agreement, EnerVest provides us office space for our executive officers and other employees at EnerVest’s offices in Houston, Texas.

 

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Available Information

 

Our annual reports on Form 10–K, quarterly reports on Form 10–Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our website at www.evenergypartners.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. These documents are also available on the SEC’s website at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. Our website also includes our Code of Business Conduct and the charters of our audit committee and compensation committee. No information from either the SEC’s website or our website is incorporated herein by reference.

 

ITEM 1A. RISK FACTORS

 

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks were actually to occur, our business, financial condition or results of operations or cash flows could be materially adversely affected.  

 

Risks Related to Our Business

 

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 and Class B units at the current distribution rate under our cash distribution policy.

 

In order to make our cash distributions at our current quarterly distribution rate of $0.763 per common and Class B unit, we will require available cash of approximately $32.9 million per quarter based on the common and Class B units outstanding as of February 17, 2012. We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at this anticipated quarterly distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

·the amount of oil and natural gas we produce;

 

·the prices at which we sell our oil and natural gas production;

 

·our ability to acquire additional oil and natural 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.

 

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

 

·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;

 

·the timing and collectability of receivables; and

 

·prevailing economic conditions.

 

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As a result of these factors, the amount of cash we distribute to our unitholders may fluctuate significantly from quarter to quarter and may be less than the quarterly distribution amount that we expect to distribute.

 

Natural gas prices have declined substantially in the last year, and are expected to remain depressed for the foreseeable future. Approximately 71% of our production, on an Mcfe basis, is natural gas. Sustained depressed prices of natural gas will adversely affect our assets, development plans, results of operations and financial position, perhaps materially.

 

Natural gas prices have declined from $4.22 for the January 2011 NYMEX Henry Hub Futures contract settled December 29, 2010 to $3.08 for the January 2012 Henry Hub Futures contract settled December 28, 2011. The reduction in prices has been caused by many factors, including recent increases in natural gas production from non–conventional (shale) reserves, warmer than normal weather and high levels of natural gas in storage. We have hedged approximately 88% and 81% of our estimated natural gas production in 2012 and 2013, respectively, at prices higher than those currently prevailing. However, if prices for natural gas remain depressed for long periods, we may be required to write down the value of our oil and natural gas properties or revise our development plans, which may cause certain of our undeveloped well location to no longer be deemed proved. In addition, sustained low prices for natural gas will reduce the amounts we would otherwise have available to pay expenses, distribute to our unitholders and service our debt obligations.

 

If oil and natural gas prices remain depressed for a prolonged period, our cash flows from operations will decline and we may have to lower our distributions or may not be able to pay distributions at all and may be unable to service our debt obligations.

 

Our revenue, profitability and cash flow depend upon the prices for oil and natural gas. The prices we receive for oil and natural gas production are volatile and a drop in prices can significantly affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms, all of which can affect our ability to pay distributions. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our cash flows. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

·the domestic and foreign supply of and demand for oil and natural gas;

 

·the amount of added production from development of unconventional natural gas reserves;

 

·the price and quantity of foreign imports of oil and natural gas;

 

·the level of consumer product demand;

 

·weather conditions;

 

·the value of the U.S dollar relative to the currencies of other countries;

 

·overall domestic and global economic conditions;

 

·political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America, China 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

 

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·the price and availability of alternative fuels.

 

Low oil or natural gas prices will decrease our revenues, but may also reduce the amount of oil or natural gas that we can economically produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non–cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our credit facility, which may adversely affect our ability to make cash distributions to our unitholders and service our debt obligations.

 

We currently own interests in oil and natural gas properties in which partnerships managed by EnerVest also own an interest and we may acquire properties in which the EnerVest managed partnerships own an interest in the future. If the EnerVest partnerships elect to sell their interest in these properties, we would own a minority interest in the properties, and EnerVest may lose the ability to operate the properties.

 

We own interests in oil and natural gas properties in which partnerships managed by EnerVest also own interests, and we expect to make acquisitions of properties jointly with EverVest partnerships in the future. These properties are primarily in the Barnett Shale, Central and East Texas and the Appalachian Basin, and these properties represent approximately 67% of our estimated net proved reserves as of December 31, 2011. The EnerVest partnerships generally have an investment strategy to typically divest properties in three to five years, while our strategy is to hold properties for the longer term. We own less than a majority working interest in the properties in which the EnerVest partnerships also own an interest. If the EnerVest partnerships were to sell their interest in these properties to a person not affiliated with EnerVest, our working interest would not be large enough that we could control the selection of the operator and EnerVest may lose the ability to operate the properties on our behalf. Loss of operations would mean that EnerVest would no longer control decisions regarding the development and production of those properties, and any replacement operator could make decisions regarding development or production activities that make it difficult to implement our strategy.

 

We depend on EnerVest to provide us services necessary to operate our business. If EnerVest were unable or unwilling to provide these services, it would result disruption in our business which could have an adverse effect on our ability to make cash distributions to our unitholders and service our debt obligations.

 

Under an omnibus agreement, EnerVest provides services to us such as accounting, human resources, office space, and other administrative services, and under an operating agreement, EnerVest operates our properties for us. If EnerVest were to become unable or unwilling to provide such services, we would need to develop these services internally or arrange for the services from another service provider. Developing the capabilities internally or by retaining another service provider could have an adverse effect on our ability make cash distributions to our unitholders and our business, and the services, when developed or retained, may not be of the same quality as provided to us by EnerVest.

 

Our hedging transactions expose us to counterparty credit risk.

 

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract.  To mitigate counterparty credit risk, we conduct our hedging activities with financial institutions who are lenders under our credit facility.  Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

 

During periods of falling commodity prices, such as in late 2008 and 2012, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

 

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The adoption of derivatives legislation and regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.  

 

During 2010, the President signed into law the Dodd–Frank Wall Street Reform and Consumer Protection Act (the “Act”).  Among other things, the Act requires the Commodity Futures Trading Commission and the SEC to enact regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over–the–counter market.  We cannot predict the content of these regulations or the effect that these regulations will have on our hedging activities.  Of particular concern, the Act does not explicitly exempt end users (such as us) from the requirements to use cleared exchanges, rather than hedging over–the–counter, and the requirements to post margin in connection with hedging activities.  If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose other requirements that are more burdensome than current regulations, our hedging would become more expensive and we may decide to alter our hedging strategy.

 

The distressed financial conditions of customers could have an adverse impact on us in the event these customers are unable to pay us for the products or services we provide.

 

Some of our customers may experience, in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations or future cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations and financial condition.

 

We may be unable to integrate successfully the operations of our recent or future acquisitions with our operations and we may not realize all the anticipated benefits of the recent acquisitions or any future acquisition.

 

Integration of our recent acquisitions with our business and operations has been a complex, time consuming and costly process. Failure to successfully assimilate our past or future acquisitions could adversely affect our financial condition and results of operations.

 

Our acquisitions involve numerous risks, including:

 

·operating a significantly larger combined organization and adding operations;

 

·difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new business segment or geographic area;

 

·the risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;

 

·the loss of significant key employees from the acquired business:

 

·the diversion of management’s attention from other business concerns;

 

·the failure to realize expected profitability or growth;

 

·the failure to realize expected synergies and cost savings;

 

·coordinating geographically disparate organizations, systems and facilities; and

 

·coordinating or consolidating corporate and administrative functions.

 

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

 

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Unless we replace the oil and natural gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flows from operations and our ability to make distributions to our unitholders or service our debt obligations.

 

Producing reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our decline rate may change when we drill additional wells, make acquisitions or under other circumstances. Our future cash flows and income and our ability to maintain and to increase distributions to unitholders are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing oil and natural gas prices and the number and attractiveness of properties for sale.

 

Our estimated oil and natural gas reserve quantities and future production rates 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.

 

Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. Our estimates of our net proved reserve quantities are based upon reports from Cawley Gillespie, an independent petroleum engineering firm used by us. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, our wells are characterized by low production rates per well. As a result, changes in future production costs assumptions could have a significant effect on our proved reserve quantities.

 

The standardized measure of discounted future net cash flows of our estimated net proved reserves is not necessarily the same as the current market value of our estimated net proved reserves. We base the discounted future net cash flows from our estimated net proved reserves on average prices for the 12 months preceding the date of the estimate. Actual prices received for production and actual costs of such production will be different than these assumptions, perhaps materially.

 

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

Our acquisition and 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.

 

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil and natural gas reserves. As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures as compared to the drilling of a vertical well, sometimes more than three times the cost. The incremental capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores. These expenditures will be deducted from our revenues in determining our cash available for distribution. We intend to finance our future capital expenditures with cash flows from operations, borrowings under our credit facility and the issuance of debt and equity securities. The incurrence of debt will require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:

 

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·the estimated quantities of our oil and natural gas reserves;

 

·the amount of oil and natural gas we produce from existing wells;

 

·the prices at which we sell our production; and

 

·our ability to acquire, locate and produce new reserves.

 

If our revenues or the borrowing base under our credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our credit facility may restrict our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a possible decline in our reserves and production, which could lead to a decline in our oil and natural gas reserves, and could adversely affect our business, results of operation, financial conditions and ability to make distributions to our unitholders. In addition, we may lose opportunities to acquire oil and natural gas properties and businesses.

 

We will rely on development drilling to assist in maintaining our levels of production. If our development drilling is unsuccessful, our cash available for distributions and for servicing our debt obligations and financial condition will be adversely affected.

 

Part of our business strategy will focus on maintaining production levels by drilling development wells. Although we were successful in development drilling in the past, we cannot assure you that we will continue to maintain production levels through development drilling. Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to drill and complete wells. Additionally, seismic technology does not allow us to know conclusively, prior to drilling a well, that oil or natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and it is possible that we will make substantial expenditures on development drilling and not discover reserves in commercially viable quantities. These expenditures will reduce cash available for distribution to our unitholders and for servicing our debt obligations.

 

Our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

 

·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

 

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·uncontrollable flows of oil or natural gas or well fluids.

 

Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities, which could adversely affect our cash available for distribution and for servicing our debt obligations.

 

One of our growth strategies is to capitalize on opportunistic acquisitions of oil and natural gas reserves. Any future acquisition will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities, and other liabilities and similar factors. Ordinarily, our review efforts are focused on the higher valued properties and are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material liabilities and costs that negatively impact our financial conditions and results of operations and our ability to make cash distributions to our unitholders and service our debt obligations.

 

Additional potential risks related to acquisitions include, among other things:

 

·incorrect assumptions regarding the future prices of oil and natural gas or the future operating or development costs of properties acquired;

 

·incorrect estimates of the oil and natural gas reserves attributable to a property we acquire;

 

·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.

 

If we consummate any future acquisitions, our capitalization and results of operations may change significantly.

 

Our hedging activities could result in financial losses or could reduce our net income, which may adversely affect our ability to pay cash distributions to our unitholders and service our debt obligations.

 

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil and natural gas, we have and may continue to enter into hedging arrangements for a significant portion of our oil and natural gas production. If we experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Lastly, an attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge.

 

Our ability to use hedging transactions to protect us from future oil and natural gas price declines will be dependent upon oil and natural gas prices at the time we enter into future hedging transactions and our future levels of hedging, and as a result our future net cash flows may be more sensitive to commodity price changes.

 

Our policy has been to hedge a significant portion of our near–term estimated oil and natural gas production. However, our price hedging strategy and future hedging transactions will be determined at the discretion of our general partner, which is not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price changes.

 

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We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue and our ability to pay distributions to our unitholders and service our debt obligations.

 

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil and natural gas prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. We may be often outbid by competitors in our attempts to acquire properties or companies. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.  

 

Our business is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders and service our debt obligations.

 

Our business activities are subject to operational risks, including:

 

·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 natural gas or well fluids.

 

In addition, a portion of our natural gas production is processed to extract natural gas liquids at processing plants that we own or that are owned by others. If these plants were to cease operations for any reason, we would need to arrange for alternative transportation and processing facilities. These alternative facilities may not be available, which could cause us to shut–in our natural gas production, or the alternative facilities could be more expensive than the facilities we currently use.

 

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

 

As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition, results of operations and ability to pay distributions to our unitholders and service our debt obligations.

 

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Our financial condition and results of operations may be materially adversely affected if we incur costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

 

 We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

 

·the CAA and comparable state laws and regulations that impose obligations related to emissions of air pollutants;

 

·the Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

 

·the Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities;

 

·the CERCLA and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal;

 

·the OPA which subject responsible parties to liability for removal costs and damages arising from an oil spill in waters of the U.S,; and

 

·EPA community right to know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations.

 

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. More stringent laws and regulations, including any related to climate change and greenhouse gases, may be adopted in the future. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

 

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

 

Our oil and natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil and natural gas we may produce and sell.

 

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil and natural gas. While the cost of compliance with these laws has not been material to our operations in the past, the possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to pay distributions to our unitholders and service our debt obligations could be adversely affected.

 

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas we produce.

 

On October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published its amendments to the GHG reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. Reporting of GHG emissions from such facilities will be required on an annual basis beginning in 2012 for emissions occurring in 2011.

 

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On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal CAA. On January 2, 2011, the EPA’s GHG emission standards for light–duty vehicles became effective. This triggers the requirement that permits issued under the CAA Title V and Prevention of Significant Deterioration programs must address GHGs. In June 2010, EPA finalized a GHG tailoring rule, applying GHG permitting initially to the largest stationary sources of GHGs above certain revised emission limits.

 

In addition, both houses of Congress have considered legislation to reduce emissions of GHGs and many states have adopted or considered measures to reduce GHG emission reduction levels, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The adoption and implementation of any legislation or regulatory programs imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. Federal efforts at a cap and trade program appear to not be moving forward in Congress. Some members of Congress have publicly indicated an intention to introduce legislation to curb EPA’s regulatory authority over GHGs.

 

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

 

In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect affect on our financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

 

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from dense rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. Hydraulic fracturing is typically regulated by state oil and natural gas commissions but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. Moreover, the EPA issued proposed rules on July 28, 2011 that would subject oil and natural gas production activities to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. Among other things, the NSPS requirements would include standards for reduced emission completions during hydraulic fracturing activities while the NESHAP requirements would include maximum achievable control technology (“MACT”) standards for certain glycol dehydrators and storage vessels at major sources of hazardous air pollutants. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the fracturing process. At the state level, some states, including Pennsylvania, Louisiana and Texas, where we operate, have adopted, and other states are considering adopting, requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

 

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In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

 

Changes in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.

 

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, incur debt or for other purposes.

 

We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.

 

The marketability of our production will depend in part upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The availability of markets are beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas, the value of our units and our ability to pay distributions on our units and service our debt obligations.

 

We may experience a temporary decline in revenues and production if we lose one of our significant customers.

 

To the extent any significant customer reduces the volume of its oil or natural gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our oil and natural gas production and our revenues and cash available for distribution could decline which could adversely affect our ability to make cash distributions to our unitholders and service our debt obligations.

 

Our ability to make cash distributions will depend on our ability to successfully drill and complete wells on our properties. Seasonal weather conditions and lease stipulations may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

 

Drilling operations in the Appalachian Basin, the San Juan Basin and Michigan are adversely affected by seasonal weather conditions, primarily in the spring. Many municipalities in Appalachia impose weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. In addition, our Monroe Field properties in Louisiana are subject to flooding. This limits our access to these jobsites and our ability to service wells in these areas on a year around basis.

 

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The amount of cash we have available for distribution to holders of our common and Class B units depends on our cash flows.

 

The amount of cash that we have available for distribution depends primarily upon our cash flows, including financial reserves and cash flows from working capital borrowing, and not solely on profitability, which will be affected by non cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.

 

We have significant indebtedness under our credit facility and our 8% senior notes due 2019. Restrictions in our credit facility and our 8% senior notes due 2019 may limit our ability to make distributions to you and may limit our ability to capitalize on acquisitions and other business opportunities.

 

Our credit facility and 8% senior notes due 2019 contain covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates, as well as containing covenants requiring us to maintain certain financial ratios and tests. In addition, the borrowing base under our facility is subject to periodic review by our lenders. Difficulties in the credit markets may cause the banks to be more restrictive when redetermining our borrowing base.

 

We may incur substantial debt in the future to enable us to maintain or increase our production levels and to otherwise pursue our business plan. This debt may restrict our ability to make distributions to our unitholders and service our debt obligations.

 

 Our business requires a significant amount of capital expenditures to maintain and grow production levels. If prices were to decline for an extended period of time, if the costs of our acquisition and development operations were to increase substantially, or if other events were to occur which reduced our revenues or increased our costs, we may be required to borrow significant amounts in the future to enable us to finance the expenditures necessary to replace the reserves we produce. The cost of the borrowings and our obligations to repay the borrowings will reduce amounts otherwise available for distributions to our unitholders.

 

Risks Inherent in an Investment in Us

 

Sales of our common units by the selling unitholders may cause our unit price to decline.

 

Sales of substantial amounts of our common units in the public market, or the perception that these sales may occur, could cause the market price of our common units to decline. In addition, the sale of these units could impair our ability to raise capital through the sale of additional common units.

 

EnerVest controls our general partner, which has sole responsibility for conducting our business and managing our operations. EnerVest, EV Investors, L.P. (“EV Investors”) and EnCap Investments, L.P. (“EnCap”), which are limited partners of our general partner, will have conflicts of interest, which may permit them to favor their own interests to your detriment.

 

EnerVest owns and controls our general partner and EnCap owns a 23.75% limited partnership interest in our general partner. Conflicts of interest may arise between EnerVest, EnCap and their respective affiliates, including our general partner, on the one hand, and us, our unitholders and the holders of our debt obligations, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its owners over the interests of our unitholders and the holders of our debt obligations. These conflicts include, among others, the following situations:

 

·we have acquired oil and natural gas properties from partnerships formed by EnerVest and partnerships and companies in which EnerVest and EnCap have an interest, and we may do so in the future;

 

·neither our partnership agreement nor any other agreement requires EnerVest or EnCap 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 EnCap, in resolving conflicts of interest;

 

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·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 and used to service our debt obligations;

 

·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.

 

Many of the directors and officers who have responsibility for our management have significant duties with, and will spend significant time serving, entities that compete with us in seeking out acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

 

In order to maintain and increase our levels of production, we will need to acquire oil and natural gas properties. Several of the officers and directors of EV Management, the general partner of our general partner, who have responsibilities for managing our operations and activities hold similar positions with other entities that are in the business of identifying and acquiring oil and natural gas properties. For example, Mr. Walker is Executive Chairman of EV Management and President and Chief Executive Officer of EnerVest, which is in the business of acquiring oil and natural gas properties and managing the EnerVest partnerships that are in that business. Mr. Houser, President and Chief Executive Officer and a director of EV Management, is also Executive Vice President and Chief Operating Officer of EnerVest. We cannot assure you that these conflicts will be resolved in our favor. Mr. Gary R. Petersen, a director of EV Management, is also a senior managing director of EnCap, which is in the business of investing in oil and natural gas companies with independent management which in turn is in the business of acquiring oil and natural gas properties. Mr. Petersen is also a director of several oil and natural gas producing entities that are in the business of acquiring oil and natural gas properties. The existing positions of these directors and officers may give rise to fiduciary obligations that are in conflict with fiduciary obligation owed to us. The EV Management officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may be affiliated. Due to these existing and potential future affiliations with these and other entities, they may have fiduciary obligations to present potential business opportunities to those entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that the opportunities are more appropriate for other entities which they serve and elect not to present them to us.

 

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 assets or businesses which in turn could adversely affect our ability to replace reserves, results of operations and cash available for distribution to our unitholders and for servicing our debt obligations.

 

Neither our partnership agreement nor the omnibus agreement between EnerVest and us prohibits EnerVest, EnCap and their affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. For instance, EnerVest, EnCap and their respective affiliates may acquire, develop or dispose of additional oil or natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Each of these entities is a large, established participant in the energy business, and each has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with these entities with respect to commercial activities as well as for acquisition candidates. As a result, competition from these entities could adversely impact our results of operations and accordingly cash available for distribution and for servicing our debt obligations.

 

Cost reimbursements due to our general partner and its affiliates for services provided may be substantial and will reduce our cash available for distribution to our unitholders and for servicing our debt obligations.

 

Pursuant to the omnibus agreement between EnerVest and us, EnerVest will receive reimbursement for the provision of various general and administrative services for our benefit. In addition, we entered into contract operating agreements with a subsidiary of EnerVest pursuant to which the subsidiary will be the contract operator of all of the wells for which we have the right to appoint an operator. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

 

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Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units.

 

Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of EV Management, the general partner of our general partner, have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Our partnership agreement contains provisions that reduce the standards to which our general partner and its affiliates would otherwise be held by state fiduciary duty laws. For example, our partnership agreement permits our general partner and its affiliates to make a number of decisions either in their individual capacities, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner and its affiliates to consider only the interests and factors that they desire, and they have no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include:

 

·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.

 

Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

Our partnership agreement contains provisions restricting the remedies available to unitholders for actions taken by our general partner or its affiliates that might otherwise constitute breaches of fiduciary duty. For example, our 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 the general partner 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 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 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 righs without the approval of the conflicts committee or holders of our common units. This may result in lower distributions to holders of our common units in certain situations.

 

Our general partner has the right 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. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.

 

In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B units. 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. The number of Class B units to be issued will be 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. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights.

 

Holders of our common units have limited voting rights and are not entitled to elect our general partner or the board of directors of its general partner.

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner, its general partner or the members of its board of directors, and will have no right to elect our general partner, its general partner or its board of directors on an annual or other continuing basis. The board of directors of EV Management is chosen by EnerVest, the sole member of EV Management. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have only a limited ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

Even if holders of our common units are dissatisfied, they will have difficulty removing our general partner without its consent.

 

The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. EnerVest owns and controls our general partner, and as of February 17, 2012, officers and directors of EV Management owned an aggregate of 9.1% of our outstanding common and Class B units. Accordingly, it may be difficult for holders of our common units to remove our general partner.

 

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

 

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

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Control of our general partner may be transferred to a third party without unitholder consent.

 

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner or EV Management, from transferring all or a portion of their respective ownership interest in our general partner or EV Management to a third party. The new owners of our general partner or EV Management would then be in a position to replace the board of directors and officers of EV Management with its own choices and thereby influence the decisions taken by the board of directors and officers.

 

We may issue additional units without your approval, which would dilute your existing ownership interests.

 

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

·our unitholders’ proportionate ownership interest in us will decrease;

 

·the amount of cash available for distribution on each unit may decrease;

 

·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.

 

We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our credit facility may restrict our ability to make distributions.

 

Our partnership agreement allows us to borrow to make distributions. We may make short term borrowings under our credit facility, which we refer to as working capital borrowings, to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short term fluctuations in our working capital that would otherwise cause volatility in our quarter to quarter distributions.

 

The terms of our credit facility may restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.

 

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production and service our debt obligations.

 

Our partnership agreement provides that we will distribute all of our available cash to our unitholders each quarter. As a result, we will be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:

 

·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 natural gas industry;

 

·our results of operations and financial condition; and

 

·prices for oil and natural gas.

 

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

 

If at any time our general partner and its affiliates own more than 80% of our common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units.

 

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Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

 

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if:

 

·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 constitutes “control” of our business.

 

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 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. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non–recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

If we distribute cash from capital surplus, which is analogous of a return of capital, our minimum quarterly distribution rate will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased.

 

Our cash distribution will be characterized as coming from either operating surplus or capital surplus. Operating surplus generally means amounts we receive from operating sources, such as sales of our oil and natural gas production, less operating expenditures, such as production costs and taxes, and less estimated maintenance capital, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus generally means amounts we receive from non–operating sources, such as sales of properties and issuances of debt and equity securities. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 98 percent to our unitholders and two percent to our general partner, and will result in a decrease in our minimum quarterly distribution and a lower threshold for distributions on the incentive distribution rights held by our general partner.

 

Our partnership agreement allows us to add to operating surplus up to two times the amount of our most recent minimum quarterly distribution. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates, as holders of incentive distribution rights, rather than to holders of common units as a return of capital.

 

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

 

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

 

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Tax Risks to Common Unitholders

 

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 anticipated after–tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer to as the IRS, on this or any other tax matter affecting us.

 

If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flows and after–tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

 

Current law may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity–level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity–level taxation through the imposition of state income, franchise and other forms of taxation. For example, in Texas, we are now subject to an entity level tax at a maximum effective rate of 0.7% on the portion of our income that is apportioned to Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution to a unitholder.

 

The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.

 

An IRS contest of our U.S. federal income tax positions may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

 

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, costs incurred in any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

 

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

 

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the tax liability that results from that income.

 

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Tax gain or loss on disposition of common units could be more or less than expected.

 

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

 

Tax–exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

 

Investment in common units by tax–exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non–U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non–U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non–U.S. persons will be required to file U.S.federal tax returns and pay tax on their share of our taxable income.

 

We will treat each purchaser of our 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.

 

Because we cannot match transferors and transferees of common units and because of other reasons, we will take depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

 

The sale or exchange of 50% or more of our capital and profits interests during any twelve–month period will result in the termination of our partnership for federal income tax purposes.

 

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve–month period. For example, an exchange of 50% of our capital and profits could occur if, in any twelve–month period, holders of our common units sell at least 50% of the interests in our capital and profits. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

 

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.

 

In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We own assets and do business in the states of Texas, Louisiana, Oklahoma, Arkansas, New Mexico, Colorado, Kansas, Michigan, Ohio, West Virginia and Pennsylvania. Each of these states, other than Texas, currently imposes a personal income tax. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns.

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

 

None.

 

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ITEM 2. PROPERTIES

 

Information regarding our properties is contained in Item 1. Business “—Our Areas of Operation” and “—Our Oil and Natural Gas Data” and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ““—Results of Operations” contained herein.

 

ITEM 3. LEGAL PROCEEDINGS

 

We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material effect on our consolidated financial statements, and no amounts have been accrued at December 31, 2011.

 

ITEM 4. MINE SAFETY DISCLOSURES

 

Not applicable.

 

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PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

Our common units are traded on the NASDAQ Global Market under the symbol “EVEP.” At the close of business on February 21, 2012, based upon information received from our transfer agent and brokers and nominees, we had 165 common unitholders of record. This number does not include owners for whom common units may be held in “street” names.

 

The following table sets forth the range of the daily high and low sales prices per common unit and cash distributions to common unitholders for 2011 and 2010:

 

  Price Range    
  High  Low 

Cash Distribution per

Common Unit (1)

 
2011:            
First Quarter $55.58  $39.20  $0.760 
Second Quarter  59.95   47.58   0.761 
Third Quarter  77.77   52.42   0.762 
Fourth Quarter  77.96   59.93   0.763(2)
             
2010:            
First Quarter $32.93  $27.24  $0.756 
Second Quarter  34.95   21.24   0.757 
Third Quarter  37.90   30.01   0.758 
Fourth Quarter  40.24   35.04   0.759 

 

 

(1)Cash distributions are declared and paid in the following calendar quarter.

 

(2)On January 20, 2012, the board of directors of EV Management declared a quarterly cash distribution for the fourth quarter of 2011 of $0.763 per common and Class B unit. The distribution was paid on February 14, 2012.

 

Cash Distributions to Unitholders

 

We intend to continue to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our credit agreement prohibits us from making cash distributions if any potential default or event of default, as defined in the credit agreement, occurs or would result from the cash distribution.

 

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter:

 

·less the amount of cash reserves established by our general partner to:

 

·provide for the proper conduct of our business;

 

·comply with applicable law, any of our debt instruments or other agreements; or

 

·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.

 

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Our general partner is entitled to 2% of all quarterly distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate share of capital to us to maintain its 2% general partnership interest. When we issued common units in the past, our general partner contributed to us an amount of cash necessary to maintain its 2% interest.

 

Our general partner also holds IDRs that entitle it to receive increasing percentages, up to a maximum of 25%, of the cash we distribute from operating surplus (as defined in our partnership agreement) in excess of the minimum quarterly distribution rate per unit per quarter. The maximum distribution percentage of 25% includes distributions paid to our general partner on its 2% general partner interest and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution percentage of 25% does not include any distributions that our general partner may receive on common units that it owns. For additional information on our distributions, please see Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

 

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter in the following manner:

 

·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; and

 

·thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages in the tables in the following section.

 

IDR Reset Election

 

In December 2011, our general partner notified us that it was making an IDR reset election as defined in our partnership agreement. Under the IDR reset election, our general partner relinquished its right to receive incentive distribution payments based on the minimum quarterly and target cash distribution levels set at the time of our public offering. The minimum quarterly distribution was increased from $0.40 to $0.7615 and the levels at which the IDRs participate in distributions were reset at higher amounts based on current common unit distribution rates and a formula in the partnership agreement. In connection with the IDR reset election, our general partner was issued 3.9 million Class B units. The IDR reset election became effective and the Class B units were issued on December 12, 2011. Each Class B unit will become convertible into one common unit at the election of the holder of the Class B units at any time after December 12, 2012. Under the terms of the partnership agreement, the IDR reset election does not affect our general partner’s interest in us (which will remain at 2%), and our general partner is not required to make an additional contribution in connection with the IDR reset election.

 

Prior to the IDR reset election, our general partner was entitled to incentive distributions if the amount we distributed with respect to one quarter exceeded specified target levels shown below:

 

     Marginal Percentage
Interest in Distributions
 
  Total Quarterly Distributions
Target Amount
  Limited
Partner
  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%
             

 

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Subsequent to the IDR reset election, our general partner is entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:

 

     Marginal Percentage
Interest in Distributions
 
  Total Quarterly Distributions
Target Amount
  Limited
Partner
  General
Partner
 
Minimum quarterly distribution $0.7615   98%  2%
First target distribution Up to $0.875725   98%  2%
Second target distribution Above $0.875725, up to $0.951875   85%  15%
Thereafter Above $0.951875   75%  25%
             

Unregistered Sales of Equity Securities

 

None.

  

Issuer Purchases of Equity Securities

 

None.

 

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ITEM 6. SELECTED FINANCIAL DATA

 

The following table shows selected financial data for the periods and as of the dates indicated. The selected financial data are derived from our audited financial statements. The selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data,” both contained herein.

 

  Year Ended December 31, 
  2011 (1)  2010 (2)  2009 (3)  2008 (4)  2007 (5) 
Statement of Operations Data:                    
Revenues:                    
Oil, natural gas and natural gas liquids revenues $256,370  $165,738  $114,066  $192,757  $89,422 
Gain on derivatives, net           1,597   3,171 
Transportation and marketing–related revenues  5,470   5,780   7,846   12,959   11,415 
Total revenues  261,840   171,518   121,912   207,313   104,008 
                     
Operating costs and expenses:                    
Lease operating expenses  74,419   53,736   41,495   42,681   21,515 
Cost of purchased natural gas  4,078   4,353   4,509   9,849   9,830 
Dry hole and exploration costs  12,140   417          
Production taxes  11,247   7,867   5,983   9,088   3,360 
Asset retirement obligations accretion expense  3,914   3,153   2,035   1,434   814 
Depreciation, depletion and amortization  74,723   55,221   52,048   38,032   19,759 
General and administrative expenses  34,968   23,313   18,556   13,653   10,384 
Impairment of oil and natural gas properties  11,037             
Gain on sales of oil and natural gas properties  (4,017)  (40,656)         
Total operating costs and expenses  222,509   107,404   124,626   114,737   65,662 
                     
Operating income (loss)  39,331   64,114   (2,714)  92,576   38,346 
                     
Other income (expense), net  63,664   42,222   4,372   133,144   (27,102)
                     
Income before income taxes  102,995   106,336   1,658   225,720   11,244 
Income taxes  (354)  (285)  (248)  (235)  (54)
Net income $102,641  $106,051  $1,410  $225,485  $11,190 
General partner’s interest in net income, including incentive distribution rights $10,886  $11,938  $7,040  $8,847  $1,221 
Limited partners’ interest in net income (loss) $91,755  $94,113  $(5,630) $216,638  $9,969 
Net income (loss) per limited partner unit:                    
Basic $2.71  $3.35  $(0.29) $14.12  $0.77 
Diluted $2.68  $3.34  $(0.29) $14.12  $0.77 
Distributions declared per unit $3.046  $3.03  $3.01  $2.82  $2.12 
                     
Financial Position (at end of period):                    
Working capital $122,355  $84,765  $52,825  $94,817  $16,438 
Total assets  2,003,224   1,486,757   907,705   979,995   607,541 
Long–term debt  953,023   619,000   302,000   467,000   270,000 
Owners’ equity  920,039   773,947   547,431   457,484   283,030 

 

 

(1)Includes the results of (i) the acquisition of oil and natural gas properties in the Barnett Shale in June 2011, September 2011 and December 2011, (ii) the acquisition of oil and natural gas properties in the Appalachian Basin in August 2011 and October 2011 and (iii) the acquisition of oil and natural gas properties in the Mid–Continent area in November 2011.

 

(2)Includes the results of (i) the acquisition of oil and natural gas properties in the Appalachian Basin in March 2010 and June 2010, (ii) the acquisition of oil and natural gas properties in the Mid–Continent area in September 2010, (iii) the acquisition of oil and natural gas properties in the San Juan Basin in July 2010 and December 2010, (iii) the acquisition of oil and natural properties in Central and East Texas in October 2010 and (iv) the acquisition of oil and natural gas properties in the Barnett Shale in December 2010.

 

(3)Includes the results of the acquisition of oil and natural gas properties in Central and East Texas in July 2009 and September 2009 and the acquisition of oil and natural gas properties in the Appalachian Basin in November 2009.

 

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(4)Includes the results of (i) the acquisition of oil properties in Central and East Texas in May 2008, August 2008 and September 2008, (ii) the acquisitions of oil and natural gas properties in Michigan in August 2008, (iii) the acquisition of oil and natural gas properties in the Mid–Continent area in August 2008, (iv) the acquisition of natural gas properties in the Appalachian Basin in September 2008 and (v) the acquisition of oil and natural gas properties in the San Juan Basin in September 2008.

 

(5)Includes the results of (i) the acquisition of natural gas properties in Michigan in January 2007, (ii) the acquisition of natural gas properties in the Monroe Field in March 2007, (iii) the acquisition of oil and natural gas properties in Central and East Texas in June 2007, (iv) the acquisition of oil and natural gas properties in the Permian Basin in October 2007 and (v) the acquisition of oil and natural gas properties in the Appalachian Basin in December 2007.

 

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” contained herein.

 

OVERVIEW

 

We are a Delaware limited partnership formed in April 2006 by EnerVest to acquire, produce and develop oil and natural gas properties. Our general partner is EV Energy GP, a Delaware limited partnership, and the general partner of our general partner is EV Management, a Delaware limited liability company.

 

As of December 31, 2011, our properties were located in the Barnett Shale, the Appalachian Basin (which includes the Utica Shale), the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the San Juan Basin, the Monroe Field in Louisiana, the Permian Basin, Central and East Texas (which includes the Austin Chalk area), and Michigan. As of December 31, 2011, we had estimated net proved reserves of 15.1 MMBbls of oil, 808.6 Bcf of natural gas and 40.9 MMBbls of natural gas liquids, or 1,144.4 Bcfe, and a standardized measure of $1,406.1 million.

 

We have grown our reserves and production substantially since the beginning of 2010. Since January 1, 2010, we have completed 12 acquisitions for an aggregate purchase price of $1.0 billion. The estimated net proved reserves at December 31, 2011 attributable to these acquisitions were 789 Bcfe, representing 69% of our December 31, 2011 net proved reserves on an Mcfe basis. These acquisitions also provided us a new core operating area in the Barnett Shale and significant growth in our Mid–Continent area and Appalachian Basin, including significant interests prospective for the Utica Shale in Ohio. These acquisitions increased the amount and percentage of our net proved reserves that are undeveloped, which will increase our capital expenditures to develop these reserves, primarily through drilling and completion activities.

 

Developments in 2011

 

Acquisitions

 

On November 1, 2011, we acquired oil and natural gas properties in the Mid–Continent area for $74.3 million, subject to customary purchase price adjustments.

 

On December 1, 2011, we, along with certain institutional partnerships managed by EnerVest, acquired oil and natural gas properties in the Barnett Shale. We acquired a 31.02% proportional interest in these properties for $75.7 million, subject to customary purchase price adjustments.

 

On December 20, 2011, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Barnett Shale. We acquired a 31.63% proportional interest in these properties for $271.4 million, subject to customary purchase price adjustments.

 

In addition to the acquisitions described above, we also made the following smaller acquisitions:

 

·we, along with certain institutional partnerships managed by EnerVest, acquired a proportional 31.02% interest in oil and natural gas properties in Barnett Shale for an aggregate purchase price of $17.3 million; and

 

·we acquired oil and natural gas properties in the Appalachian Basin from certain institutional partnerships managed by EnerVest for $31.1 million, subject to customary purchase price adjustments.

 

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Other

 

In March 2011, we closed a public offering of 3.45 million common units at an offering price of $44.42 per common unit. We received net proceeds of $149.8 million, including a contribution of $3.0 million by our general partner to maintain its 2% interest in us. We used a portion of the net proceeds to repay indebtedness outstanding under our credit facility.

 

In March 2011, we issued $300.0 million in aggregate principal amount of 8.0% senior unsecured notes due 2019. We received net proceeds of $291.5 million, after deducting the discount of $7.5 million and offering expenses of $1.0 million. We used the net proceeds to repay indebtedness outstanding under our credit facility.

 

In April 2011, we entered into a second amended and restated $1.0 billion credit facility that expires in April 2016. The facility requires the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.25 to 1.0. The borrowing base is subject to scheduled redeterminations every six months beginning October 1, 2011. As of December 31, 2011, the borrowing base is $800.0 million.

 

In December 2011, EV Energy GP notified us that it had made an IDR reset election as defined in our partnership agreement. Under the IDR reset election, EV Energy GP relinquished its right to receive incentive distribution payments based on the minimum quarterly and target cash distribution levels set at the time of our public offering. The minimum quarterly distribution was increased from $0.40 to $0.7615 and the levels at which the IDRs participate in distributions were reset at higher amounts based on current common unit distribution rates and a formula in the partnership agreement. In connection with the IDR reset election, EV Energy GP was issued 3.9 million Class B units. The IDR reset election became effective and the Class B units were issued on December 12, 2011. Each Class B unit will become convertible into one common unit at the election of the holder of the Class B units at any time after December 12, 2012. Under the terms of the partnership agreement, the IDR reset election does not affect EV Energy GP’s interest in us (which will remain at 2%), and EV Energy GP is not required to make an additional contribution in connection with the IDR reset election.

 

In December 2011, we entered into a Purchase and Sale Agreement and a Development Agreement with Total and Chesapeake, whereby Total acquired an undivided 25% interest in approximately 619,000 net acres in the Utica Shale and agreed to fund certain future development costs.  Of this acreage, approximately 542,000 net acres were sold by Chesapeake, approximately 73,250 net acres were sold by institutional partnerships managed by EnerVest and approximately 3,750 net acres were sold by us.  We received $4.2 million in cash for our acres.  We continue to own working interests in these acres.  Our portion of future development costs to be carried by Total is $9.9 million, which we anticipate receiving by the end of 2014.  We also contributed $0.5 million for a 9% interest in an entity that will own the midstream infrastructure related to production primarily generated from the assets.

 

In 2011, we and certain institutional partnerships managed by EnerVest carved out 7.5% ORRI from 315,000 net (419,000 gross) acres (the "Underlying Properties") in Ohio, which we believe may be prospective for the Utica Shale, and contributed the ORRI to a newly formed limited partnership.  EnerVest is the general partner of this partnership.  The ORRI will entitle the partnership to an average approximate 5.64% of the gross revenues from the Underlying Properties.  We own a 48% limited partner interest in the partnership.

 

Developments in 2012

 

On February 7, 2012, we, along with certain institutional partnerships managed by EnerVest, had a second closing on the oil and natural gas properties in the Barnett Shale that we acquired in December 2011. We acquired a 31.63% proportional interest in these properties for $28.7 million, subject to customary purchase price adjustments.

 

In February 2012, we closed a public offering of 4.025 million common units at an offering price of $67.95 per common unit. We received net proceeds from this offering of approximately $268.2 million, including a contribution of $5.4 million by our general partner to maintain its 2% interest in us. We expect to incur offering expenses of approximately $0.2 million. We used the net proceeds to repay indebtedness outstanding under our credit facility. As of February 17, 2012, indebtedness outstanding under our credit facility was $420.0 million.

 

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Business Environment

 

Our primary business objective is to provide stability and growth in cash distributions per unit over time. The amount of cash we can distribute on our units principally depends upon the amount of cash generated from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

·the prices at which we will sell our oil, natural gas liquids and natural gas production;

 

·our ability to hedge commodity prices;

 

·the amount of oil, natural gas liquids and natural gas we produce; and

 

·the level of our operating and administrative costs.

 

Oil and natural gas prices are expected to be volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas include the discovery of substantial accumulations of natural gas in unconventional reservoirs due to technological advancements necessary to commercially produce these unconventional reserves, North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America.

 

In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we are a party to derivatives, and we intend to enter into derivatives in the future to reduce the impact of oil and natural gas price volatility on our cash flows. By removing a significant portion of this price volatility on our future oil and natural gas production through December 2015, we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flows from operations for those periods. If commodity prices are depressed for an extended period of time, it could alter our acquisition and development plans, and adversely affect our growth strategy and ability to access additional capital in the capital markets.

 

The primary factors affecting our production levels are capital availability, our ability to make accretive acquisitions, the success of our drilling program and our inventory of drilling prospects. In addition, as initial reservoir pressures are depleted, production from our wells decreases. We attempt to overcome this natural decline through a combination of drilling and acquisitions. Our future growth will depend on our ability to continue to add reserves through drilling and acquisitions in excess of production. We will maintain our focus on the costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact our production, which may have an adverse effect on our revenues and, as a result, cash available for distribution.

 

We focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long–term operations. Our future cash flows from operations are dependent upon our ability to manage our overall cost structure.

 

Current Low Natural Gas Prices

 

Natural gas prices have declined from $4.22 for the January 2011 NYMEX Henry Hub Futures contract settled December 29, 2010 to $3.08 for the January 2012 Henry Hub Futures contract settled December 28, 2011. The reduction in prices has been caused by many factors, including recent increases in natural gas production from non–conventional (shale) reserves, warmer than normal weather and high levels of natural gas in storage. Prices for oil and natural gas liquids, however, have not been similarly depressed.

 

We have hedged approximately 88% and 81% of our estimated natural gas production in 2012 and 2013, respectively, at prices higher than those currently prevailing. However, if prices for natural gas remain depressed for long periods, we may be required to write down the value of our oil and natural gas properties or revise our development plans, which may cause certain of our undeveloped well location to no longer be deemed proved. In addition, sustained low prices for natural gas will reduce the amounts we would otherwise have available to pay expenses, distribute to our unitholders and service our debt obligations.

 

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If low natural gas prices continue for an extended period of time, we may be unable to hedge additional natural gas production for 2014 and future years at favorable prices. This could cause us to change our development plans for our natural gas properties and shut–in natural gas production, and may result in an impairment in the value of our natural gas properties, a reduction in the borrowing base under our credit facility and reduce our cash available for distribution and for servicing our indebtedness.

 

Critical Accounting Policies

 

The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. Certain of our accounting policies involve estimates and assumptions to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We base these estimates and assumptions on historical experience and on various other information and assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as our operating environment changes and as new events occur.

 

Our critical accounting policies are important to the portrayal of both our financial condition and results of operations and require us to make difficult, subjective or complex assumptions or estimates about matters that are uncertain. We would report different amounts in our consolidated financial statements, which could be material, if we used different assumptions or estimates. We believe that the following are the critical accounting policies used in the preparation of our consolidated financial statements.

 

Oil and Natural Gas Properties

 

We account for our oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

 

No gains or losses are recognized upon the disposition of oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

 

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

 

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The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

 

We assess our proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas and future inflation levels. If the carrying amount of a property exceeds the sum of the estimated undiscounted future net cash flows, we recognize an impairment expense equal to the difference between the carrying value and the fair value of the property, which is estimated to be the expected present value of the future net cash flows from proved reserves. Estimated future net cash flows are based on existing proved reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of our estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

 

Estimates of Oil and Natural Gas Reserves

 

Our estimates of proved oil and natural gas reserves are based on the quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs and workover costs, all of which may vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Independent reserve engineers prepare our reserve estimates at the end of each year.

 

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units–of–production method to amortize the costs of our oil and natural gas properties, the quantity of reserves could significantly impact our depreciation, depletion and amortization expense. Our reserves are also the basis of our supplemental oil and natural gas disclosures.

 

Accounting for Derivatives

 

We use derivatives to hedge against the variability in cash flows associated with the forecasted sale of our anticipated future oil, natural gas and natural gas liquids production. We generally hedge a substantial, but varying, portion of our anticipated oil and natural gas production for the next 12 – 48 months. We do not use derivatives for trading purposes. We have elected not to apply hedge accounting to our derivatives. Accordingly, we carry our derivatives at fair value on our consolidated balance sheet, with the changes in the fair value included in our consolidated statement of operations in the period in which the change occurs. Our current results of operations would potentially have been significantly different had we elected and qualified for hedge accounting on our derivatives.

 

In determining the amounts to be recorded, we are required to estimate the fair values of the derivatives. We base our estimates of fair value upon various factors that include closing prices on the NYMEX, volatility, the time value of options and the credit worthiness of the counterparties to our derivative instruments. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and interest rates.

 

Accounting for Asset Retirement Obligations

 

We have significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. Our removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

 

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We record an asset retirement obligation (“ARO”) and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis.

 

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance.

 

Revenue Recognition

 

Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectibility of the revenue is reasonably assured. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

 

There are two principal accounting practices to account for natural gas imbalances. These methods differ as to whether revenue is recognized based on the actual sale of natural gas (sales method) or an owner's entitled share of the current period's production (entitlement method). We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production.

 

We own and operate a network of natural gas gathering systems in the Monroe Field in Northern Louisiana which gather and transport owned natural gas and a small amount of third party natural gas to intrastate, interstate and local distribution pipelines. Natural gas gathering and transportation revenue is recognized when the natural gas has been delivered to a custody transfer point.

 

RESULTS OF OPERATIONS

 

  Year Ended December 31, 
  2011  2010  2009 
Production data:            
Oil (MBbls)  891   679   514 
Natural gas liquids (MBbls)  1,096   728   768 
Natural gas (MMcf)  29,247   19,486   16,519 
Net production (MMcfe)  41,169   27,933   24,210 
Average sales price per unit:            
Oil (Bbl) $91.72  $74.78  $56.17 
Natural gas liquids (Bbl)  52.99   42.64   31.08 
Natural gas (Mcf)  3.99   4.30   3.71 
Mcfe  6.23   5.93   4.71 
Average unit cost per Mcfe:            
Production costs:            
Lease operating expenses $1.81  $1.92  $1.71 
Production taxes  0.27   0.28   0.25 
Total  2.08   2.20   1.96 
Asset retirement obligations accretion expense  0.10   0.11   0.08 
Depreciation, depletion and amortization  1.82   1.98   2.15 
General and administrative expenses  0.85   0.83   0.77 

 

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Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010

 

Net income for 2011 was $102.6 million compared with $106.1 million for 2010. This change reflects (i) a $90.3 million increase in revenues due to increased production primarily from our acquisitions of oil and natural gas properties in 2010 and 2011 and higher prices for oil and natural gas liquids, (ii) a $9.4 million increase in realized gains on derivatives, (iii) a $32.5 million increase in non–cash changes in the fair value of our derivatives, partially offset by (iv) a $55.7 million increase in operating expenses mainly related to the properties acquired in 2010 and 2011, (v) a $20.1 million increase in interest expense, (vi) impairments of $11.0 million related to the write–down of oil and natural gas properties to their fair value, (vii) a $11.7 million increase in dry hole and exploration costs, and (viii) $36.6 million of lower gains on the sales of oil and natural gas properties.

 

Oil, natural gas and natural gas liquids revenues for 2011 totaled $256.4 million, an increase of $90.6 million compared with 2010. This increase was the result of $77.8 million related to higher production, primarily from our 2010 and 2011 acquisitions, and $19.0 million related to higher realized prices for oil and natural gas liquids, offset by $6.2 million related to lower prices for natural gas.

 

Lease operating expenses for 2011 increased $20.7 million compared with 2010 as the result of $23.0 million related to our 2011 and 2010 acquisitions and our expanded development drilling program, partially offset by $2.3 million ($0.08 per Mcfe) of lease operating expenses in 2010 associated with oil in tanks acquired in the March 2010 acquisition that was sold in 2010. Lease operating expenses per Mcfe were $1.81 in 2011 compared with $1.92 in 2010. The decrease in the rate per Mcfe is attributable to the $0.08 associated with the oil in tanks and, to a lesser extent, lower per Mcfe costs from our 2011 and December 2010 acquisitions of oil and natural gas properties in the Barnett Shale.

 

Dry hole and exploration costs for 2011 increased $11.7 million compared with 2010 as a result of $9.2 million of dry hole costs, primarily related to wells in Central and East Texas and the San Juan Basin, and increased seismic costs at certain of our oil and natural gas properties in the Appalachian Basin.

 

Production taxes for 2011, which are generally based on a percentage of our oil, natural gas and natural gas liquids revenues, increased $3.4 million compared with 2010 as a result of $3.6 million due to increased production, partially offset by $0.2 million due to lower average realized prices for natural gas. Production taxes for 2011 were $0.27 per Mcfe compared with $0.28 per Mcfe for 2010.

 

Asset retirement obligations accretion expense for 2011 increased $0.8 million compared with 2010 due to the oil and natural gas properties that we acquired in 2010 and 2011. Asset retirement obligations accretion expense for 2011 was $0.10 per Mcfe compared with $0.11 per Mcfe for 2010.

 

Depreciation, depletion and amortization for 2011 increased $19.5 million compared with 2010 due to $24.0 million from higher production offset by a decrease of $4.5 million due to a lower average DD&A rate per unit. The lower average DD&A rate reflects the lower cost of reserves acquired in our acquisitions of Barnett Shale properties in 2011 and December 2010. Depreciation, depletion and amortization for 2011 was $1.82 per Mcfe compared with $1.98 per Mcfe for 2010.

 

General and administrative expenses for 2011 totaled $35.0 million, an increase of $11.7 million compared with 2010. This increase is primarily the result of (i) $6.6 million of higher compensation costs primarily related to our equity–based compensation, (ii) $2.1 million of higher fees paid to EnerVest under the omnibus agreement due to an increase in operations from our acquisitions of oil and natural gas properties in 2011 and 2010, (iii) $1.7 million of increased due diligence costs incurred in conjunction with our 2011 acquisitions, and (iv) an overall increase in third party professional fees and costs related to our significant growth. General and administrative expenses for 2011 were $0.85 per Mcfe compared with $0.83 per Mcfe for 2010.

 

In 2011, we incurred impairment charges of $11.0 million to write down oil and natural gas properties to their fair value. Of this amount, $10.4 million related to oil and natural gas properties that were written down to their fair values prior to being sold and $0.6 million related to leasehold impairments of unproved oil and natural gas properties.

 

In 2011, gain on sales of oil and natural gas properties of $4.0 million related to our contribution of approximately 3,750 net acres in the Utica Shale to a joint venture transaction with Total. We received $4.2 million in cash at closing and $9.9 million will be paid in the form of a drilling and completion cost carry, which we anticipate receiving by the end of 2014.

 

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During 2011 and 2010, we recorded cash settlements of $59.0 million and $49.0 million, respectively, as realized gains on derivatives, net, as the contract prices for our derivatives exceeded the underlying market price for that period. Realized gains on derivatives, net for 2011 also exclude $5.3 million related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives and include $4.7 million related to the June 2011 termination of three of our interest rate swaps. The $4.7 million represented the value of these interest rate swaps on the date of termination. The terminated interest rate swaps were rolled over into three new interest rate swaps with a value of $5.2 million at inception.

 

Unrealized gains (losses) on derivatives, net represent the change in the fair value of our open derivatives during the period. In 2011, the fair value of our open derivatives increased from a net asset of $103.9 million at December 31, 2010 to a net asset of $138.8 million at December 31, 2011 due to the decline in natural gas prices in 2011 partially offset by the increase in oil prices during 2011. Included in the fair value at December 31, 2010 is a net receivable of $5.3 million related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives and a net payable of $4.7 million related to the June 2011 termination of three of our interest rate swaps. In 2010, the fair value of our open derivatives increased from a net asset of $93.1 million at December 31, 2009 to a net asset of $103.9 million at December 31, 2010, after giving effect to the $7.8 million of derivatives acquired in December 2010.

 

Interest expense for 2011 increased $20.1 million compared with 2010 due to an increase of $13.8 million from a higher weighted average long–term debt balance and an increase of $6.3 million due to a higher weighted average effective interest rate attributable to our 8% senior notes due 2019 issued March 2011.

 

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009

 

Net income for 2010 was $106.1 million, an increase of $104.6 million compared with 2009. This increase was primarily the result of $49.6 million of higher revenues due to increased production and higher prices for oil, natural gas and natural gas liquids, $54.7 million related to non–cash changes in the fair value of our derivatives and a gain of $40.7 million on the sales of oil and natural gas properties, partially offset by $20.0 million of lower realized gains on our derivatives, $12.2 million of increased lease operating expenses and $4.8 million of increased general and administrative expenses.

 

Oil, natural gas and natural gas liquids revenues for 2010 totaled $165.7 million, an increase of $51.7 million compared with 2009. This increase was the result of $28.2 million related to higher prices for oil, natural gas liquids and natural gas and $23.5 million related to increased production.

 

Transportation and marketing–related revenues for 2010 decreased $2.1 million compared with 2009 primarily due to the recognition of deferred revenues of $1.8 million in 2009 from the production curtailments in the Monroe Field in 2008.

 

Lease operating expenses for 2010 increased $12.2 million compared with 2009 as the result of $6.9 million due to our expanded acquisition and development drilling program, $3.1 million due to generally higher service costs experienced in our industry and $2.3 million ($0.08 per Mcfe) associated with the sales of oil in tanks acquired in the March 2010 acquisition. Lease operating expenses per Mcfe were $1.92 in 2010 compared with $1.71 in 2009.

 

Production taxes for 2010, which are generally based on a percentage of our oil, natural gas and natural gas liquids revenues, increased $1.9 million compared with 2009 as the result of $1.1 million due to increased production and $0.8 million due to higher prices for oil, natural gas and natural gas liquids. Production taxes for 2010 were $0.28 per Mcfe compared with $0.25 per Mcfe for 2009.

 

Asset retirement obligations accretion expense for 2010 increased $1.1 million compared with 2009 due to the oil and natural gas properties that we acquired in 2009 and 2010. Asset retirement obligations accretion expense for 2010 was $0.11 per Mcfe compared with $0.08 per Mcfe for 2009.

 

Depreciation, depletion and amortization for 2010 increased $3.2 million compared with 2009 due to $7.4 million from higher production offset by a decrease of $4.2 million due to a lower average DD&A rate per unit. The lower average DD&A rate reflects the effect of our acquisitions of oil and natural gas properties in 2010. Depreciation, depletion and amortization for 2010 was $1.98 per Mcfe compared with $2.15 per Mcfe for 2009.

 

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General and administrative expenses for 2010 totaled $23.3 million, an increase of $4.8 million compared with 2009. This increase is primarily the result of (i) $2.5 million of higher compensation costs primarily related to our equity–based compensation, (ii) $1.1 million of higher fees paid to EnerVest under the omnibus agreement due to our acquisitions of oil and natural gas properties in 2010 and 2009 and (iii) $1.2 million of increased costs incurred in conjunction with the integration of the oil and natural gas properties acquired in 2010. General and administrative expenses were $0.83 per Mcfe for 2010 compared with $0.77 per Mcfe for 2009.

 

Gain on sales of oil and natural gas properties was $40.7 million for 2010 and was primarily related to the sale of unproved oil and natural gas properties.

 

Realized gains (losses) on derivatives, net represent the monthly settlements with our counterparties related to derivatives that matured during the period. During 2010 and 2009, we received cash payments of $49.0 million and $69.0 million, respectively, from our counterparties as the contract prices for our derivatives exceeded the underlying market price for that period.

 

Unrealized gains (losses) on derivatives, net represent the change in the fair value of our open derivatives during the period. In 2010, the fair value of our open derivatives increased from a net asset of $93.1 million at December 31, 2009 to a net asset of $103.9 million at December 31, 2010, after giving effect to the $7.8 million of derivatives acquired in December 2010. In 2009, the fair value of our open derivatives decreased from a net asset of $144.7 million at December 31, 2008 to a net asset of $93.1 million at December 31, 2009.

 

Interest expense for 2010 decreased $1.9 million compared with 2009 due to a decrease of $2.6 million from lower weighted average borrowings outstanding under our credit facility offset by an increase of $0.7 million due to a higher weighted average effective interest rate in 2010 compared with 2009.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Historically, our primary sources of liquidity and capital have been issuances of equity and debt securities, borrowings under our credit facility and cash flows from operations. Our primary uses of cash have been acquisitions of oil and natural gas properties and related assets, development of our oil and natural gas properties, distributions to our partners and working capital needs. For 2012, we believe that cash on hand and net cash flows generated from operations will be adequate to fund our capital budget and satisfy our short–term liquidity needs. We may also utilize borrowings under our credit facility and various financing sources available to us, including the issuance of equity or debt securities through public offerings or private placements, to fund our acquisitions and long–term liquidity needs. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

 

In the past we accessed the equity and debt markets to finance our significant acquisitions. While we have been successful in accessing the public equity and debt markets earlier this year and the public equity markets in prior years, any disruptions in the financial markets may limit our ability to access the public equity or debt markets in the future.

 

Long–term Debt

 

As of December 31, 2011, we have a $1.0 billion credit facility that expires in April 2016. Borrowings under the facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves. As of December 31, 2011, the borrowing base was $800.0 million, and we had $660.0 million outstanding. As of February 17, 2012, indebtedness outstanding under our facility was $420.0 million.

 

In March 2011, we issued $300.0 million in aggregate principal amount of 8.0% senior notes due 2019 and received net proceeds of approximately $291.5 million.  We used the net proceeds to repay indebtedness outstanding under our credit facility. These notes are recorded on our consolidated balance sheet as $293.0 million, which is net of the unamortized discount of $7.0 million.

 

For additional information about our long–term debt, such as interest rates and covenants, please see “Item 8. Financial Statements and Supplementary Data” contained herein.  

 

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Cash and Cash Equivalents

 

At December 31, 2011, we had $30.3 million of cash and cash equivalents, which included $24.1 million of short–term investments.  With regard to our short–term investments, we invest in money market accounts with major financial institutions.  

 

Counterparty Exposure

 

At December 31, 2011, our open derivative contracts were in a net receivable position with a fair value of $138.8 million. All of our derivative contracts are with major financial institutions who are also lenders under our credit facility.  Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative contracts and we could incur a loss. As of December 31, 2011, all of our counterparties have performed pursuant to their derivative contracts.

 

Cash Flows

 

Cash flows provided (used) by type of activity were as follows for the years ended December 31:

 

  2011  2010  2009 
Operating activities $167,212  $122,353  $109,525 
Investing activities  (518,962)  (550,559)  (53,917)
Financing activities  358,935   432,527   (78,430)

 

Operating Activities

 

Cash flows from operating activities were $167.2 million and $122.4 million in 2011 and 2010, respectively. The increase was primarily due to higher production and prices for oil and natural gas liquids and increased realized gains on derivatives, partially offset by lower natural gas prices, higher operating expenses and interest expense.

 

Cash flows from operating activities provided $122.4 million and $109.5 million in 2010 and 2009, respectively. The increase was primarily due to higher production and prices for oil, natural gas and natural gas liquids, partially offset by lower realized gains on derivatives and higher operating expenses.

 

Investing Activities

 

Our principal recurring investing activity is the acquisition and development of oil and natural gas properties. During 2011, we spent $463.6 million for the acquisition of oil and natural gas properties and $75.9 million for development of our oil and natural gas properties. In addition, we received $6.6 million from settlements of derivatives acquired in our December 2010 acquisition of oil and natural gas properties and $14.0 million in proceeds from the sales of oil and natural gas properties.

 

During 2010, we spent $568.4 million on the acquisitions of oil and natural gas properties and $26.5 million for the development of our oil and natural gas properties. In addition, we received $44.4 million for the sales of oil and natural gas properties.

 

During 2009, we spent $39.6 million on acquisitions of oil and natural gas properties and $14.3 million for the development of our oil and natural gas properties.

 

Financing Activities

 

During 2011, we received net proceeds of $146.8 million from our public equity offering in March 2011, and we received contributions of $3.2 million from our general partner in order to maintain its 2% interest in us. We also received net proceeds of $291.5 million from our debt offering in March 2011, after deducting offering expenses of $1.0 million. We used the proceeds from these offerings and cash flows from operations to repay $436.5 million of borrowings outstanding under our credit facility. In addition, we borrowed $477.5 million under our credit facility to finance our acquisitions, paid distributions of $115.1 million to holders of our common units and our general partner and paid $6.7 million in loan costs related to our new $1.0 billion credit facility.

 

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During 2010, we received net proceeds of $204.7 million from our public equity offerings in February 2010 and August 2010, and we received contributions of $4.3 million from our general partner in order to maintain its 2% interest in us. We borrowed $543.0 million under our credit facility to finance our acquisitions of oil and natural gas properties and we repaid $226.0 million of borrowings outstanding under our credit facility with proceeds from our public equity offerings and cash flows from operations. In addition, we paid distributions of $92.9 million to holders of our common units and our general partner.

 

During 2009, we received net proceeds of $148.6 million from our public equity offerings in June 2009 and September 2009, and we received contributions of $3.1 million from our general partner in order to maintain its 2% interest in us. We borrowed $20.0 million under our credit facility to finance our acquisition of oil and natural gas properties in November 2009 and we repaid $185.0 million of borrowings outstanding under our credit facility with proceeds from our public equity offerings and cash flows from operations. In addition, we paid distributions of $65.0 million to holders of our common and subordinated units and our general partner.

 

Capital Requirements

 

In 2012, we currently expect spending for the development of our oil and natural gas properties to be between $140.0 million and $180.0 million. We also currently expect to make distributions of approximately $32.9 million per quarter to holders of our common and Class B units and general partner based on our current quarterly distribution rate of $0.763 per unit outstanding and our common and Class B units outstanding as of February 17, 2012. We expect to fund these amounts with cash on hand and net cash flows generated from operations.

 

We are actively engaged in the acquisition of oil and natural gas properties. We would expect to finance any significant acquisition of oil and natural gas properties in 2012 through the issuance of equity or debt securities.

 

Contractual Obligations

 

In the table below, we set forth our contractual cash obligations as of December 31, 2011. Some of the figures we include in this table are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors. The contractual cash obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective. Amounts in the table represent obligations where both the timing and amount of payment streams are known.

 

  Payments Due by Period (amounts in thousands) 
  Total  Less Than
1 Year
  1 – 3
Years
  4 – 5
Years
  After 5
Years
 
Total debt $960,000  $  $  $660,000  $300,000 
Estimated interest payments (1)  251,648   41,688   83,376   71,584   55,000 
Purchase obligation (2)  13,100   13,100          
Total $1,224,748  $54,788  $83,376  $731,584  $355,000 

 

 

(1)Amounts represent the expected cash payments for interest based on (i) the amount outstanding under our credit facility as of December 31, 2011 and the weighted average interest rate for 2011 of 2.68%, and (ii) our $300.0 million in aggregate principal amount of 8.0% senior notes due 2019. Such amounts do not include the effects of our interest rate swaps.

 

(2)Amounts represent payments to be made under our omnibus agreement with EnerVest based on the amount that we pay as of December 31, 2011. This amount will increase or decrease as we purchase or divest assets. While these payments will continue for periods subsequent to December 31, 2012, no amounts are shown as they cannot be quantified.

 

Our asset retirement obligations are not included in the table above given the uncertainty regarding the actual timing of such expenditures. The total amount of our asset retirement obligations at December 31, 2011 is $93.2 million.

 

Off–Balance Sheet Arrangements

 

As of December 31, 2011, we had no off–balance sheet arrangements.

 

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RECENT ACCOUNTING STANDARDS

 

Please see “Item 8. Financial Statements and supplementary Data”” contained herein for additional information.

 

FORWARD–LOOKING STATEMENTS

 

This Form 10–K contains forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act (each a “forward–looking statement”). These forward–looking statements relate to, among other things, the following:

 

·our future financial and operating performance and results;

 

·our business strategy and plans, including the Utica Shale;

 

·our estimated net proved reserves, PV–10 value and standardized measure;

 

·market prices;

 

·our future derivative activities; and

 

·our plans and forecasts.

 

We have based these forward–looking statements on our current assumptions, expectations and projections about future events.

 

The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward–looking statements. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward–looking” information. We do not undertake any obligation to update or revise publicly any forward–looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Form 10–K including, but not limited to:

 

·fluctuations in prices of oil and natural gas;

 

·significant disruptions in the financial markets;

 

·future capital requirements and availability of financing;

 

·uncertainty inherent in estimating our reserves;

 

·risks associated with drilling and operating wells;

 

·discovery, acquisition, development and replacement of oil and natural gas reserves;

 

·cash flows and liquidity;

 

·timing and amount of future production of oil and natural gas;

 

·availability of drilling and production equipment;

 

·marketing of oil and natural gas;

 

·developments in oil and natural gas producing countries;

 

·competition;

 

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·general economic conditions;

 

·governmental regulations;

 

·receipt of amounts owed to us by purchasers of our production and counterparties to our derivative financial instrument contracts;

 

·hedging decisions, including whether or not to enter into derivative financial instruments;

 

·events similar to those of September 11, 2001;

 

·actions of third party co–owners of interest in properties in which we also own an interest;

 

·fluctuations in interest rates and the value of the U.S. dollar in international currency markets; and

 

·our ability to effectively integrate companies and properties that we acquire.

 

All of our forward–looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors” section included in Item 1A.

 

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flows, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. We may enter into derivatives to manage or reduce market risk, but do not enter into derivatives for speculative purposes.

 

We do not designate these or future derivatives as hedges for accounting purposes. Accordingly, the changes in the fair value of these derivatives are recognized currently in earnings.

 

Commodity Price Risk

 

Our major market risk exposure is to prices for oil, natural gas and natural gas liquids. These prices have historically been volatile. As such, future earnings are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional spot prices for natural gas production. We have used, and expect to continue to use, oil and natural gas commodity contracts to reduce our risk of changes in the prices of oil and natural gas. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with pre–existing or anticipated sales of oil and natural gas.

 

We have entered into commodity contracts to hedge significant amounts of our anticipated oil and natural gas production through December 2015. As of December 31, 2011, we have commodity contracts covering approximately 52% of our production attributable to our estimated net proved reserves through December 2015, as estimated in our reserve report prepared by third party engineers using prices, costs and other assumptions required by SEC rules. Subsequent to December 31, 2011, we entered into additional commodity contracts and now have commodity contracts covering approximately 57% of our production through 2015. Our actual production will vary from the amounts estimated in our reserve reports, perhaps materially. Please read the disclosures under “Our estimated oil and natural gas reserve quantities and future production rates 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” in the “Risk Factors” section included in Item 1A.

 

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The fair value of our oil and natural gas commodity contracts at December 31, 2011 was a net asset of $148.8 million. A 10% change in oil and natural gas prices with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts and basis swaps of approximately $66.7 million. Please see “Item 8. Financial Statements and Supplementary Data” contained herein for additional information.

 

Interest Rate Risk

 

Our floating rate credit facility and interest rate swaps also expose us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in these interest rates. If interest rates on our facility increased by 1%, interest expense for 2011 would have increased by approximately $3.2 million. The fair value of our interest rate swaps at December 31, 2011 was a net liability of $10.0 million. A 1% change in interest rates with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such interest rate swaps) of our interest rate swaps of approximately $4.0 million. Please see “Item 8. Financial Statements and supplementary Data” contained herein for additional information.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

 

Management, including our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining effective internal control over our financial reporting. Our internal control system was designed to provide reasonable assurance to our Management and Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that EV Energy Partners, L.P.’s internal control over financial reporting was effective as of December 31, 2011.

 

Deloitte & Touche LLP, our independent registered public accounting firm, has issued an attestation report on the effectiveness on our internal control over financial reporting as of December 31, 2011 which is included in ”Item 8. Financial Statements and Supplementary Data” contained herein.

 

/s/ MARK A. HOUSER   /s/ MICHAEL E. MERCER
Mark A. Houser   Michael E. Mercer
Chief Executive Officer of EV Management, LLC,   Chief Financial Officer of EV Management, LLC,
general partner of EV Energy, GP, L.P.,   general partner of EV Energy GP, L.P.,
general partner of EV Energy Partners, L.P.   general partner of EV Energy Partners, L.P.

 

Houston, TX
February 29, 2012

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors of EV Management, LLC

and Unitholders of EV Energy Partners, L.P. and Subsidiaries

Houston, Texas

 

We have audited the accompanying consolidated balance sheets of EV Energy Partners, L.P. and subsidiaries (the "Partnership") as of December 31, 2011 and 2010, and the related consolidated statements of operations, cash flows, and changes in owners’ equity of the Partnership for each of the three years in the period ended December 31, 2011. We also have audited the Partnership's internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting.  Our responsibility is to express an opinion on these financial statements and an opinion on the Partnership's internal control over financial reporting based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances.  We believe that our audits provide a reasonable basis for our opinions.

 

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

 

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

 

As discussed in Note 2 to the consolidated financial statements, the Partnership changed its method of accounting during 2009 for oil and natural gas reserves and disclosures.

 

/s/DELOITTE & TOUCHE LLP

Houston, Texas

February 29, 2012

 

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EV Energy Partners, L.P.

Consolidated Balance Sheets

(In thousands, except number of units)

 

   December 31, 
   2011   2010 
ASSETS          
           
Current assets:          
Cash and cash equivalents  $30,312   $23,127 
Accounts receivable:          
Oil, natural gas and natural gas liquids revenues   36,926    27,742 
Other   459    441 
Derivative asset   81,772    55,100 
Other current assets   3,084    1,158 
Assets held for sale   6,597     
Total current assets   159,150    107,568 
           
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization;          
   December 31, 2011, $244,092; December 31, 2010, $176,897   1,768,529    1,324,240 
Other property, net of accumulated depreciation and amortization; December 31, 2011, $447; December 31, 2010, $465   1,345    1,567 
Long–term derivative asset   57,643    51,497 
Other assets   16,557    1,885 
Total assets  $2,003,224   $1,486,757 
           
LIABILITIES AND OWNERS’ EQUITY          
           
Current liabilities:          
Accounts payable and accrued liabilities:          
Third party  $34,705   $20,678 
Related party   870    182 
Derivative liability   618    1,943 
Liabilities held for sale   602     
Total current liabilities   36,795    22,803 
           
Asset retirement obligations   90,803    67,175 
Long–term debt   953,023    619,000 
Other long–term liabilities   2,564    3,048 
Long–term derivative liability       784 
           
Commitments and contingencies          
           
Owners’ equity:          
Common unitholders – 34,173,650 units and 30,510,313 units issued and outstanding as of December 31, 2011 and 2010, respectively   935,425    779,327 
Class B unitholders – 3,873,357 units issued and outstanding as of December 31, 2011   232     
General partner interest   (15,618)   (5,380)
Total owners’ equity   920,039    773,947 
Total liabilities and owners’ equity  $2,003,224   $1,486,757 

  

See accompanying notes to consolidated financial statements.

 

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EV Energy Partners, L.P.

Consolidated Statements of Operations

(In thousands, except per unit data)

  

   Year Ended December 31, 
   2011   2010   2009 
Revenues:               
Oil, natural gas and natural gas liquids revenues  $256,370   $165,738   $114,066 
Transportation and marketing–related revenues   5,470    5,780    7,846 
Total revenues   261,840    171,518    121,912 
                
Operating costs and expenses:               
Lease operating expenses   74,419    53,736    41,495 
Cost of purchased natural gas   4,078    4,353    4,509 
Dry hole and exploration costs   12,140    417     
Production taxes   11,247    7,867    5,983 
Asset retirement obligations accretion expense   3,914    3,153    2,035 
Depreciation, depletion and amortization   74,723    55,221    52,048 
General and administrative expenses   34,968    23,313    18,556 
Impairment of oil and natural gas properties   11,037         
Gain on sales of oil and natural gas properties   (4,017)   (40,656)    
Total operating costs and expenses   222,509    107,404    124,626 
                
Operating income (loss)   39,331    64,114    (2,714)
                
Other income (expense), net:               
Realized gains on derivatives, net   58,402    49,042    68,984 
Unrealized gains (losses) on derivatives, net   35,505    2,994    (51,665)
Interest expense   (30,568)   (10,442)   (12,321)
Other income (expense), net   325    628    (626)
Total other income, net   63,664    42,222    4,372 
                
Income before income taxes   102,995    106,336    1,658 
                
Income taxes   (354)   (285)   (248)
                
Net income  $102,641   $106,051   $1,410 
General partner’s interest in net income, including incentive distribution rights  $10,886   $11,938   $7,040 
Limited partners’ interest in net income (loss)  $91,755   $94,113   $(5,630)
                
Net income (loss) per limited partner unit:               
Basic  $2.71   $3.35   $(0.29)
Diluted  $2.68   $3.34   $(0.29)
                
Weighted average limited partner units outstanding:               
Basic   33,895    28,095    19,302 
Diluted   34,183    28,162    19,302 

 

See accompanying notes to consolidated financial statements.

 

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EV Energy Partners, L.P.

Consolidated Statements of Cash Flows

(In thousands) 

 

   Year Ended December 31, 
   2011   2010   2009 
Cash flows from operating activities:               
Net income  $102,641   $106,051   $1,410 
Adjustments to reconcile net income to net cash flows provided by operating activities:               
Dry hole costs   9,220    170     
Asset retirement obligations accretion expense   3,914    3,153    2,035 
Depreciation, depletion and amortization   74,723    55,221    52,048 
Equity–based compensation   9,834    5,043    3,659 
Impairment of oil and natural gas properties   11,037         
Gain on sales of oil and natural gas properties   (4,017)   (40,656)    
Noncash derivative activity   (40,187)   (2,994)   51,665 
Amortization of discount on long–term debt   523         
Amortization of deferred loan costs   1,348    564    799 
Other   40    (169)   544 
Changes in operating assets and liabilities:               
Accounts receivable   (6,505)   (9,320)   3,955 
Other current assets   (342)   2,215    214 
Accounts payable and accrued liabilities   7,362    4,514    (2,126)
Deferred revenues           (4,120)
Long–term liabilities       (734)    
Other, net   (2,379)   (705)   (558)
Net cash flows provided by operating activities   167,212    122,353    109,525 
                
Cash flows from investing activities:               
Acquisitions of oil and natural gas properties   (463,624)   (568,433)   (39,646)
Additions to oil and natural gas properties   (75,913)   (26,525)   (14,271)
Proceeds from sales of oil and natural gas properties   14,012    44,399     
Settlements from acquired derivatives   6,563         
Net cash flows used in investing activities   (518,962)   (550,559)   (53,917)
                
Cash flows from financing activities:               
Long–term debt borrowings   477,500    543,000    20,000 
Repayments of long–term debt borrowings   (436,500)   (226,000)   (185,000)
Proceeds from debt offering   292,500         
Loan costs paid   (7,698)   (465)   (44)
Proceeds from public equity offerings   147,108    204,965    149,038 
Offering costs   (347)   (306)   (484)
Contributions from general partner   3,191    4,267    3,077 
Distributions paid   (115,101)   (92,934)   (65,017)
Distribution related to acquisition   (1,718)        
Net cash flows provided by (used in) financing activities   358,935    432,527    (78,430)
                
Increase (decrease) in cash and cash equivalents   7,185    4,321    (22,822)
Cash and cash equivalents – beginning of period   23,127    18,806    41,628 
Cash and cash equivalents – end of period  $30,312   $23,127   $18,806 

 

See accompanying notes to consolidated financial statements.

 

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EV Energy Partners, L.P.

Consolidated Statements of Changes in Owners’ Equity

(In thousands)

 

               General   Total 
   Common   Class B   Subordinated   Partner   Owners’ 
   Unitholders   Unitholders   Unitholders   Interest   Equity 
Balance, December 31, 2008  $432,031   $   $21,618   $3,835   $457,484 
Conversion of 103,409 vested phantom units   1,706                1,706 
Proceeds from public equity offerings, net of offering costs of $484   148,554                148,554 
Contributions from general partner               3,077    3,077 
Distributions   (48,016)       (9,331)   (7,670)   (65,017)
Equity–based compensation   217                217 
Conversion of subordinated units   13,176        (13,176)        
Net income   492        889    29    1,410 
Balance, December 31, 2009   548,160            (729)   547,431 
Conversion of 84,842 vested phantom units   2,580                2,580 
Proceeds from public equity offerings, net of offering costs of $306   204,659                204,659 
Contributions from general partner               4,267    4,267 
Distributions   (81,895)           (11,039)   (92,934)
Equity–based compensation   1,893                1,893 
Net income   103,930            2,121    106,051 
Balance, December 31, 2010   779,327            (5,380)   773,947 
Conversion of 80,534 vested phantom units   3,508                3,508 
Issuance of 3,873,357 Class B units                    
Proceeds from public equity offering, net of offering costs of $347   146,761                146,761 
Contributions from general partner               3,191    3,191 
Distributions   (101,337)           (13,764)   (115,101)
Distribution related to acquisition               (1,718)   (1,718)
Equity–based compensation   6,810                6,810 
Net income   100,356    232        2,053    102,641 
Balance, December 31, 2011  $935,425   $232   $   $(15,618)  $920,039 

 

See accompanying notes to consolidated financial statements.

 

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EV Energy Partners, L.P.

Notes to Consolidated Financial Statements

 

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS

 

EV Energy Partners, L.P. (the “Partnership”) is a publicly held limited partnership that engages in the acquisition, development and production of oil and natural gas properties. The Partnership’s general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited partnership, and the general partner of its general partner is EV Management, LLC (“EV Management”), a Delaware limited liability company. EV Management is a wholly owned subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited partnership. EnerVest and its affiliates also have a significant interest in the Partnership through their 71.25% ownership of EV Energy GP which, in turn, owns a 2% general partner interest in the Partnership and all of its incentive distribution rights.

 

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Presentation

 

The consolidated financial statements include the operations of the Partnership and all of its wholly–owned subsidiaries (“we,” “our” or “us”). All intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Consolidated Financial Statements, all dollar and share amounts in tabulations are in thousands of dollars and shares, respectively, unless otherwise indicated.

 

Use of Estimates

 

 The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

 

Cash and Cash Equivalents

 

We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents. All of our cash and cash equivalents are maintained with several major financial institutions in the United States. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk.

 

Accounts Receivable

 

Accounts receivable from oil, natural gas and natural gas liquids sales are recorded at the invoiced amount and do not bear interest. We routinely assess the financial strength of our customers and bad debts are recorded based on an account–by–account review after all means of collection have been exhausted, and the potential recovery is considered remote.

 

As of December 31, 2011 and 2010, we did not have any reserves for doubtful accounts, and we did not incur any expense related to bad debts. We do not have any off–balance sheet credit exposure related to our customers.

 

Property and Depreciation

 

Our oil and natural gas producing activities are accounted for under the successful efforts method of accounting. Under this method, exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Lease acquisition costs are capitalized when incurred. Capitalized costs associated with unproved properties totaled $53.7 million and $7.3 million as of December 31, 2011 and December 31, 2010, respectively. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs and costs of certain non–producing leasehold costs are expensed as incurred. For the years ended December 31, 2011 and 2010, we recorded dry hole and exploration costs of $12.1 and $0.4 million, respectively. We recorded no dry hole and exploration costs in the year ended December 31, 2009.

 

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EV Energy Partners, L.P.

Notes to Consolidated Financial Statements (continued)

  

No gains or losses are recognized upon the disposition of oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

 

The capitalized costs of our producing oil and natural gas properties are depreciated and depleted by the units–of–production method based on the ratio of current production to estimated total net proved oil and natural gas reserves as estimated by independent petroleum engineers. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold, platform, and pipeline costs.

 

Other property is stated at cost less accumulated depreciation, which is computed using the straight–line method based on estimated economic lives ranging from three to 25 years. We expense costs for maintenance and repairs in the period incurred. Significant improvements and betterments are capitalized if they extend the useful life of the asset.

 

Impairment of Long–Lived Assets

 

We evaluate our proved oil and natural gas properties and related equipment and facilities for impairment whenever events or changes in circumstances indicate that the carrying amounts of such properties may not be recoverable. The determination of recoverability is made based upon estimated undiscounted future net cash flows. The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related asset. For the year ended December 31, 2011, we recorded impairment charges of $10.4 million related to proved oil and natural gas properties as the carrying amounts of such properties were determined not to be recoverable (see Note 7). For the years ended December 31, 2010 and 2009, we recorded no impairment charges related to proved oil and natural gas properties as the carrying amounts of such properties were determined to be recoverable.

 

Unproved oil and natural gas properties are assessed periodically on a property–by–property basis, and any impairment in value is recognized. For the year ended December 31, 2011, we recorded leasehold impairment charges of $0.6 million related to unproved oil and natural gas properties. For the years ended December 31, 2010 and 2009, we recorded no impairment charges related to unproved oil and natural gas properties.

 

Asset Retirement Obligations

 

An asset retirement obligation (“ARO”) represents the future abandonment costs of tangible assets, such as platforms, wells, service assets, pipelines, and other facilities. We record an ARO and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis. If the ARO is settled for an amount other than the recorded amount, a gain or loss is recognized.

 

Revenue Recognition

 

Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production. There were no significant gas imbalances at December 31, 2011 or 2010.

 

We own and operate a network of natural gas gathering systems in the Monroe field in Northern Louisiana which gather and transport owned natural gas and a small amount of third party natural gas to intrastate, interstate and local distribution pipelines. Natural gas gathering and transportation revenue is recognized when the natural gas has been delivered to a custody transfer point.

 

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EV Energy Partners, L.P.

Notes to Consolidated Financial Statements (continued)

 

Income Taxes

 

We are a partnership that is not taxable for federal income tax purposes. As such, we do not directly pay federal income tax. As appropriate, our taxable income or loss is includable in the federal income tax returns of our partners. Since we do not have access to information regarding each partner’s tax basis, we cannot readily determine the total difference in the basis of our net assets for financial and tax reporting purposes.

 

We record our obligations under the Texas gross margin tax as “Income taxes” in our consolidated statement of operations.

 

Net Income per Limited Partner Unit

 

Our partnership agreement contains incentive distribution rights. Accordingly, net income used in the determination of net income per limited partner unit for the current reporting period is to be reduced by the amount of available cash that will be distributed to the limited partners, the general partner and the holders of the incentive distribution rights for that reporting period. The undistributed earnings, if any, are then allocated to the limited partners, the general partner and the holders of the incentive distribution rights in accordance with the terms of the partnership agreement. Our partnership agreement does not allow for the distribution of undistributed earnings to the holders of the incentive distribution rights, as it limits distributions to the holders of the incentive distribution rights to available cash as defined in the partnership agreement. Basic and diluted net income per limited partner unit is determined by dividing net income, after deducting the amount allocated to the general partner and the holders of the incentive distribution rights, by the weighted average number of outstanding limited partner units during the period.

 

Derivatives

 

We monitor our exposure to various business risks, including commodity price and interest rate risks, and use derivatives to manage the impact of certain of these risks. Our policies do not permit the use of derivatives for speculative purposes. We use energy derivatives for the purpose of mitigating risk resulting from fluctuations in the market price of oil and natural gas.

 

We have elected not to designate our derivatives as hedging instruments. Changes in the fair value of derivatives are recorded immediately to net income as “Unrealized gains (losses) on derivatives, net” in our consolidated statements of operations.

 

The counterparties to our derivatives are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis.

 

Business Segment Reporting

 

We operate in one reportable segment engaged in the exploration, development and production of oil and natural gas properties and all of our operations are located in the United States.

 

Concentration of Credit Risk

 

Our oil, natural gas and natural gas liquids revenues are derived principally from uncollateralized sales to numerous companies in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry. We have experienced no significant credit losses on such sales in the past.

 

In 2011, 2010 and 2009, no customer accounted for greater than 10% of our consolidated oil, natural gas and natural gas liquids revenues. We believe that the loss of a major customer would have a temporary effect on our revenues but that over time, we would be able to replace our major customers.

 

Recent Accounting Standards

 

In January 2010, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2010–03, Extractive Activities – Oil and Gas (Topic 932), to align the oil and natural gas reserve estimation and disclosure requirements of Topic 932 with the Securities and Exchange Commission’s final rule, Modernization of Oil and Gas Reporting. ASU No. 2010–03 was effective for annual reporting periods ending on or after December 31, 2009. We adopted the provisions of ASU 2010–03 in our consolidated financial statements beginning in the year ended December 31, 2009 (see Notes 17 and 18).

 

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EV Energy Partners, L.P.

Notes to Consolidated Financial Statements (continued)

 

In May 2011, the FASB issued ASU No. 2011–04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. This ASU represents the converged guidance of the FASB and the International Accounting Standards Board on fair value measurement, and has resulted in common requirements for measuring fair value and for disclosing information about fair value measurements, including a consistent meaning of the term “fair value.” The provisions of ASU 2011–04 are applicable to interim and annual reporting periods subsequent to December 15, 2011. The adoption of ASU 2011–04 did not impact our operating results, financial position or cash flows, but did impact our disclosures on fair value measurements (see Note 7).

 

In December 2011, the FASB issued ASU No. 2011–11, Disclosures about Offsetting Assets and Liabilities. This ASU affect all entities that have financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement. ASU 2011–11 requires an entity to disclose information about offsetting and related arrangements to enable user of its financial statements to understand the effect of those arrangements on its financial position. The provisions of ASU 2011–11 are applicable to annual reporting periods beginning on or after January 1, 2011 and interim periods within those annual periods. We have not yet determined the impact of this ASU on our consolidated financial statements.

 

No other new accounting pronouncements issued or effective during the year ended December 31, 2011 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.

 

NOTE 3. EQUITY–BASED COMPENSATION

 

EV Management has a long–term incentive plan (the “Plan”) for employees, consultants and directors of EV Management and its affiliates who perform services for us. The Plan, as amended, allows for the award of unit options, phantom units, performance units, restricted units and deferred equity rights. As of December 31, 2011, the aggregate amount of our common units that may be awarded under the plan was 4.5 million units. Unless earlier terminated by us or unless all units available under the Plan have been paid to participants, the Plan will terminate as of the close of business on September 20, 2016. The compensation committee of the board of directors administers the Plan.

 

Phantom Units

 

Liability Awards

 

We account for the phantom units issued prior to 2009 as liability awards due to the Plan’s provision allowing us, at our discretion, to settle the award in either cash or common units and the presumption that some or all of these awards would be settled in cash. The fair value of these phantom units is remeasured at the end of each reporting period based on the current market price of our common units until settlement. Prior to settlement, compensation cost is recognized for these phantom units based on the proportionate amount of the requisite service period that has been rendered to date and is net of estimated forfeitures. These phantom units are subject to graded vesting over a three to four year period.

 

Activity related to these phantom units is as follows:

 

Nonvested phantom units as of December 31, 2010   164,434 
Vested   (80,534)
Forfeited   (2,000)
Nonvested phantom units as of December 31, 2011   81,900 

 

The total fair value of the phantom units vested in the years ended December 31, 2011, 2010 and 2009 was $3.5 million, $3.3 million and $1.7 million, respectively.

 

We recognized compensation cost related to these phantom units of $3.0 million, $3.1 million and $3.4 million in the years ended December 31, 2011, 2010 and 2009, respectively. These costs are included in “General and administrative expenses” in our consolidated statements of operations.

 

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EV Energy Partners, L.P.

Notes to Consolidated Financial Statements (continued)

 

As of December 31, 2011, there was $2.8 million of total unrecognized compensation cost related to these unvested phantom units which is expected to be recognized over a weighted average period of 1.0 year.

 

Equity Awards

 

We account for the phantom units issued beginning in 2009 as equity awards since we have determined that these awards will likely be settled by issuing common units. Compensation cost is recognized for these phantom units on a straight–line basis over the service period and is net of estimated forfeitures. These phantom units are subject to graded vesting over a four year period.

 

We estimated the fair value of these phantom units using the Black–Scholes option pricing model. The following assumptions were used to estimate the weighted average fair value of these phantom units for the years ended December 31:

 

   2011   2010   2009 
Weighted average fair value of phantom units  $63.87   $37.15   $28.68 
Expected volatility   36.803%   48.042%   57.016%
Risk–free interest rate   0.40%   1.05%   1.16%
Dividend yield   0.0%   0.0%   0.0%
Expected life (years)   4.0    4.0    4.1 

 

We calculated estimated volatility using historical daily prices for two years prior to the grant date. The risk–free interest rate was based on U.S. Treasury yield curves. The dividend yield is not taken into account as recipients are entitled to receive all distributions underlying the phantom units.

 

Activity related to these phantom units is as follows:

 

       Weighted 
       Average 
      Grant Date 
   Number of   Fair Value 
   Phantom   per Phantom 
    Units   Unit 
Nonvested phantom units as of December 31, 2010   580,700   $33.95 
Granted   240,045    63.87 
Vested   (70,610)   29.64 
Forfeited   (11,450)   34.22 
Nonvested phantom units as of December 31, 2011   738,685   $44.07 

 

The total grant date fair value of the phantom units vested in the year ended December 31, 2011 was $2.1 million.

 

We recognized compensation cost related to these phantom units of $4.9 million, $1.7 million and $0.1 million in the years ended December 31, 2011, 2010 and 2009. These costs are included in “General and administrative expenses” in our consolidated statements of operations.

 

As of December 31, 2011, there was $27.0 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 3.4 years.

 

Performance Units

 

In September 2011, we issued 0.3 million performance units to certain employees and executive officers of EV Management and its affiliates. These performance units vest 25% each year beginning in January 2012 subject to our common units achieving certain market prices. We accounted for the performance units as equity awards. We estimated the fair value of 0.1 million of the performance units using the Black–Scholes option pricing model, as the market price had already been achieved for those performance units. We estimated the fair value of the remainder of the performance units using the Monte Carlo simulation model.

 

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EV Energy Partners, L.P.

Notes to Consolidated Financial Statements (continued)

 

In March 2009, we issued 0.3 million performance units to certain employees and executive officers of EV Management and its affiliates. These performance units vest 25% each year beginning in January 2010 subject to our common units achieving certain market prices. As of December 31, 2011, the performance criterion has been achieved with respect to all of these performance units. We accounted for these performance units as equity awards, and we estimated the fair value of these performance units using the Monte Carlo simulation model.

 

The following assumptions were used to estimate the weighted average fair value of the performance units:

 

   2011   2009 
Weighted average fair value of performance units  $64.07   $2.37 
Expected volatility   47.987%   56.725%
Risk–free interest rate   0.56%   1.911%
Expected quarterly distribution amount  $0.762   $0.751 
Expected life (years)   2.69    2.85 

 

We calculated estimated volatility using historical daily prices for five years prior to the grant date. The risk–free interest rate was based on U.S. Treasury yield curves. The dividend yield is not taken into account as recipients are entitled to receive all distributions underlying the phantom units. The fair value of the performance units issued in 2011 assumes that the expected quarterly distribution amount will increase by $0.001 over the term of the performance units. The fair value of the performance units issued in 2009 assumes that the expected quarterly distribution amount will increase at a 3% annual compound growth rate over the five year term of the performance units.

 

Activity related to these performance units is as follows:

 

       Weighted 
       Average 
       Grant Date 
   Number of   Fair Value 
   Phantom   per Phantom 
   Units   Unit 
Nonvested performance units as of December 31, 2010   200,000   $2.37 
Granted   285,000    64.07 
Vested   (80,000)   2.37 
Nonvested performance units as of December 31, 2011   405,000   $45.79 

 

The total grant date fair value of the performance units vested in the years ended December 31, 2011 and 2010 was $0.2 million and $0.1 million, respectively.

 

We recognized compensation cost related to our performance units of $2.0 million, $0.1 million and $0.1 million in the years ended December 31, 2011, 2010 and 2009. These costs are included in “General and administrative expenses” in our consolidated statements of operations.

 

As of December 31, 2011, there was $16.6 million of total unrecognized compensation cost related to unvested performance units which is expected to be recognized over a weighted average period of 3.0 years.

 

NOTE 4. ACQUISITIONS

 

2011

 

On November 1, 2011, we acquired oil and natural gas properties in the Mid–Continent area for $74.3 million, subject to customary purchase price adjustments. We recognized $1.8 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations for the year ended December 31, 2011.

 

On December 1, 2011, we, along with certain institutional partnerships managed by EnerVest, acquired oil and natural gas properties in the Barnett Shale. We acquired a 31.02% proportional interest in these properties for $75.7 million, subject to customary purchase price adjustments. We recognized $1.7 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations for the year ended December 31, 2011.

 

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EV Energy Partners, L.P.

Notes to Consolidated Financial Statements (continued)

  

On December 20, 2011, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Barnett Shale. We acquired a 31.63% proportional interest in these properties for $271.4 million, subject to customary purchase price adjustments. We recognized $2.2 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations for the year ended December 31, 2011.

 

The following table reflects pro forma revenues, net income and net income per limited partner unit for the years ended December 31 as if these acquisitions had taken place on January 1, 2010. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future.

 

   2011   2010 
Revenues  $350,229   $256,242 
Net income   140,409    119,498 
           
Net income per limited partner unit:          
Basic  $3.80   $3.82 
Diluted  $3.77   $3.81 

 

In addition to the acquisitions described above, we also made the following smaller acquisitions:

 

·we received final purchase price settlements totaling $4.1 million related to our September 2010 and December 2010 acquisitions of oil and natural gas properties in the Mid–Continent area and the Barnett Shale;

 

·we, along with certain institutional partnerships managed by EnerVest, acquired a proportional 31.02% interest in oil and natural gas properties in Barnett Shale for an aggregate purchase price of $17.3 million; and

 

·we acquired oil and natural gas properties in the Appalachian Basin from certain institutional partnerships managed by EnerVest for $31.1 million, subject to customary purchase price adjustments.

 

As we acquired the oil and natural gas properties in the Appalachian Basin from certain institutional partnerships managed by EnerVest, we carried over the historical costs related to EnerVest’s interests and applied purchase accounting to the remaining interests acquired. As a result, we recorded a deemed distribution of $1.7 million that represents the difference between the recognized fair values of the identifiable assets acquired and liabilities assumed and the amount paid for the acquisition.

 

The recognized fair values of the identifiable assets acquired and liabilities assumed in connection with all of these acquisitions are as follows:

 

Accounts receivable  $2,698 
Other current assets   1,584 
Proved oil and natural gas properties   428,478 
Unproved oil and natural gas properties   43,947 
Other property   12 
Other assets   7,706 
Accounts payable and accrued liabilities   (523)
Asset retirement obligations   (19,855)
   $464,047 

 

The amounts included in the table above for the November 2011 acquisition and the December 2011 acquisitions represent preliminary estimates of the fair values of the identifiable assets acquired and liabilities assumed for these acquisitions. We expect to finalize these fair values in the first quarter of 2012.

 

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EV Energy Partners, L.P.

Notes to Consolidated Financial Statements (continued)

  

2010

 

On March 30, 2010 followed by a second closing on June 29, 2010, we, along with certain institutional partnerships managed by EnerVest, acquired oil and natural gas properties in the Appalachian Basin. We acquired a 46.15% proportional interest in these properties for $145.8 million.

 

On September 29, 2010, we acquired oil and natural gas properties in the Mid–Continent area for $119.9 million, subject to customary closing conditions and purchase price adjustments.

 

On December 30, 2010, we, along with certain institutional partnerships managed by EnerVest, acquired oil and natural gas properties in the Barnett Shale, including certain related derivatives. We acquired a 31.02% proportional interest in these properties for $295.8 million, subject to customary closing conditions and purchase price adjustments.

 

In addition to the acquisitions described above, in 2010, we, along with certain institutional partnerships managed by EnerVest, acquired oil and natural gas properties in the Appalachian Basin, the San Juan Basin and Central and East Texas for an aggregate purchase price of $7.0 million.

 

The recognized fair values of the identifiable assets acquired and liabilities assumed in connection with these acquisitions are as follows:

 

Accounts receivable  $136 
Derivative asset   5,397 
Other current assets   2,748 
Oil and natural gas properties   579,609 
Other property   1,036 
Long–term derivative asset   2,638 
Accounts payable and accrued liabilities   (79)
Derivative liability   (139)
Asset retirement obligations   (22,831)
Long–term derivative liability   (82)
   $568,433 

 

NOTE 5. DIVESTITURES

 

In December 2011, we entered into a Purchase and Sale Agreement and a Development Agreement with Total E&P USA, Inc. (“Total”), a subsidiary of Total S.A., and Chesapeake Energy Corporation (“Chesapeake”), whereby Total acquired an undivided 25% interest in approximately 619,000 net acres in the Utica Shale and agreed to fund certain future development costs.  Of this acreage, approximately 542,000 net acres were sold by Chesapeake, approximately 73,250 net acres were sold by institutional partnerships managed by EnerVest and approximately 3,750 net acres were sold by us.  We received $4.2 million in cash for our acres.  We continue to own working interests in these acres.  Our portion of future development costs to be carried by Total is $9.9 million, which we anticipate receiving by the end of 2014.  We also contributed $0.5 million for a 9% interest in an entity that will own the midstream infrastructure related to production primarily generated from the assets.

 

In 2011, we sold oil and natural gas properties in the Mid–Continent and Central and East Texas areas for $9.8 million.

 

In 2010, we sold 14 non–core oil and natural gas wells and unproved oil and natural gas properties for $44.4 million and recorded gains of $40.7 million.

 

NOTE 6. RISK MANAGEMENT

 

Our business activities expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids. In addition, our floating rate credit facility exposes us to risks associated with changes in interest rates. As such, future earnings are subject to fluctuation due to changes in both the market price of oil, natural gas and natural gas liquids and interest rates. We use derivatives to reduce our risk of changes in the prices of oil and natural gas and interest rates. Our policies do not permit the use of derivatives for speculative purposes.

 

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EV Energy Partners, L.P.

Notes to Consolidated Financial Statements (continued)

  

We have elected not to designate any of our derivatives as hedging instruments. Accordingly, changes in the fair value of our derivatives are recorded immediately to net income as “Unrealized gains (losses) on derivatives, net” in our consolidated statements of operations.

 

As of December 31, 2011, we had entered into oil commodity contracts with the following terms:

 

       Weighted   Weighted   Weighted 
   Hedged   Average   Average   Average 
   Volume   Fixed   Floor   Ceiling 
Period Covered  (MBbls)   Price   Price   Price 
Swaps – 2012   876.4   $94.88   $   $ 
Collars – 2012   456.8         104.54    156.77 
Swaps – 2013   1,350.3    87.82           
Swaps – 2014   1,152.7    91.35           

 

As of December 31, 2011, we had entered into natural gas commodity contracts with the following terms:

 

       Weighted   Weighted   Weighted 
   Hedged   Average   Average   Average 
   Volume   Fixed   Floor   Ceiling 
Period Covered  (MmmBtus)   Price   Price   Price 
Swaps – 2012   26,019.6   $5.32   $   $ 
Collars – 2012   6,618.7         7.94    9.90 
Swaps – 2013   32,229.5    5.07           
Swaps – 2014   15,184.0    5.73           
Swaps – 2015   15,147.5    5.97           

 

As of December 31, 2011, we had entered into natural gas liquids commodity contracts with the following terms:

 

   Hedged   Weighted 
   Volume   Average 
Period Covered  (MBbls)   Fixed Price 
Ethane (MBbls):          
Swaps – 2012   732.0   $29.18 
Propane (MBbls):          
Swap – 2012   366.0    53.97 

 

As of December 31, 2011, we had also entered into interest rate swaps with the following terms:

 

   Notional   Floating   Fixed 
Period Covered  Amount   Rate   Rate 
January 2012 – July 2012  $90,000   1 Month LIBOR    4.157%
January 2012 – September 2012   40,000   1 Month LIBOR    2.145%
July 2012 – July 2015   110,000   1 Month LIBOR    3.315%
                

 

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EV Energy Partners, L.P.

Notes to Consolidated Financial Statements (continued)

  

The fair value of these derivatives was as follows as of December 31:

 

   Asset Derivatives   Liability Derivatives 
   2011   2010   2011   2010 
Commodity contracts  $152,506   $123,655   $3,699   $7,633 
Interest rate swaps           10,010    12,152 
Total fair value   152,506    123,655    13,709    19,785 
Netting arrangements   (13,091)   (17,058)   (13,091)   (17,058)
Net recorded fair value  $139,415   $106,597   $618   $2,727 
                     
Location of derivatives in our consolidated balance sheets:                    
Derivative asset  $81,772   $55,100   $   $ 
Long–term derivative asset   57,643    51,497         
Derivative liability           618    1,943 
Long–term derivative liability               784 
   $139,415   $106,597   $618   $2,727 

 

The following table presents the impact of derivatives and their location within the consolidated statements of operations for the years ended December 31:

 

   2011   2010   2009 
Realized gains on derivatives, net:               
Commodity contracts (1)  $59,891   $57,694   $77,335 
Interest rate swaps (2)   (1,489)   (8,652)   (8,351)
Total  $58,402   $49,042   $68,984 
                
Unrealized gains (losses) on derivatives, net:               
Commodity contracts  $38,045   $3,081   $(55,580)
Interest rate swaps (2)   (2,540)   (87)   3,915 
Total  $35,505   $2,994   $(51,665)

 


(1)Realized gains for the year ended December 31, 2011 exclude $5.3 million related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives.

 

(2)In June 2011, we terminated three of our interest rate swaps and reclassified the $4.7 million non–cash gain from “Unrealized gains (losses) on derivatives, net” to “Realized gains on derivatives, net.”

 

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EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

NOTE 7. FAIR VALUE MEASUREMENTS

 

Recurring Basis

 

The following table presents the fair value hierarchy table for our net assets and liabilities that are required to be measured at fair value:

 

       Fair Value Measurements at the End of the     
       Reporting Period     
       Quoted             
       Prices in             
       Active   Significant         
       Markets for   Other   Significant     
       Identical   Observable   Unobservable     
   December 31,   Assets   Inputs   Inputs   Total 
   2011   (Level 1)   (Level 2)   (Level 3)   Losses 
Recurring basis:                         
Assets:                         
Commodity contracts  $152,506   $   $152,506   $      
                          
Liabilities:                         
Commodity contracts  $3,699       $3,699   $      
Interest rate swaps   10,010        10,010          
   $13,709   $   $13,709   $      
                          
Nonrecurring basis:                         
Assets:                         
Long–lived assets held for sale  $15,784   $   $15,784   $   $10,399 

 

Our derivatives consist of over–the–counter (“OTC”) contracts which are not traded on a public exchange. These derivatives are indexed to active trading hubs for the underlying commodity, and are OTC contracts commonly used in the energy industry and offered by a number of financial institutions and large energy companies.

 

As the fair value of these derivatives is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third party pricing services, brokers and market transactions, we have categorized these derivatives as Level 2. We value these derivatives based on observable market data for similar instruments. This observable data includes the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap data. Our estimates of fair value have been determined at discrete points in time based on relevant market data. There were no changes in valuation techniques or related inputs in the year ended December 31, 2011.

 

Nonrecurring Basis

 

Long–lived Assets Held for Sale

 

At various times during 2011, oil and natural gas properties with an aggregate carrying amount of $26.2 million were written down to their aggregate fair value of $15.8 million, resulting in impairment charges of $10.4 million. These impairment charges were included in earnings for the year ended December 31, 2011. The fair values were determined based on the mutually agreed upon selling prices we received (see Note 5), or are to receive. upon the sale of these oil and natural gas properties.

 

As of December 31, 2011, we have $6.6 million of oil and natural gas properties and $0.6 million of asset retirement obligations classified as assets held for sale and liabilities held for sale, respectively.

 

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EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

Financial Instruments

 

The estimated fair values of our financial instruments have been determined at discrete points in time based on relevant market information. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, derivatives and long–term debt. The carrying amounts of our financial instruments other than derivatives and long–term debt approximate fair value because of the short–term nature of the items. Derivatives are recorded at fair value (see above).

 

The carrying value of debt outstanding under our credit facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us. As of December 31, 2011, the estimated fair value of our senior notes due 2019 was $306.8 million, which differs from the carrying value of $293.0 million. The fair value of our senior notes due 2019 was estimated using quoted market prices based on trades of such debt as of December 31, 2011. As the fair value of the senior notes due 2019 was based on inputs using quoted market prices for similar trades of such debt obtained from independent brokers, we have categorized the senior notes due 2019 as Level 2.

 

NOTE 8. ASSET RETIREMENT OBLIGATIONS

 

The changes in the aggregate ARO are as follows:

 

Balance as of December 31, 2009  $43,688 
Liabilities incurred and assumed in acquisitions   23,488 
Accretion expense   3,153 
Revisions in estimated cash flows   (902)
Settlements and divestitures   (997)
Balance as of December 31, 2010   68,430 
Liabilities incurred and assumed in acquisitions   20,664 
Accretion expense   3,914 
Revisions in estimated cash flows   5,795 
Reclass to liabilities held for sale   (602)
Settlements and divestitures   (4,976)
Balance as of December 31, 2011  $93,225 

 

As of December 31, 2011 and 2010, $2.4 million and $1.3 million, respectively, of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” on our consolidated balance sheets.

 

NOTE 9. LONG–TERM DEBT

 

Long–term debt consists of the following as of December 31:

 

   2011   2010 
Credit facility  $660,000   $619,000 
8.0% senior notes due 2019   300,000     
Unamortized discount   (6,977)    
Long–term debt  $953,023   $619,000 

 

Credit Facility

 

As of December 31, 2011, we have a $1.0 billion credit facility that expires in April 2016. Borrowings under the facility are secured by a first priority lien on substantially all of our assets and the assets of our subsidiaries. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general corporate purposes and for funding distributions to partners. We also may use up to $100.0 million of available borrowing capacity for letters of credit. The facility requires the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.25 to 1.0. As of December 31, 2011, we were in compliance with these financial covenants.

 

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EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

Borrowings under the facility bear interest at a floating rate based on, at our election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that we have outstanding (weighted average effective interest rate of 3.55% at December 31, 2011).

 

Borrowings under the facility may not exceed a “borrowing base” determined by the lenders under the facility based on our oil and natural gas reserves. As of December 31, 2011, the borrowing base under the facility was $800.0 million. The borrowing base is subject to scheduled redeterminations as of April 1 and October 1 of each year with an additional redetermination once per calendar year at our request or at the request of the lenders and with one calculation that may be made at our request during each calendar year in connection with material acquisitions or divestitures of properties.

 

8.0% Senior Notes due 2019

 

On March 22, 2011, we issued $300.0 million in aggregate principal amount of 8.0% senior unsecured notes due 2019 (the “Notes”) at an offering price equal to 100% of par. The Notes were sold in a private placement to eligible purchasers in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended.

 

We received net proceeds of $291.5 million, after deducting the discount of $7.5 million and offering expenses of $1.0 million. We used the net proceeds to repay indebtedness under our existing credit facility. The discount and the offering expenses are being amortized over the life of the Notes. The amortization is included in “Interest expense” in our unaudited condensed consolidated statements of operations.

 

The Notes were issued under an indenture dated March 22, 2011, (the “Indenture”), mature April 15, 2019, and bear interest at 8.0%. Interest is payable semi–annually beginning October 15, 2011. The Notes are general unsecured obligations and are effectively junior in right of payment to any of our secured indebtedness to the extent of the value of the collateral securing such indebtedness.

 

The Notes are unconditionally guaranteed, jointly and severally, on a senior unsecured basis, by all of our existing subsidiaries other than EV Energy Finance Corp. (“Finance”), which is a co–issuer of the Notes. Neither we nor Finance have independent assets or operations apart from the assets and operations of our subsidiaries.

 

The Indenture provides that, prior to April 15, 2014, we may redeem up to 35% of the aggregate principal amount of the Notes with the net proceeds of a public or private equity offering at a redemption price of 108.0% of the principal amount redeemed, plus accrued and unpaid interest, provided that:

 

·at least 65% of the aggregate principal amount of Notes issued under the Indenture remains outstanding immediately after the occurrence of such redemption; and

 

·the redemption occurs within 180 days of the date of the closing of such public or private equity offering.

 

On and after April 15, 2015, we may redeem all or a part of the Notes, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if any, on the Notes to be redeemed to the applicable redemption date, if redeemed during the twelve–month period beginning on April 15 of the years indicated below:

 

Year  Percentage 
2015   104.0%
2016   102.0%
2017 and thereafter   100.0%

 

Prior to April 15, 2015, we may redeem all or part of the Notes at a redemption price equal to the sum of:

 

·the principal amount thereof, plus

 

·the Make Whole Premium (as defined in the Indenture) at the redemption date, plus accrued and unpaid interest, if any, to the redemption date.

  

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EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

  

The Indenture also provides that, if a change of control (as defined in the Indenture) occurs, the holders have a right to require us to repurchase all or part of the Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

 

The Indenture contains covenants that, among other things, limit our ability to: (i) pay distributions on, purchase or redeem our common units or redeem our subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of our assets; (vii) enter into intercompany agreements that restrict distributions or other payments from our restricted subsidiaries to us; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.

 

In connection with the issuance of the Notes, we and the initial purchasers entered into a Registration Rights Agreement (the “Registration Rights Agreement”). Pursuant to the Registration Rights Agreement, we agreed to conduct a registered exchange offer for the Notes or cause to become effective a shelf registration statement providing for the resale of the Notes. We completed the registered exchange offer for the Notes in 2011.

 

NOTE 10. COMMITMENTS AND CONTINGENCIES

 

We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material effect on our consolidated financial statements, and no amounts have been accrued at December 31, 2011 and 2010.

 

NOTE 11. OWNERS’ EQUITY

 

Equity Offerings

 

In June 2009 and September 2009, we closed public offerings of 4.025 million common units and 3.22 million common units, respectively, at offering prices of $20.40 per common unit and $22.83 per common unit, respectively. We received net proceeds of $151.6 million, including contributions of $3.1 million by our general partner to maintain its 2% interest in us.

 

In February 2010 and August 2010, we closed public offerings of 3.45 million and 3.45 million common units, respectively, at offering prices of $28.08 per common unit and $33.97 per common unit, respectively. We received net proceeds of $208.9 million, including contributions of $4.3 million by our general partner to maintain its 2% interest in us.

 

In March 2011, we closed a public offering of 3.45 million of our common units at an offering price of $44.42 per common unit. We received net proceeds of $149.8 million, including a contribution of $3.0 million by our general partner to maintain its 2% interest in us.

 

Units Outstanding

 

At December 31, 2011, owner’s equity consists of 34,173,650 common units outstanding (including 1,698,272 common units held by our executive officers and directors) and 3,873,357 Class B units (including 2,052,581 Class B units owned by our executive officers and directors), collectively representing a 98% limited partnership interest in us, and a 2% general partnership interest.

 

Common Units

 

The common units have limited voting rights as set forth in our partnership agreement.

 

Pursuant to our partnership agreement, if at any time our general partner and its affiliates own more than 80% of the common units outstanding, our general partner has the right, but not the obligation, to “call” or acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then current market value. Our general partner may assign this call right to any of its affiliates or to us.

 

Class B Units

 

The Class B units have limited voting rights as set forth in our partnership agreement.

 

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EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

Each Class B unit will become convertible into one common unit at the election of the holder of the Class B unit at any time after December 12, 2012. Prior to converting into common units, each Class B unit will be entitled to the same distributions and voting rights as a common unit.

 

General Partner Interest

 

Our general partner owns a 2% interest in us. This interest entitles our general partner to receive distributions of available cash from operating surplus as discussed further below under Cash Distributions. Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, Class B unitholders and general partner will receive.

 

The general partner has the management rights as set forth in our partnership agreement.

 

Allocations of Net Income

 

Net income is allocated between our general partner and the limited partners in accordance with the provisions of our partnership agreement. Net income is generally allocated first to our general partner and the limited partners in an amount equal to the net losses allocated to our general partner and the limited partners in the current and prior tax years under the partnership agreement. The remaining net income is allocated to our general partner and the limited partners in accordance with their respective percentage interests of the general partner and limited partners.

 

Cash Distributions

 

We intend to continue to make regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our credit facility prohibits us from making cash distributions if any potential default or event of default, as defined in our credit facility, occurs or would result from the cash distribution.

 

Within 45 days after the end of each quarter, we will distribute all of our available cash (as defined in our partnership agreement) to our general partner and unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter; less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, to comply with applicable laws, any of our debt instruments, or other agreements or to provide funds for distributions to unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

 

Our partnership agreement requires that we make distributions of available cash from operating surplus in the following manner:

 

·first, 98% to the 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; and

 

·thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages below.

 

In December 2011, our general partner notified us that it had made an incentive distribution rights (“IDR”) reset election as defined in our partnership agreements. Under the IDR reset election, our general partner relinquished its right to receive incentive distribution payments based on the minimum quarterly and target cash distribution levels set at the time of our public offering. The minimum quarterly distribution was increased from $0.40 to $0.7615 and the levels at which the IDRs participate in distributions were reset at higher amounts based on current common unit distribution rates and a formula in the partnership agreement. In connection with resetting the minimum quarterly and target cash distribution levels, our general partner received 3.9 million Class B units.

 

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EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

  

Prior to the IDR reset election, our general partner was entitled to incentive distributions if the amount we distributed with respect to one quarter exceeded specified target levels shown below:

 

     Marginal Percentage 
     Interest in Distributions 
 Total Quarterly Distributions   Limited    General 
 Target Amount   Partner    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%  

 

Subsequent to the IDR reset election, our general partner is entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:

 

       Marginal Percentage 
       Interest in Distributions 
  Total Quarterly Distributions   Limited     General 
  Target Amount   Partner     Partner 
Minimum quarterly distribution   $0.7615     98    2%
First target distribution   Up to $0.875725     98%    2%
Second target distribution   Above $0.875725, up to $0.951875     85%    15%
Thereafter   Above $0.951875     75%    25%

 

The following sets forth the distributions we paid during the years ended December 31, 2011 and 2010:

 

       Distribution   Total 
Date Paid    Period Covered   per Unit   Distribution 
February 14, 2011   October 1, 2010 – December 31, 2010   $0.759   $26,477 
May 13, 2011   January 1, 2011 – March 31, 2011    0.760    29,496 
August 12, 2011   April 1, 2011 – June 30, 2011    0.761    29,541 
November 14, 2011   July 1, 2011 – September 30, 2011    0.762    29,587 
             $115,101 
                
February 12, 2010   October 1, 2009 – December 31, 2009   $0.755   $20,221 
May 14, 2010   January 1, 2010 – March 31, 2010    0.756    23,212 
August 13, 2010   April 1, 2010 – June 30, 2010    0.757    23,248 
November 12, 2010   July 1, 2010 – September 30, 2010    0.758    26,253 
             $92,934 

 

On January 20, 2012, the board of directors of EV Management declared a $0.763 per unit distribution for the fourth quarter of 2011 on all common and Class B units. The distribution was paid on February 12, 2012 to unitholders of record at the close of business on January 30, 2012. The aggregate amount of the distribution was $29.8 million.

 

84
 

 

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

  

NOTE 12. NET INCOME (LOSS) PER LIMITED PARTNER UNIT

 

The following sets forth the calculation of net income (loss) per limited partner unit for the years ended December 31:

 

   2011   2010   2009 
Net income  $102,641   $106,051   $1,410 
Less:               
Incentive distribution rights   (8,833)   (9,817)   (7,012)
General partner’s 2% interest in net income   (2,053)   (2,121)   (28)
Limited partners’ interest in net income (loss)  $91,755   $94,113   $(5,630)
                
Weighted average limited partner units outstanding:               
Common units   33,532    27,962    16,524 
Class B units   212         
Subordinated units           2,718 
Performance units (1)   151    133    60 
Denominator for basic net income (loss) per limited partner unit   33,895    28,095    19,302 
Dilutive phantom units   288    67     
Total   34,183    28,162    19,302 
                
Net income (loss) per limited partner unit:               
Basic  $2.71   $3.35   $(0.29)
Diluted  $2.68   $3.34   $(0.29)

 


(1)Our earned but unvested performance units are considered to be participating securities for purposes of calculating