ITEM 1. BUSINESS
Overview
EV Energy Partners, L.P. (“we,” “our,” “us” or the “Partnership”) is a publicly held Delaware limited partnership. 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 have two reportable segments: exploration and production and midstream. Our exploration and production segment is responsible for the acquisition, development and production of our oil and natural gas properties. Our midstream segment, which consists of our investments in Utica East Ohio Midstream LLC (“UEO”) and, prior to October 2014, Cardinal Gas Services, LLC (“Cardinal”), is engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio. We account for our midstream asset using the equity method of accounting.
As of December 31, 2014, our oil and natural gas 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 Monroe Field in Northern Louisiana, the San Juan Basin, Michigan, Central Texas (which includes the Austin Chalk area), and the Permian Basin. Our midstream assets are located in the Utica Shale area in Ohio.
Oil, natural gas and natural gas liquids reserve information is derived from our reserve report prepared by Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), our independent reserve engineers. All of our proved reserves are located in the United States. The following table summarizes information about our proved reserves by geographic region as of December 31, 2014:
(1)At December 31, 2014, our standardized measure of discounted future net cash flows was $1,093.3 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 reserves.
The table below provides a reconciliation of PV-10 to the standardized measure at December 31, 2014 (dollars in millions):
Developments in 2014
In 2014, we invested $114.1 million in our midstream segment to fund our share of capital expenditures for Cardinal and UEO.
In October 2014, we, along with certain institutional partnerships managed by EnerVest, closed on the sale of certain deep rights in the Eagle Ford formation in Burleson, Brazos and Grimes Counties, Texas, and our share of the proceeds was $33.8 million. We retained all non-Eagle Ford formation rights, including the Austin Chalk formation and corresponding production. The transaction is subject to customary purchase price adjustments.
In October 2014, we also closed on the sale of our 9% interest in Cardinal for $161.1 million, which included certain purchase price adjustments. The transaction is subject to additional customary purchase price adjustments.
Developments in 2015
Beginning in the third quarter of 2014, prices for oil began a dramatic decline, and current prices for oil are significantly less than they have been over the last several years. Beginning in the fourth quarter of 2014, prices for natural gas and natural gas liquids also began to decline, and they remain low by historical standards. These low prices affect our business in numerous ways, including:
·a material reduction in our revenues and cash flows;
·a decrease in proved reserves and possible impairments of our oil and natural gas properties as a result of reduced capital spending and the possibility that some of our developed wells and undeveloped wells may become uneconomic;
·an increase in our cost of capital and difficulty in accessing capital, including the decrease in the borrowing base under our credit facility from $730.0 million to $650.0 million;
·an increase in the value of oil and natural gas derivatives we entered into before prices declined, which increases our exposure to counterparty defaults; and
·an increase in the possibility that some of the purchasers of our oil and natural gas production, or some of the companies that provide us with services, may experience financial difficulties.
In response to lower prices, we have taken a number of actions to preserve our liquidity and financial flexibility, including:
·reducing our distribution for the fourth quarter of 2014 by $0.274 per common unit to $0.50 per common unit;
·amending our credit facility to include, among other things, an extension of the facility to February 2020, as well as an extension of our senior secured debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense covenant to March 31, 2016;
·reducing the amount of capital spending we expect to dedicate to the development of our exploration and production segment by approximately 40% in 2015; and
·actively seeking alternative sources of capital to develop our proved undeveloped and probable reserves, including farmouts, production payments and joint ventures.
In addition, with the completion of the initial processing, fractionation and storage buildout in UEO and the sale of our interest in Cardinal, our midstream capital expenditures are expected to decline by approximately $100.0 million compared with 2014. We also plan to accelerate the monetization of our 21% investment in UEO and utilize the proceeds from a sale to reinvest in long-life, producing oil and natural gas properties. We believe that such a sale and reinvestment would result in a significant increase to our borrowing base and liquidity.
Business Strategy
Our primary business objective is to manage our oil and natural gas properties and midstream investments 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.
·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 portion of our oil and natural gas production.
Our commodity derivatives are primarily in the form of swaps that are designed to provide a fixed price 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 89% of our estimated net proved reserves as of December 31, 2014. 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 $2.0 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 over 173,000 net working interest acres in Ohio and Pennsylvania that we believe may be prospective for the Utica Shale. In mid-2012, we initiated the process for the monetization of a portion of our working interest acres related to the Utica Shale, and in 2013, we, along with certain institutional partnerships managed by EnerVest, signed agreements to divest a portion of our Utica shale acreage in Ohio. Through December 2014, we have closed on sales with proceeds of $45.6 million for these acres. We continue to pursue additional forms of monetizations, 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 to delay the monetization of all or a portion of the Utica Shale properties.
·Continue capital contributions to our midstream investment and evaluate potential monetization opportunities
We own a 21% interest in UEO, which provides midstream services to natural gas producers in the Utica Shale area in Ohio. As of December 31, 2014, we have invested $294.1 million in cash in UEO and plan to invest an additional $26.0 million to $32.0 million in 2015. UEO provides a relatively stable cash flow stream based on long-term, fixed fee contracts with dedicated acreage from subsidiaries of Chesapeake Energy Corporation (“Chesapeake”) and Total S.A. (“Total”), as well as other producers. However, we remain focused on the acquisition, development and production of oil and natural gas properties and we plan to accelerate the monetization of our interest in UEO.
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
Our properties are located in eight producing basins with an average reserve life of 16 years as of December 31, 2014. The majority of our properties have been producing for many years, resulting in predictable decline rates.
·Significant inventory of low-risk development opportunities
We have a significant inventory of development projects in our core areas of operation. At December 31, 2014, we had 2,802 identified gross drilling locations, of which approximately 298 were proved undeveloped drilling locations and the remainder were unproved drilling locations. In 2014, we drilled a total of 188 gross (38.8 net) wells with a 99% gross success rate. Our development program is focused on lower risk drilling opportunities to maintain and increase production.
·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.
·Hedging through 2016 at attractive average prices
By removing the price volatility from a 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.
·Midstream investment provides opportunity for monetization at an attractive price.
At our midstream investment, producers are charged a fixed fee for gathering, processing, transporting, fractionating, and storage services. The contracts are 15 to 20 years in duration with dedicated acreage and/or minimum volumes. As such, we plan to accelerate monetization of this asset given our long-term focus on the acquisition, development and production of oil and natural gas properties.
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, 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 is one of the 25 largest oil and natural gas companies in the United States, with more than 36,000 wells across 15 states, 6.0 million acres under lease and $11.0 billion in assets under management.
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 oil and natural gas properties representing 89% of our proved oil and gas reserves as of December 31, 2014. The EnerVest partnerships own interests in oil and gas properties in which we own interests. The properties are primarily located in the Barnett Shale, Central Texas and the Appalachian Basin, and these properties represent approximately 70% of our net proved reserves at December 31, 2014. 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 agreements for certain of our EnerVest partnerships, however, provide 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 partnerships during their investment periods, EnerVest must first offer those opportunities to those EnerVest partnerships, 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.
Oil and Natural Gas Producing Activities
At December 31, 2014, our oil and natural gas 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 Monroe Field in Northern Louisiana, the San Juan Basin, Michigan, Central Texas (which includes the Austin Chalk area), and the Permian Basin.
Barnett Shale
Our properties are primarily located in Denton, Montague, Parker, Tarrant and Wise counties in Northern Texas. Our estimated net proved reserves as of December 31, 2014 were 576.7 Bcfe, 72% of which is natural gas. During 2014, we drilled 73 gross wells in the Barnett Shale, all of which were successfully completed. EnerVest operates wells representing 98% of our estimated net proved reserves in this area, and we own an average 27% working interest in 1,537 gross productive wells.
Appalachian Basin (including the Utica Shale)
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 40 counties in Eastern Ohio and 8 counties in Western Pennsylvania. Our West Virginia area properties are producing primarily from the Balltown, Benson and Big Injun formations in 22 counties in North Central West Virginia. Our estimated net proved reserves as of December 31, 2014 were 137.1 Bcfe, 69% of which is natural gas. During 2014, we drilled 42 gross wells in the Applachian Basin, 40 of which were successfully completed. EnerVest operates wells representing 65% of our estimated net proved reserves in this area, and we own an average 40% working interest in 8,546 gross productive wells.
We hold approximately 173,000 net working interest acres in Ohio and Pennsylvania and an approximate 2% average ORRI in approximately 880,000 gross acres in 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. Of the wells we drilled in the Appalachian Basin area in 2014, 16 gross wells were drilled in the Utica Shale, and our estimated net proved reserves in this area were 40.9 Mmcfe as of December 31, 2014.
The Utica Shale area can be divided into wet natural gas, volatile oil, black oil and dry natural gas areas. Most drilling activity in the Utica Shale area has been in the wet natural gas area, but drilling activity is increasing in the dry natural gas and volatile oil areas. The current focus in the volatile oil area is on hydraulic fracturing techniques necessary to economically drill and produce in this area. We own approximately 114,000 acres in the wet natural gas and volatile oil areas. We are currently seeking partners to provide capital for drilling and development on part of our acreage in the wet natural gas area.
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.
Mid-Continent Area
Our properties are primarily located in 43 counties in Oklahoma, 22 counties in Texas, four parishes in North Louisiana, two counties in Kansas and six counties in Arkansas. Our estimated net proved reserves as of December 31, 2014 were 59.8 Bcfe, 67% of which is natural gas. During 2014, we drilled 40 gross wells in the Mid-Continent area, all of which were successfully completed. EnerVest operates wells representing 18% of our estimated net proved reserves in this area, and we own an average 18% working interest in 1,835 gross productive wells.
Monroe Field
Our properties are primarily located in two parishes in Northeast Louisiana. Our estimated net proved reserves as of December 31, 2014 were 52.5 Bcfe, 100% of which is natural gas. During 2014, we did not drill any wells in the Monroe Field. EnerVest operates wells representing 100% of our estimated net proved reserves in this area, and we own an average 99% working interest in 3,913 gross productive wells.
San Juan Basin
Our 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, 2014 were 51.9 Bcfe, 66% of which is natural gas. During 2014, we did not drill any wells in the San Juan Basin. EnerVest operates wells representing 93% of our estimated net proved reserves in this area, and we own an average 71% working interest in 208 gross productive wells.
Michigan
Our 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, 2014 were 51.3 Bcfe, 100% of which is natural gas. During 2014, we did not drill any wells in Michigan. EnerVest operates wells representing 99% of our estimated net proved reserves in this area, and we own an average 99% working interest in 374 gross productive wells.
Central Texas
Our properties produce primarily from the Austin Chalk formation and are located in 16 counties in Central Texas. Our portion of the estimated net proved reserves as of December 31, 2014 was 43.2 Bcfe, 39% of which is natural gas. During 2014, we drilled 29 gross wells in Central Texas, all of which were successfully completed. EnerVest operates wells representing 97% of our estimated net proved reserves in this area, and we own an average 15% working interest in 1,649 gross productive wells.
Permian Basin
Our 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, 2014 were 28.0 Bcfe, 38% of which is natural gas. During 2014, we drilled three gross wells in the Permian Basin, all of which were successfully completed. EnerVest operates wells representing 99% of our estimated net proved reserves in this area, and we own an average 97% working interest in 137 gross productive wells.
Our Oil, Natural Gas and Natural Gas Liquids Data
Our Reserves
The following table presents our estimated net proved reserves at December 31, 2014:
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. We do not have any reserves that would be classified as synthetic oil or synthetic natural gas.
Our estimates of proved reserves are based on the quantities of oil, natural gas and natural gas liquids 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. 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 are believed to provide accurate forecasts. Non-producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. These methods are believed to 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, natural gas and natural gas liquids reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and natural gas liquids 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, natural gas and natural gas liquids that are ultimately recovered. Please read “Risk Factors” in Item 1A.
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 units at the current distribution rate under our cash distribution policy.
Assuming we maintain our current quarterly distribution of $0.50 per common unit, we will require available cash of approximately $25.2 million per quarter based on the common units and phantom units outstanding as of February 13, 2015. 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, natural gas and natural gas liquids we produce;
·the prices at which we sell our 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.
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.
If 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, natural gas and natural gas liquids. Prices for these commodities have been depressed recently when compared with historical prices. The prices we receive for our 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 prices have a significant impact on the value of our reserves and on our cash flows. Prices 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, natural gas and natural gas liquids;
·the amount of added production from development of unconventional natural gas reserves;
·the price and quantity of foreign imports of oil, natural gas and natural gas liquids;
·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
·the price and availability of alternative fuels.
Low prices will decrease our revenues, but may also reduce the amount of oil, natural gas or natural gas liquids 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.
Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling and result in changes to the amount of our proved undeveloped reserves.
As of December 31, 2014, we had over 2,802 gross identified potential drilling locations on our existing acreage. As of December 31, 2014, we included reserves attributable to 298 of our gross identified potential drilling locations in our proved undeveloped reserves category. These drilling locations, including those without proved undeveloped reserves, represent a part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Future development of proved undeveloped reserves attributable to our interests in properties EnerVest does not operate will be subject to decisions of the operator which will be beyond our control.
Approximately 16% of our total estimated proved reserves as of December 31, 2014, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that we will have the financing to make the substantial capital expenditures required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that our projections of the ability to finance these future cots will be realized, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in oil, natural gas or natural gas liquids prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. In addition, the decision of the operators to develop the proved undeveloped reserves attributable to our properties that EnerVest does not operate will be subject to the business plans and constraints of the operators of these properties, and be beyond our control.
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 70% of our estimated net proved reserves as of December 31, 2014. 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 in 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 may limit our gains and expose us to counterparty credit risk.
We enter into derivative contracts from time to time to manage our exposure to fluctuations in oil, natural gas and natural gas liquids prices. These derivative contracts limit our potential gains if prices rise above the fixed prices established by the derivative contracts. These derivative contracts may also expose us to other risks of financial losses, for example, if our production is less than we anticipated at the time we entered into the derivatives contract. Similarly, during periods of falling commodity prices, our derivative contracts expose us to risk of financial loss if the counterparty to the derivative contract fails to perform its obligations under the derivative contract (e.g., our counterparty fails to perform its obligation to make payments to us under the derivative contract when the market (floating) price under such derivative contract falls below the specified fixed price). 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. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
Our limited ability to hedge our natural gas liquids production could adversely impact our net cash provided by operating activities and results of operations.
A liquid, readily available and commercially viable market for hedging natural gas liquids has not developed in the same way that exists for oil and natural gas. The current direct natural gas liquids hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits our ability to hedge our natural gas liquids production effectively or at all. As a result, our net cash provided by operating activities and results of operations could be adversely impacted by fluctuations in the market prices for natural gas liquids.
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.
Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC approved on November 5, 2013, a proposed rule imposing position limits for certain futures and option contracts in various commodities (including natural gas) and for swaps that are their economic equivalents. Certain specified types of hedging transactions are exempt from these position limits, provided that such hedging transactions satisfy the CFTC’s requirements for “bona fide hedging” transactions or positions. Similarly, the CFTC has issued a proposed rule on margin requirements for swap transactions, which proposes an exemption for commercial end-users, entering into uncleared swaps in order to hedge commercial risks affecting their business, from any requirement to post margin to secure such swap transactions. In addition, the CFTC has issued a final rule authorizing an exception for commercial end-users using swaps to hedge their commercial risks from the otherwise applicable mandatory obligation under the Dodd-Frank Act to clear all swap transactions through a registered derivatives clearing organization and to trade all such swaps on a registered exchange. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. All of the above regulations could increase the costs to us of entering into derivative contracts to hedge or mitigate our exposure to volatility in oil, natural gas and natural gas liquids prices and other commercial risks affecting our business.
While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or margin requirements, depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, these rules and regulations may require us to comply with position limits, margin requirements and with certain clearing and trade-execution requirements in connection with our financial derivative activities The Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared derivative contracts with us, which could increase the cost to us of entering into such derivative contracts. The Dodd-Frank Act may also require our current counterparties to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of commercial end-users to have access to derivative contracts to hedge or mitigate their exposure to volatility in oil, natural gas and natural gas liquids prices. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes), materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter.
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 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.
Unless we replace the 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, natural gas and natural gas liquids prices and the number and attractiveness of properties for sale.
Our estimated 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 our 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, natural gas and natural gas liquids 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, natural gas and natural gas liquids 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, natural gas and natural gas liquids 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, development and midstream expansion 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 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. The agreement governing our midstream investment requires that we make capital calls when requested by the operator of the facility. In 2015, we expect these capital calls to be between $26.0 million and $32.0 million. Should we not make these capital calls, our ownership could be diluted or future distributions from our midstream investments could be reduced by any unfunded capital contributions.
Our capital 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:
·the estimated quantities of our reserves;
·the amount of oil, natural gas and natural gas liquids we produce from existing wells;
·the prices at which we sell our production;
·the ability of our midstream business to obtain commitments for production to use their gathering, processing and fractionation facilities; 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, 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
·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, natural gas and natural gas liquids reserves. Any future acquisition will require an assessment of recoverable reserves, title, future oil, natural gas and natural gas liquids 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, natural gas and natural gas liquids or the future operating or development costs of properties acquired;
·incorrect estimates of the 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, natural gas and natural gas liquids, we have and may continue to enter into hedging arrangements for a significant portion of our 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 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 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 commodity 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, natural gas and natural gas liquids revenues becoming more sensitive to commodity price changes.
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, natural gas and natural gas liquids, 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 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; and
·surface spillage and surface or ground water contamination from petroleum constituents or hydraulic fracturing chemical additives.
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.
Our midstream activities are subject to all of the operating risks associated with constructing, operating and maintaining pipelines, processing and fractionation facilities, and related equipment, including the possibility of leaks, breaks and ruptures, damage due to natural hazards such as ground movement and weather, explosions, fires, personal injuries and death.
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 attorneys’ 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.
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 Safe Drinking Water Act and state or local laws and regulations related to hydraulic fracturing;
·the OPA which subject responsible parties to liability for removal costs and damages arising from an oil spill in waters of the U.S.;
·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; and
·the Endangered Species Act, which may restrict or prohibit operations in protected area.
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 exploration, production and midstream 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 and maintaining 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 resource conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil, natural gas and natural gas liquids 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, natural gas and natural gas liquids. 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, natural gas and natural gas liquids we produce.
The EPA requires the reporting of GHG emissions from specified large GHG emission sources, including 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. We began reporting emissions in 2012 for emissions occurring in 2011 and continue to report as required on an annual basis.
More stringent laws and regulations relating to climate change and GHGs may be adopted and could cause us to incur material expenses to comply.
Both houses of Congress previously 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, natural gas and natural gas liquids 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.
In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. The EPA recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations. Those measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and natural gas production sources and natural gas processing and transmission sources.
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 effect 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 and local 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 most 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. In addition, in past sessions, legislation was 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 including such things as restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some cases impose a moratorium on, hydraulic fracturing. 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.
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; the EPA released a progress report in December 2012; final results are not yet available. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and that it has an initiative under the Toxics Substances Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. 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.
We are now subject to regulation under NSPS and NESHAPS programs, which could result in increased operating costs.
On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and the NESHAP programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We continuously evaluate the effect of new rules on our business.
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, natural gas and natural gas liquids, 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 is 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, natural gas and natural gas liquids, 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 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 and production activities in some of the areas where we operate.
Drilling and producing 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. In addition, during 2014, freezing weather in the Barnett Shale caused us to suspend production from our wells for several days resulting in lost revenues. Similar freezing conditions are likely to occur in the future, which will negatively affect our revenues, perhaps materially.
The amount of cash we have available for distribution to holders of our common 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 noncash 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.
Any significant reduction in our borrowing base under our credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our credit facility if required as a result of a borrowing base redetermination.
Availability under our credit facility is currently subject to a borrowing base of $730.0 million, which was reduced to $650.0 million in conjunction with amending our credit facility in February 2015. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on the value of our oil and natural gas reserves as determined by the lenders under our credit facility, and other factors deemed relevant by our lenders. Continuing declines in prices for oil, natural gas and natural gas liquids may cause our banks to further reduce the borrowing base under our credit facility. As of December 31, 2014, we had outstanding borrowings of $531.0 million which bore a weighted average interest rate of 2.57%. We intend to continue borrowing under our credit facility in the future. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further, if the outstanding borrowings under our credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
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.
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.
We have limited control over operations in our midstream business.
We do not operate our UEO processing and fractionation plants. We have only minority interests in the entity that owns these facilities. As such, we are unable to control, and have only limited ability to influence, these businesses. The operator of these facilities may conduct the business in ways that are not as beneficial to us or our unitholders as would be the case if we operated these businesses.
If producers for our midstream investment do not increase the volumes of natural gas they provide to UEO processing facilities, our ability to increase cash flow may be adversely affected.
The ability of UEO to increase the throughput on their processing facilities will be substantially dependent on receiving increased volumes from producers. Other than the scheduled increases in the minimum volume commitments provided for in the natural gas gathering agreements with certain producers in certain geographic areas, the producers are not obligated to provide additional volumes to the systems, and they may determine in the future that drilling activities in areas outside of the current areas of operation are strategically more attractive to them. A reduction in the natural gas volumes supplied by Chesapeake, Total or other producers could result in reduced throughput on the systems and adversely impact our realized cash flows from our midstream investments.
We do not obtain independent evaluations of natural gas and natural gas liquids reserves connected to the gathering systems of our midstream investment; therefore, in the future, volumes of natural gas and natural gas liquids on our systems could be less than we currently anticipate.
We did not obtain independent evaluations of natural gas and natural gas liquids reserves connected to UEO. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. Notwithstanding the contractual protections in certain of UEO’s agreements, if the total reserves or estimated life of the reserves connected to our gathering systems are less than anticipated and UEO is unable to secure additional sources of natural gas and natural gas liquids, it could have a material adverse effect on the business of our midstream investments.
If third party pipelines or other facilities interconnected to UEO processing facilities become partially or fully unavailable, or if the volumes UEO processes does not meet the quality requirements of such pipelines or facilities, our cash flow could be adversely affected.
UEO processing facilities connect to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third party pipelines or facilities is not within our control. These pipelines and other facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, curtailments of receipt or deliveries due to insufficient capacity or for any other reason. If any of these pipelines or facilities become unable to transport natural gas, or if the volumes that UEO processes do not meet the natural gas quality requirements of such pipelines or facilities, our cash flow could be adversely affected.
Risks Inherent in an Investment in Us
We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.
Unlike a corporation, our limited partnership agreement requires us to make distributions to our unitholders of all available cash reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our units may decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may have difficulty issuing more equity to recapitalize.
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;
·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 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 obligations 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.
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.
Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee 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 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 13, 2015, officers and directors of EV Management owned an aggregate of 9.2% of our outstanding common. 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.
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, natural gas and natural gas liquids.
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.
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 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.
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.
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 Medicare, 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.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
Information regarding our properties is contained in “Item 1. Business - Oil and Natural Gas Producing Activities 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.
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, 2014.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
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 13, 2015, based upon information received from our transfer agent and brokers and nominees, we had 248 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 2014 and 2013:
_____________
(1)Cash distributions are declared and paid in the following calendar quarter.
(2)On February 2, 2015, the board of directors of EV Management declared a quarterly cash distribution for the fourth quarter of 2014 of $0.50 per common unit. The distribution was paid on February 13, 2015.
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.
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.
Our general partner is entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:
Unregistered Sales of Equity Securities
None.
Issuer Purchases of Equity Securities
None.
ITEM 6.
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.
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. 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.
We have two reportable segments: exploration and production and midstream. Our exploration and production segment is responsible for the acquisition, development and production of our oil and natural gas properties. Our midstream segment, which consists of our investment in UEO and, prior to October 2014, Cardinal, is engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio. We account for our midstream segment using the equity method of accounting.
As of December 31, 2014, our oil and natural gas 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 Monroe Field in Northern Louisiana, the San Juan Basin, Michigan, Central Texas (which includes the Austin Chalk area), and the Permian Basin. As of December 31, 2014, we had estimated net proved reserves of 11.9 MMBbls of oil, 712.2 Bcf of natural gas and 36.1 MMBbls of natural gas liquids, or 1,000.5 Bcfe, and a standardized measure of $1,093.3 million.
Developments in 2014
In 2014, we invested $114.1 million in our midstream segment to fund our share of capital expenditures for Cardinal and UEO.
In October 2014, we, along with certain institutional partnerships managed by EnerVest, closed on the sale of certain deep rights in the Eagle Ford formation in Burleson, Brazos and Grimes Counties, Texas, and our share of the proceeds was $33.8 million. We retained all non-Eagle Ford formation rights, including the Austin Chalk formation and corresponding production. The transaction is subject to customary purchase price adjustments.
In October 2014, we also closed on the sale of our 9% interest in Cardinal for $161.1 million, which included certain purchase price adjustments and transaction-related expenses. The transaction is subject to additional customary purchase price adjustments.
Developments in 2015
Beginning in the third quarter of 2014, prices for oil began a dramatic decline, and current prices for oil are significantly less than they have been over the last several years. Beginning in the fourth quarter of 2014, prices for natural gas and natural gas liquids also began to decline, and they remain low by historical standards. These low prices affect our business in numerous ways, including:
·a material reduction in our revenues and cash flows;
·a decrease in proved reserves and possible impairments of our oil and natural gas properties as a result of reduced capital spending and the possibility that some of our developed wells and undeveloped wells may become uneconomic;
·an increase in our cost of capital and difficulty in accessing capital, including the decrease in the borrowing base under our credit facility from $730.0 million to $650.0 million;
·an increase in the value of oil and natural gas derivatives we entered into before prices declined, which increases our exposure to counterparty defaults; and
·an increase in the possibility that some of the purchasers of our oil and natural gas production, or some of the companies that provide us with services, may experience financial difficulties.
In response to lower prices, we have taken a number of actions to preserve our liquidity and financial flexibility, including:
·reducing our distribution for the fourth quarter of 2014 by $0.274 per common unit to $0.50 per common unit;
·amending our credit facility to include, among other things, an extension of the facility to February 2020, as well as an extension of our senior secured debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense covenant to March 31, 2016;
·reducing the amount of capital spending we expect to dedicate to the development of our exploration and production segment by approximately 40% in 2015; and
·actively seeking alternative sources of capital to develop our proved undeveloped and probable reserves, including farmouts, production payments and joint ventures.
In addition, with the completion of the initial processing, fractionation and storage buildout in UEO and the sale of our interest in Cardinal, our midstream capital expenditures are expected to decline by approximately $100.0 million compared with 2014. We also plan to accelerate the monetization of our 21% investment in UEO and utilize the proceeds from a sale to reinvest in long-life, producing oil and natural gas properties. We believe that such a sale and reinvestment would result in a significant increase to our borrowing base and liquidity.
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 distributions that we may receive from our interest in UEO;
·the amount of oil, natural gas liquids and natural gas we produce; and
·the level of our operating and administrative costs.
Oil, natural gas and natural gas liquids 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 oil, natural gas and natural gas liquids include the discovery of substantial accumulations of natural gas in unconventional reservoirs due to technological advancements necessary to commercially produce these unconventional reserves. Factors affecting the price of natural gas include North American weather conditions, industrial and consumer demand for natural gas and natural gas liquids, possible natural gas exports, storage levels of natural gas and natural gas liquids and the availability and accessibility of natural gas deposits in North America.
In order to mitigate the impact of changes in 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 price volatility on our cash flows. By removing a significant portion of this price volatility on our future production through December 2016, we have mitigated, but not eliminated, the potential effects of changing 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 our 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.
UEO generates revenues from fees charged for gathering, compressing, processing and fractionating natural gas and natural gas liquids. The primary drivers of revenues are the capacity of its facilities and the production available for gathering, processing and fractionating. As we account for our investment in UEO using the equity method of accounting, our proportionate share of its revenues or expenses is reflected in “Income from unconsolidated affiliates” in our consolidated statements of operations.
Utica Shale
We hold approximately 173,000 net working interest acres in Pennsylvania and Ohio and an approximate 2% average ORRI in 880,000 gross acres in 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. Exploration and development activities targeting the Utica Shale are progressing, 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.
In mid-2012, we initiated the process for the monetization of a majority of our working interest acres related to the Utica Shale, and in 2013, we, along with certain institutional partnerships managed by EnerVest, signed agreements to divest a portion of our Utica Shale acreage in Ohio. Through December 2014, we have closed on sales with proceeds of $45.6 million for these acres. We continue to pursue additional forms of monetizations, and we cannot at this time predict the type of transactions we may enter into or the type or amount of consideration we may receive. We may not be successful in our additional efforts to monetize the Utica Shale properties, it may take longer to complete the divestiture process than we expect, or we may decide to delay the monetization of all or a portion of the Utica Shale properties.
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 proved 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, natural gas and natural gas liquids 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.
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 reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids 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. Estimated future net cash flows are based on existing proved reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. 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, Natural Gas and Natural Gas Liquids Reserves
Our estimates of proved reserves are based on the quantities of oil, natural gas and natural gas liquids 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. 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 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 production for the next 12 - 36 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.
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, 2014 Compared with the Year Ended December 31, 2013
Net income (loss) for 2014 was $129.7 million compared with $(76.2) million for 2013. The significant factors in this change were (i) a $117.0 million favorable change in gain (loss) on derivatives, net; (ii) a $92.1 million gain on the sale of investment in unconsolidated affiliates; and (iii) a $24.1 million increase in total revenues; partially offset by (iv) a $28.6 million increase in impairment of oil and natural gas properties.
Oil, natural gas and natural gas liquids revenues for 2014 totaled $334.7 million, an increase of $23.8 million compared with 2013. This was the result of increases of $25.0 million related to higher prices for natural gas and $9.8 million related to increased oil, natural gas and natural gas liquids production offset by a decrease of $11.0 million related to lower prices for oil and natural gas liquids.
Lease operating expenses for 2014 increased $1.3 million compared with 2013 as the result of $3.1 million from higher oil, natural gas and natural gas liquids production offset by $1.8 million from a lower rate per Mcfe. Lease operating expenses per Mcfe were $1.66 in 2014 compared with $1.69 in 2013.
Dry hole and exploration costs for 2014 increased $4.3 million compared with 2013 as a result of higher costs at certain of our oil and natural gas properties in the Appalachian Basin and the Austin Chalk.
Production taxes, which are generally based on a percentage of our oil, natural gas and natural gas liquids revenues, for 2014 increased $0.5 million compared with 2013 due to increased oil, natural gas and natural gas liquids revenues. Production taxes for both 2014 and 2013 were $0.19 per Mcfe.
Depreciation, depletion and amortization (“DD&A”) for 2014 decreased $7.7 million compared with 2013 due to $10.8 million from a lower average DD&A rate per Mcfe offset by $3.1 million from increased production. The lower DD&A rate per Mcfe reflects the impact that changes in prices had on our reserves estimates and the decrease in the carrying value of our oil and natural gas properties from the impact of the impairments that were recognized in 2013. DD&A for 2014 was $1.67 per Mcfe compared with $1.85 per Mcfe for 2013.
General and administrative expenses for 2014 totaled $45.0 million, an increase of $4.4 million compared with 2013. This increase is the result of (i) $2.1 million of higher fees paid to EnerVest under the omnibus agreement; (ii) $1.8 million of additional equity compensation costs related to the accelerated vesting of the phantom units of a former officer; and (iii) $0.9 million of higher compensation costs due to the separation payment made to a former officer partially offset by $1.2 million of lower compensation costs primarily related to the January 2014 vesting of our phantom units issued under our equity-based compensation plan. General and administrative expenses were $0.71 per Mcfe in 2014 compared with $0.66 per Mcfe in 2013.
In 2014, as a result of a reduction in estimated future net cash flows primarily caused by the decrease in prices, we incurred impairment charges of $114.0 million. Of this amount, $103.1 million related to oil and natural gas properties that were written down to their fair value as determined based on the expected present value of the future net cash flows. Significant assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future oil and natural gas prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates and other relevant data. The remainder of the impairment charges consisted of $10.7 million of leasehold impairment charges and $0.2 million of an impairment charge to write down assets held for sale to their fair value. In 2013, we incurred impairment charges of $85.3 million. Of this amount, $76.3 million related to oil and natural gas properties that were written down to their fair value as determined based on the expected present value of the future net cash flows. Significant assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future oil and natural gas prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates and other relevant data. The remainder of the impairment charges consisted of $8.5 million of leasehold impairment charges and $0.5 million of an impairment charge to write down assets held for sale to their fair value.
In 2014, we recognized a $31.8 million gain on the sale of oil and natural gas properties in the Eagle Ford and a $1.5 million gain on the sale of oil and natural gas properties in the Utica Shale area of Ohio. In 2013, we recognized a gain of $41.3 million on the sale of oil and natural gas properties in the Utica Shale area of Ohio.
Gain (loss) on derivatives, net was $99.7 million for 2014 compared with $(17.3) million for 2013. This change was attributable to changes in future oil and natural gas prices and the impact of decreased cash settlements of matured derivative contracts with more favorable terms that expired as of December 31, 2013. The 12 month forward price at December 31, 2014 for oil averaged $56.46 per Bbl compared with $95.66 per Bbl at December 31, 2013, and the 12 month forward price at December 31, 2014 for natural gas averaged $3.03 per MmBtu compared with $4.19 at December 31, 2013. The 12 month forward price at December 31, 2013 for oil averaged $95.66 per Bbl compared with $93.09 at December 31, 2012, and the 12 month forward prices at December 31, 2013 for natural gas averaged $4.19 per MmBtu compared with $3.54 per Bbl at December 31, 2012.
Interest expense for 2014 increased $3.5 million compared with 2013 due to an increase of $4.6 million from a higher weighted average long-term debt balance and a $1.5 million decrease in capitalized interest offset by $2.6 million from a lower weighted average effective interest rate.
In 2014, we recognized a gain of $92.1 million on the sale of our 9% interest in Cardinal.
Equity in income (loss) of unconsolidated affiliates was $15.8 million for 2014 compared with $(0.3) million for 2013. The significant factor in the increase was the commencement of operations at both Cardinal and UEO, with throughput continuing to increase as more wells come on line.
Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012
Net loss for 2013 was $76.2 million compared with a net loss of $16.3 million for 2012. This change reflects (i) $84.0 million change in (loss) gain on derivatives, net and (ii) $50.9 million in increased impairment charges, offset by (iii) $41.3 million in increased gain on sales of oil and natural gas properties, (iv) $29.8 million of higher revenues, and (v) $4.1 million in decreased operating expenses.
Oil, natural gas and natural gas liquids revenues for 2013 totaled $310.9 million, an increase of $29.2 million compared with 2012. This was the result of increases of $33.2 million related to higher prices for oil and natural gas and $12.9 million related to increased natural gas and natural gas liquids production offset by decreases of $9.0 million related to lower prices for natural gas liquids and $7.9 million related to decreased oil production.
Lease operating expenses for 2013 increased $0.9 million compared with 2012 as the result of $3.5 million from higher natural gas and natural gas liquids production offset by $1.7 million ($0.03 per Mcfe) of costs in 2012 associated with the sales of oil in tanks acquired in certain of our 2011 acquisitions and $0.9 million from a lower rate per Mcfe. Lease operating expenses per Mcfe were $1.69 in 2013 compared with $1.74 in 2012.
Dry hole and exploration costs for 2013 decreased $4.4 million compared with 2012 primarily as a result of decreased seismic costs at certain of our oil and natural gas properties in the Appalachian Basin.
Production taxes, which are generally based on a percentage of our oil, natural gas and natural gas liquids revenues, for 2013 increased $0.6 million compared with 2012 primarily due to increased oil, natural gas and natural gas liquids revenues. Production taxes for 2013 were $0.19 per Mcfe compared with $0.18 per Mcfe for 2012.
DD&A for 2013 increased $0.4 million compared with 2012 due to $3.7 million from increased production offset by $3.3 million from a lower DD&A rate. The lower DD&A rate per Mcfe reflects the impact that changes in prices had on our reserves estimates. DD&A for 2013 was $1.85 per Mcfe compared with $1.90 per Mcfe for 2012.
General and administrative expenses for 2013 totaled $40.7 million, a decrease of $2.0 million compared with 2012. This decrease is primarily the result of $3.1 million of lower fees paid to EnerVest under the omnibus agreement and $0.7 million of decreased due diligence costs, partially offset by $1.0 million of higher equity compensation costs. General and administrative expenses were $0.66 per Mcfe in 2013 compared with $0.72 per Mcfe in 2012.
In 2013, we incurred impairment charges of $85.3 million. Of this amount, $76.3 million related to oil and natural gas properties that were written down to their fair value as determined based on the expected present value of the future net cash flows. Significant assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future oil and natural gas prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates and other relevant data. The remainder of the impairment charges consisted of $8.5 million of leasehold impairment charges and $0.5 million of an impairment charge to write down assets held for sale to their fair value. In 2012, we incurred impairment charges of $34.5 million. Of this amount, $31.9 million related to oil and natural gas properties that were written down to their fair value, $2.1 million related to leasehold impairment charges and $0.5 million related to additional impairment charges to write down assets held for sale to their fair value.
In 2013, we recognized a gain of $41.3 million on the sale of oil and natural gas properties in the Utica Shale area of Ohio.
Gain (loss) gain on derivatives, net was $(17.3) million for 2013 compared with $66.7 million for 2012. This change was attributable to increases in future natural gas prices. The 12 month forward prices at December 31, 2013 for natural gas averaged $4.19 per Bbl compared with $3.54 per Bbl at December 31, 2012.
Interest expense for 2013 increased $0.4 million compared with 2012 due to an increase of $10.9 million from a higher weighted average long-term debt balance offset by $4.1 million from a lower weighted average effective interest rate and $6.4 million of higher capitalized interest related to our investments in unconsolidated affiliates.
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, contributions to our midstream investments, distributions to our unitholders and general partner and working capital needs. For 2015, we believe that cash on hand, proceeds from sales of assets, net cash flows generated from operations and borrowings under our credit facility will be adequate to fund our capital budget, pay distributions to our unitholders and general partner 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.
Beginning in the third quarter of 2014, prices for oil began a dramatic decline, and current prices for oil are significantly less than they have been over the last several years. Beginning in the fourth quarter of 2014, prices for natural gas and natural gas liquids also began to decline, and they remain low by historical standards. These low prices affect our business in numerous ways, including:
·reducing our distribution for the fourth quarter of 2014 by $0.274 per common unit to $0.50 per common unit;
·amending our credit facility to include, among other things, an extension of the facility to February 2020, as well as an extension of our senior secured debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense covenant to March 31, 2016;
·reducing the amount of capital spending we expect to dedicate to the development of our exploration and production segment by approximately 40% in 2015; and
·actively seeking alternative sources of capital to develop our proved undeveloped and probable reserves, including farmouts, production payments and joint ventures.
In addition, with the completion of the initial processing, fractionation and storage buildout in UEO and the sale of our interest in Cardinal, our midstream capital expenditures are expected to decline by approximately $100.0 million compared with 2014. We also plan to accelerate the monetization of our 21% investment in UEO and utilize the proceeds from a sale to reinvest in long-life, producing oil and natural gas properties. We believe that such a sale and reinvestment would result in a significant increase to our borrowing base and liquidity.
Long-term Debt
As of December 31, 2014, 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, 2014, the borrowing base was $730.0 million, and we had $531.0 million outstanding.
As of December 31, 2014, we have $500.0 million in aggregate principal amount outstanding of 8.0% senior notes due 2019. As of December 31, 2014, the aggregate carrying amount of the senior notes due 2019 was $499.4 million.
In February 2015, we amended our credit facility to include, among other things, an extension of the facility to February 2020, as well as an extension of our ratio of senior secured debt to EBITDAX of no greater than 3.5 to 1.0 covenant to March 31, 2016, after which it reverts back to a ratio of total debt to EBITDAX of no greater than 4.25 to 1.0. In addition, the borrowing base under the facility was decreased to $650.0 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.
Cash and Cash Equivalents
At December 31, 2014, we had $8.3 million of cash and cash equivalents, which included $4.1 million of short-term investments. With regard to our short-term investments, we invest in money market accounts with major financial institutions.
Counterparty Exposure
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, 2014, all of our counterparties have performed pursuant to their derivative contracts.
Cash Flows
Operating Activities
Cash flows from operating activities provided $148.2 million and $152.5 million in 2014 and 2013, respectively. The significant factors in the change were a $24.1 million increase in our oil, natural gas and natural gas liquids revenues offset by $24.8 million of decreased cash settlements from our matured derivative contracts and a decrease in working capital, primarily related to lower accounts receivable as a result of lower oil, natural gas and natural gas liquids prices at December 31, 2014 compared with December 31, 2013. The decreased cash settlements are due to the impact of derivative contracts with more favorable terms that expired as of December 31, 2013.
Cash flows from operating activities provided $152.5 million and $209.5 million in 2013 and 2012, respectively. The significant factor in the decrease was $84.2 million of decreased cash settlements from our matured derivative contracts offset by a $29.2 million increase in our oil, natural gas and natural gas liquids revenues.
Investing Activities
During 2014, we spent $102.8 million for additions to our oil and natural gas properties and increased our investment in our midstream assets by $114.1 million. In addition, we received $206.3 million from the sale of oil and natural gas properties and our investment in Cardinal, and restricted cash, which represents proceeds from the sale of certain oil and natural gas properties we deposited with a qualified intermediary to facilitate like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code, increased by $33.8 million.
During 2013, we spent $66.0 million for an acquisition of oil and natural gas properties, and we received $8.0 million in final purchase price settlements related to our August 2012 acquisition of additional working interests in acreage in Ohio. We spent $98.0 million for additions to our oil and natural gas properties and increased our investment in our midstream assets by $221.1 million. In addition, we received $44.1 million from the sale of oil and natural gas properties and incurred $5.0 million of prepaid drilling costs.
During 2012, we spent $120.0 million for acquisitions of oil and natural gas properties and $129.8 million for additions to our oil and natural gas properties. We also increased our investment in our midstream assets by $33.8 million. In addition, we received $5.5 million from the sale of oil and natural gas properties and $4.6 million from the settlements of acquired derivatives.
Financing Activities
During 2014, we received $209.0 million from borrowings under our credit facility and we repaid $159.0 million of borrowings under our credit facility. In addition, we paid distributions of $155.0 million to holders of our common units and phantom units and our general partner.
During 2013, we received proceeds of $204.3 million, after payment of offering costs of $0.2 million, from our public equity offering in October 2013, and we received contributions of $4.5 million from our general partner in order to maintain its 2% interest in us. We used the proceeds to repay $208.0 million of indebtedness outstanding under our credit facility. We also received $329.0 million from borrowings under our credit facility and paid distributions of $140.1 million to holders of our common units and phantom units and our general partner.
During 2012, we received proceeds of $262.5 million, after payment of offering costs of $0.3 million, from our public equity offering in February 2012 and $201.9 million, after deducting $4.1 million for underwriters’ discounts and payment of offering expenses, from our debt offering in March 2012. We used the proceeds to repay $460.0 million of indebtedness outstanding under our credit facility. We also received $160.0 million from borrowings under our credit facility and contributions of $5.7 million from our general partner in order to maintain its 2% interest in us. In addition, we paid distributions of $128.9 million to holders of our common units, Class B units and our general partner.
Capital Requirements
In 2015, we currently expect spending for additions to our oil and natural gas properties to be between $55.0 million and $65.0 million and our commitment to fund the construction activities for UEO to be between $26.0 million and $32.0 million. Assuming we maintain our current quarterly distribution of $0.50 per common unit, we also currently expect to make distributions of approximately $25.2 million per quarter to holders of our common units, phantom units and general partner based on our common units and phantom units outstanding as of February 13, 2015. We expect to fund these amounts with cash on hand, proceeds from sales of assets, net cash flows generated from operations and borrowings under our credit facility.
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 2015 with proceeds from the sale of UEO or other assets or through the issuance of equity or debt securities.
Contractual Obligations
_____________
(1)In February 2015, we amended our credit facility to include, among other things, an extension of the facility to February 2020.
(2)Amounts represent the expected cash payments for interest based on (i) the amount outstanding under our credit facility as of December 31, 2014 and the weighted average interest rate for 2014 of 2.57%, and (ii) our $500.0 million in aggregate principal amount of 8.0% senior notes due 2019. Such amounts do not include the effects of our interest rate swaps.
(3)Amounts represent commitments under a firm transportation agreement at current rates.
(4)Amounts represent payments to be made under our omnibus agreement with EnerVest based on the amount that we will pay in 2015. This amount will increase or decrease as we purchase or divest assets. While these payments will continue for periods subsequent to December 31, 2015, 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, 2014 is $105.8 million.
Off-Balance Sheet Arrangements
As of December 31, 2014, we had no off-balance sheet arrangements.
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, and our ability to pay distributions;
·our business strategy and plans, and future capital expenditures, including plans for the sale of additional acreage in the Utica Shale, the Eagle Ford formation and UEO;
·our estimated net proved reserves, PV-10 value and standardized measure;
·market prices;
·our anticipated future gathering, processing and fractionation activities;
·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, natural gas and natural gas liquids and the length of time commodity prices remain depressed;
·significant disruptions in the financial markets;
·future capital requirements and availability of financing;
·our limited control over operations in our midstream business;
·uncertainty inherent in estimating our reserves;
·risks associated with drilling and operating wells;
·discovery, acquisition, development and replacement of reserves;
·cash flows and liquidity;
·timing and amount of future production of oil, natural gas and natural gas liquids;
·availability of drilling and production equipment;
·marketing of oil, natural gas and natural gas liquids;
·developments in oil and natural gas producing countries;
·competition;
·general economic conditions;
·governmental regulations;
·activities taken or non-performance by third parties, including suppliers, contractors, operators, transporters and purchasers of our production and counterparties to our derivative financial instrument contracts;
·hedging decisions, including whether or not to enter into derivative financial instruments;
·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, natural gas and natural gas liquids. Declines in prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower prices also may reduce the amount of oil, natural gas or natural gas liquids that we can produce economically. A decline in prices could have a material adverse effect on the estimated value and estimated quantities of our reserves, our ability to fund our operations and our financial condition, cash flows, results of operations and access to capital. Historically, prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.
ITEM 7A.
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, derivatives to reduce our risk of changes in the prices of oil, natural gas and natural gas liquids. 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, natural gas and natural gas liquids.
We have entered into derivatives to hedge a portion of our anticipated production through December 2016. As of December 31, 2014, we have derivatives covering approximately 64% of our production attributable to our estimated net proved reserves through December 2016, as estimated in our reserve report prepared by third party engineers using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in our reserve reports, perhaps materially. Please read the disclosures under “Our estimated 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.
The fair value of our oil and natural gas derivatives at December 31, 2014 was a net asset of $135.4 million. A 10% change in 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 commodity contracts of approximately $27.8 million. Please see “Item 8.
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 (2013) 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, 2014.
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, 2014 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 27, 2015
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, 2014 and 2013, 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, 2014. We also have audited the Partnership's internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership's management is responsible for these consolidated 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 consolidated 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 consolidated 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 consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall consolidated 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 EV Energy Partners, L.P. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/DELOITTE & TOUCHE LLP
Houston, Texas
February 27, 2015
EV Energy Partners, L.P.
Consolidated Balance Sheets
(In thousands, except number of units)
See accompanying notes to consolidated financial statements.
EV Energy Partners, L.P.
Consolidated Statements of Operations
(In thousands, except per unit data)
See accompanying notes to consolidated financial statements.
EV Energy Partners, L.P.
Consolidated Statements of Cash Flows
(In thousands)
See accompanying notes to consolidated financial statements.
EV Energy Partners, L.P.
Consolidated Statements of Changes in Owners’ Equity
(In thousands)
See accompanying notes to consolidated financial statements.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements
NOTE 1. ORGANIZATION AND NATURE OF BUSINESS
EV Energy Partners, L.P. (the “Parent”) and its wholly owned subsidiaries (collectively, the “Partnership”) are a publicly held limited partnership. 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.
The Partnership has two reportable segments: exploration and production and midstream. The exploration and production segment is responsible for the acquisition, development and production of the Partnership’s oil and natural gas properties. The midstream segment, which consists of the Partnership’s investments in Utica East Ohio Midstream LLC (“UEO”) and, prior to October 2014, Cardinal Gas Services, LLC (“Cardinal”), is engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio.
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, 2014 and 2013, 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.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
Property and Depreciation
Our oil, natural gas and natural gas liquids 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 $117.7 million and $133.8 million as of December 31, 2014 and December 31, 2013, 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 2014, 2013 and 2012, we recorded dry hole and exploration costs of $6.7 million, $2.4 million and $6.8 million, respectively.
No gains or losses are recognized upon the disposition of proved 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 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 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 2014, 2013 and 2012, we recorded impairment charges of $103.3 million, $76.9 million and $32.4 million, respectively, related to proved oil and natural gas properties as the carrying amounts of such properties were determined not to be recoverable (see Note 8).
Unproved oil and natural gas properties are assessed periodically on a property-by-property basis, and any impairment in value is recognized. For 2014, 2013 and 2012, we recorded leasehold impairment charges of $10.7 million, $8.5 million and $2.1 million, respectively, related to unproved oil and natural gas properties.
Restricted Cash
Restricted cash represents proceeds from the sale of certain oil and natural gas properties we deposited with a qualified intermediary to facilitate like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code.
Investments in Unconsolidated Affiliates
We account for our investments in unconsolidated affiliates using the equity method of accounting. Accordingly, we recognize our proportionate share of their earnings or losses in the period in which they are reported in their financial statements rather than in the period in which they declare a dividend. Dividends received from these unconsolidated affiliates decrease the carrying amount of our investments.
Asset Retirement Obligations
An asset retirement obligation (“ARO”) represents the future abandonment costs of tangible assets, such as wells, service assets, 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.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
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, 2014 or 2013.
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.
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, natural gas and natural gas liquids.
We have elected not to designate our derivatives as hedging instruments. Changes in the fair value of derivatives are recorded immediately to earnings as “Gain (loss) on derivatives, net” in our consolidated statements of operations.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
Concentration of Credit Risk
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, 2014, all of our counterparties have performed pursuant to their derivative contracts.
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 2014, 2013 and 2012, 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 April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This ASU amends the definition of a discontinued operation and requires entities to provide additional disclosures about disposal transactions that do not meet the discontinued operations criteria. This ASU requires discontinued operations treatment for disposals of a component or group of components that represent a strategic shift that has or will have a major impact on an entity’s operations or financial results. The provisions of ASU 2014-08 are applicable to annual reporting periods beginning after December 15, 2014 and interim periods within those annual periods. Early adoption is permitted for any annual or interim period for which an entity’s financial statements have not yet been previously issued or made available for issuance. We chose to adopt ASU 2014-08 as of September 30, 2014. There was no material impact on our consolidated financial statements.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. This ASU will supersede virtually all of the revenue recognition guidance in generally accepted accounting principles in the United States. The core principle of the five-step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. The provisions of ASU 2014-09 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. We have not yet determined the effect that adopting this ASU will have on our consolidated financial statements.
In August 2014, the FASB issued AU No. 2014-15, Presentation of Financial Statements - Going Concern. This ASU amends the accounting guidance for the presentation and disclosure of uncertainties about an entity’s ability to continue as a going concern. It requires management to evaluate and disclose whether there is substantial doubt about its ability to continue as a going concern. Management should consider relevant conditions or events that are known or reasonably known on the date the financial statements are issued. The provisions of ASU 2014-15 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. We do not expect that adopting this ASU will have a material impact on our consolidated financial statements.
No other new accounting pronouncements issued or effective during the year ended December 31, 2014 have had or are expected to have a material impact on our consolidated financial statements.
Subsequent Event
In February 2015, we amended our credit facility to include, among other things, an extension of the facility to February 2020, as well as an extension of our senior secured debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense (“EBITDAX”) covenant to March 31, 2016. In addition, the borrowing base under the facility was decreased to $650.0 million.
We evaluated subsequent events for appropriate accounting and disclosure through the date these consolidated financial statements were issued.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
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, 2014, 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
Equity Awards
We account for 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:
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:
The total grant date fair value of the phantom units vested in 2014, 2013 and 2012 was $11.9 million, $8.5 million and $4.8 million, respectively.
We recognized compensation cost related to these phantom units of $13.9 million, $11.9 million and $8.4 million in 2014, 2013 and 2012. These costs are included in “General and administrative expenses” in our consolidated statements of operations.
As of December 31, 2014, there was $24.0 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.8 years.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
Liability Awards
We accounted for phantom units issued prior to 2009 as liability awards, and the fair value of these phantom units was 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 was recognized for these phantom units based on the proportionate amount of the requisite service period that has been rendered to date and was net of estimated forfeitures. These phantom units were subject to graded vesting over a four year period.
The total fair value of the phantom units vested in 2013 and 2012 was $2.4 million and $2.8 million, respectively.
We recognized compensation cost related to these phantom units of $0.2 million and $2.5 million in 2013 and 2012, respectively. These costs are included in “General and administrative expenses” in our consolidated statements of operations.
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 market condition performance units using the Monte Carlo simulation model.
Activity related to these performance units is as follows:
The total grant date fair value of the performance units vested in 2014, 2013 and 2012 was $1.4 million, $1.6 million and $1.7 million, respectively.
We recognized compensation cost related to our performance units of $5.4 million, $5.4 million and $5.6 million in 2014, 2013 and 2012, respectively. These costs are included in “General and administrative expenses” in our consolidated statements of operations.
As of December 31, 2014, there was $0.2 million of total unrecognized compensation cost related to unvested performance units which is expected to be recognized in the first quarter of 2015.
NOTE 4. ACQUISITIONS
In March 2013, we received final purchase price settlements of $8.0 million related to our August 2012 acquisition of additional working interests in acreage in Ohio.
In November 2013, we, along with certain institutional partnerships managed by EnerVest, acquired natural gas properties in the Barnett Shale. We acquired a 31% proportional interest in these properties for an aggregate purchase price of $66.0 million, subject to customary purchase price adjustments. We recognized $1.4 million of oil, natural gas and natural gas liquids revenues related to these acquisitions in our consolidated statement of operations for 2013.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
We accounted for these acquisitions as business combinations. Pro forma results of operations have not been presented as the amounts would not be material to our consolidated statements of operations.
The recognized fair values of the identifiable assets acquired and liabilities assumed in connection with the November 2013 acquisitions are as follows:
The amounts included in the table above represented preliminary estimates of the fair values of the identifiable assets acquired and liabilities assumed for these acquisitions. The fair values were finalized in 2014 and resulted in no significant adjustment to the original purchase price allocation.
In February 2012 and March 2012, we, along with certain institutional partnerships managed by EnerVest, had additional closings 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 an aggregate purchase price of $36.5 million, subject to customary purchase price adjustments.
In April 2012, we received final purchase price settlements of $1.7 million related to our acquisitions of oil and natural gas properties in the Barnett Shale in December 2011.
In May 2012, we paid a final purchase price settlement of $0.9 million related to our acquisition of oil and natural gas properties in the Mid-Continent area in November 2011.
In November 2012, we acquired oil and natural gas assets for $1.1 million, subject to customary purchase price adjustments.
We accounted for these acquisitions as business combinations. Pro forma results of operations have not been presented as the amounts would not be material to our consolidated statements of operations.
In August 2012, we also acquired additional working interests in acreage in Ohio that we believe may be prospective for the Utica Shale for $75.2 million, after preliminary purchase price adjustments.
NOTE 5. DIVESTITURES
We, along with certain institutional partnerships managed by EnerVest, closed on the sale of certain deep rights in the Eagle Ford formation in Burleson, Brazos and Grimes Counties, Texas, and our share of the proceeds was $33.8 million. We retained all non-Eagle Ford formation rights, including the Austin Chalk formation and corresponding production. The transaction is subject to customary purchase price adjustments. Operating results related to the Eagle Ford formation were included in our exploration and production segment.
We closed on the sale of our nine percent interest in Cardinal for $161.1 million, which included certain purchase price adjustments and transaction-related expenses. The transaction is subject to additional customary purchase price adjustments. We recognized equity in income (loss) of unconsolidated affiliates related to our interest in Cardinal of $5.4 million, $1.2 million and $(0.1) million in 2014, 2013 and 2012, respectively, and these amounts were reported in our midstream segment.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
The assets and liabilities that were held for sale as of December 31, 2013 were sold for $5.8 million. In conjunction with the sale, we incurred an additional impairment charge of $0.2 million (see Note 8). Operating results related to these properties were included in our exploration and production segment.
In addition, we closed on the sale of additional Utica Shale acreage in Ohio and six non-core oil and natural gas wells in the Permian Basin for aggregate proceeds of $5.6 million.
We closed on sales of Utica Shale acreage in Ohio and received proceeds of $44.1 million for these acres.
In 2012, the assets and liabilities that were held for sale as of December 31, 2011 were sold for $5.5 million. We also sold non-core oil and natural gas wells for $0.5 million, which is recorded within accounts receivable as of December 31, 2012.
NOTE 6. INVESTMENTS IN UNCONSOLIDATED AFFILIATES
The most significant of our investments in unconsolidated affiliates are our 21% interest and, prior to October 2014, our 9% interest in Cardinal (see Note 5). Both of these investments are engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio.
Summarized balance sheet information for our significant investments in unconsolidated affiliates is as follows as of December 31:
(1)Balance sheet information is for UEO on a stand-alone basis.
(2)Balance sheet information is for UEO and Cardinal on a combined basis.
Summarized combined statement of operations information for our significant investments in unconsolidated affiliates is as follows for the years ended December 31:
(1)Statement of operations data for Cardinal is included through the date of divestiture (see Note 5).
As of December 31, 2014, the excess of our investment over our equity in UEO is $12.5 million. As of December 31, 2013, the excess of our investment over our equity in Cardinal and UEO is $8.2 million.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
NOTE 7. 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 the market price of oil, natural gas and natural gas liquids and interest rates. We use derivatives to reduce our risk of volatility in the prices of oil, natural gas and natural gas liquids and interest rates. Our policies do not permit the use of derivatives for speculative purposes.
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 earnings as “Gain (loss) on derivatives, net” in our consolidated statements of operations.
As of December 31, 2014, we had entered into oil and natural gas derivatives with the following terms:
As of December 31, 2014, we had also entered into interest rate swaps with the following terms:
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
The following table sets forth the fair values and classification of our outstanding derivatives:
We have entered into master netting arrangements with our counterparties. The amounts above are presented on a net basis in our consolidated balance sheets when such amounts are with the same counterparty. In addition, we have recorded accounts payable and receivable balances related to our settled derivatives that are subject to our master netting agreements. These amounts are not included in the above table; however, under our master netting agreements, we have the right to offset these positions against our forward exposure related to outstanding derivatives.
Should our credit facility become due and payable because of an event of default, our derivatives that are in a net liability position could also become due and payable. We could also be required to post cash collateral related to these derivatives under certain circumstances. As of December 31, 2014 and 2013, we were not required to post any collateral nor did we hold any collateral associated with our derivatives.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
NOTE 8. 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 on a recurring basis:
Our derivatives consist of over-the-counter (“OTC”) contracts which are not traded on a public exchange. 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 using the income approach using inputs such as 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, such as forward LIBOR curves. 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 2014.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
Nonrecurring 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 on a nonrecurring basis:
Long-lived Assets Held and Used
In 2014, as a result of a reduction in estimated future net cash flows primarily caused by the decrease in prices, oil and natural gas properties with an aggregate carrying amount of $186.1 million were written down to their fair value of $83.0 million, resulting in an aggregate impairment charge of $103.1 million. This impairment charge was included in earnings for 2014. In 2013, oil and natural gas properties with an aggregate carrying amount of $131.5 million were written down to their aggregate fair value of $55.2 million, resulting in an aggregate impairment charge of $76.3 million. This impairment charge was included in earnings for 2013. In 2012, oil and natural gas properties with an aggregate carrying amount of $66.1 million were written down to their aggregate fair value of $34.2 million, resulting in an aggregate impairment charge of $31.9 million. This impairment charge was included in earnings for 2012.
The fair values were determined using the income approach and were based on the expected present value of the future net cash flows from proved reserves. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.
Long-lived Assets Held for Sale
In 2014, we incurred an additional impairment charge of $0.2 million to write down assets held for sale at December 31, 2013 with a carrying amount of $6.0 million to their fair value of $5.8 million. This impairment charge was included in earnings for 2014. In 2013, we incurred an impairment charge of $0.5 million to write down assets held for sale to their fair market value of $8.0 million. This impairment charge was included in earnings for 2013. In 2012, we incurred additional impairment charges of $0.5 million to write down assets held for sale to their fair value of $6.0 million. These impairment charges were included in earnings for 2012.
The fair values were determined using Level 2 inputs consisting of the mutually agreed upon selling price we received upon the sale of these oil and natural gas properties.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
As of December 31, 2013, we have $8.0 million of oil and natural gas properties and $2.2 million of ARO classified as assets held for sale and liabilities held for sale, respectively in our consolidated balance sheets.
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, 2014 and December 31, 2013, the estimated fair value of our senior notes due 2019 was $427.5 million and $504.7 million, respectively, which differs from the carrying value of $499.4 million and $499.3 million, respectively. The fair value of the senior notes due 2019 was determined using Level 2 inputs.
NOTE 9. ASSET RETIREMENT OBLIGATIONS
The changes in the aggregate ARO are as follows:
As of both December 31, 2014 and 2013, $1.9 million of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our consolidated balance sheets. In addition, as of December 31, 2013, $2.2 million of our ARO was included in “Liabilities related to assets held for sale” in our consolidated balance sheets.
NOTE 10. LONG-TERM DEBT
Credit Facility
As of December 31, 2014, 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 oil and natural gas properties. 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 senior secured debt to EBITDAX of no greater than 3.5 to 1.0. As of December 31, 2014, we were in compliance with these financial covenants.
The facility does not require any repayments of amounts outstanding until it expires in April 2016. 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 2.98% and 3.09% at December 31, 2014 and 2013, respectively).
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, 2014, the borrowing base under the facility was $730.0 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.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
We had $531.0 million and $481.0 million outstanding under the facility at December 31, 2014 and 2013, respectively.
8.0% Senior Notes due 2019
We have $500.0 million outstanding of our 8.0% senior unsecured notes due 2019 (the “Notes”). 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. 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 fully and 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 the Parent nor Finance have independent assets or operations apart from the assets and operations of our subsidiaries.
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:
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.
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.
The aggregate carrying amount of the Notes was $499.4 million and $499.3 million at December 31, 2014 and December 31, 2013, respectively.
NOTE 11. 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, 2014 and 2013.
As of December 31, 2014, we expect our aggregate commitment to fund the construction activities for UEO to be between $26.0 million and $32.0 million for 2015.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
We have entered into a firm agreement for the future transportation and processing of natural gas. We are obligated to transport minimum daily natural gas volumes. As of December 31, 2014, our future minimum transportation fees under this agreement are as follows for the years ended December 31:
NOTE 12. OWNERS’ EQUITY
Units Outstanding
At December 31, 2014, owner’s equity consists of 48,572,019 common units outstanding (including 4,249,470 common units held by our executive officers and directors), collectively representing a 98% limited partnership interest in us, and a 2% general partnership interest.
Equity Offerings
In October 2013, we closed a public offering of 5.75 million common units at an offering price of $36.86 per common unit. We received net proceeds of $208.5 million, including a contribution of $4.2 million by our general partner to maintain its 2% interest in us.
In February 2012, we closed a public offering of 4.025 million of our common units at an offering price of $67.95 per common unit. We received net proceeds of $267.9 million, including a contribution of $5.4 million by our general partner to maintain its 2% interest in us.
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.
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.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
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 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.
The minimum quarterly distribution is not guaranteed and distributions below the minimum quarterly distribution will not be accrued in arrears.
Our general partner is entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:
The following sets forth the distributions we paid during the years ended December 31, 2014 and 2013:
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
On February 2, 2015, the board of directors of EV Management declared a $0.50 per unit distribution for the fourth quarter of 2014 on all common units. The distribution was paid on February 13, 2015 to unitholders of record at the close of business on February 9, 2015. The aggregate amount of the distribution was $25.2 million.
NOTE 13. 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:
(1)Unearned performance units totaling 0.2 million, 0.2 million and 0.8 million units were not included in the computation of diluted net income (loss) per limited partner unit for 2014, 2013 and 2012, respectively, because the effect would have been anti-dilutive.
NOTE 14. RELATED PARTY TRANSACTIONS
Pursuant to our omnibus agreement with EnerVest, we paid EnerVest $12.1 million, $10.0 million and $13.1 million in 2014, 2013 and 2012, respectively, in monthly administrative fees for providing us general and administrative services. These fees are based on an allocation of charges between EnerVest and us based on the estimated use of such services by each party, and we believe that the allocation method employed by EnerVest is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis. These fees are included in general and administrative expenses in our consolidated statements of operations.
We have entered into operating agreements with EnerVest whereby a subsidiary of 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. During 2014, 2013 and 2012, we reimbursed EnerVest approximately $17.0 million, $17.1 million and $17.5 million, respectively, for direct expenses incurred in the operation of our wells and related gathering systems and production facilities and for the allocable share of the costs of EnerVest employees who performed services on our properties. As the vast majority of such expenses are charged to us on an actual basis (i.e., no mark-up or subsidy is charged or received by EnerVest), we believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market and are representative of what the amounts would have been on a standalone basis. These costs are included in lease operating expenses in our consolidated statements of operations. Additionally, in its role as contract operator, this EnerVest subsidiary also collects proceeds from oil, natural gas and natural gas liquids sales and distributes them to us and other working interest owners.
In 2011, we and certain institutional partnerships managed by EnerVest carved out 7.5% overriding royalty interests ("ORRI") from certain acres in Ohio (the "Underlying Properties"), 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 and account for our investment using the equity method of accounting. We recognized $0.4 million, $0.2 million and $0.1 million of income from unconsolidated affiliates in 2014, 2013 and 2012, respectively, and we received $0.3 million and $0.2 million of distributions in 2014 and 2013, respectively.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
NOTE 15. OTHER SUPPLEMENTAL INFORMATION
Supplemental cash flows and non-cash transactions were as follows as of and for the years ended December 31:
Accounts payable and accrued liabilities consisted of the following as of December 31:
NOTE 16. QUARTERLY DATA (UNAUDITED)
(1)Represents total revenues less lease operating expenses, cost of purchased natural gas and production taxes.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
NOTE 17. SEGMENT INFORMATION
We have two reportable segments: exploration and production and midstream. Our exploration and production segment is responsible for the acquisition, development and production of our oil and natural gas properties. Our midstream segment, which consists of UEO and, through October 2014, Cardinal, is accounted for using the equity method of accounting and is engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio. All of our operations are located in the United States.
Management evaluates the performance of our segments based on segment profits, which include segment revenues and direct segment costs and expenses. Segment profit excludes items such as asset retirement obligations accretion expense, depreciation, depletion and amortization, general and administrative expenses, impairment of oil and natural gas properties, gain of sales of oil and natural gas properties, gain (loss) on derivatives, interest expense, gain on sale of investment in unconsolidated affiliate and other income or expense.
Summarized financial information for our operating segments is shown below:
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
The following table reconciles the segment profits reported above to loss before income taxes and (loss) income from unconsolidated affiliates for the years ended December 31:
NOTE 18. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS ACTIVITIES (UNAUDITED)
Capitalized costs relating to oil and natural gas producing activities are as follows at December 31:
Costs incurred in oil and natural gas property acquisition and development activities are as follows for the years ended December 31:
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
NOTE 19. ESTIMATED PROVED OIL, NATURAL GAS AND NATURAL GAS LIQUIDS RESERVES (UNAUDITED)
Our estimated proved reserves are all located within the United States. We caution that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are expected to change as further information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil, natural gas and natural gas liquids reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used in these estimates. The estimates of our proved reserves as of December 31, 2014, 2013 and 2012 have been prepared by Cawley, Gillespie, & Associates, Inc., independent petroleum consultants.
The following table sets forth changes in estimated proved and estimated proved developed reserves for the periods indicated.
(1)Thousands of barrels.
(2)Million cubic feet.
(3)Million cubic feet equivalent; barrels are converted to Mcfe based on one barrel of oil or natural gas liquids to six Mcf of natural gas equivalent
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
(4)Revisions were primarily attributable to decreased prices used in estimating our reserves (269.9 Bcfe) offset by positive development and production history (16.4 Bcfe).
(5)Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (39.0 Bcfe) and the Appalachian Basin (3.1 Bcfe).
(6)Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (177.1 Bcfe).
(7)Revisions were primarily attributable to the removal of 213.3 Bcfe of reserves that we had planned to develop at December 31, 2013, but based on current prices, we no longer expect to develop within the next five years.
(8)Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (78.2 Bcfe) and the Appalachian Basin (33.0 Bcfe).
NOTE 20. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL, NATURAL GAS AND NATURAL GAS LIQUIDS RESERVES (UNAUDITED)
The following tables present a standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil, natural gas and natural gas liquids reserves. In computing this data, assumptions other than those required by the SEC could produce different results. Accordingly, the data should not be construed as representative of the fair market value of our estimated proved oil, natural gas and natural gas liquids reserves. The following assumptions have been made:
·Future cash inflows were based on prices used in estimating our proved oil, natural gas and natural gas liquids reserves. Future price changes were included only to the extent provided by existing contractual agreements.
·Future development and production costs were computed using year end costs assuming no change in present economic conditions.
·In accordance with our standing as a non taxable entity, no provisions for future federal income taxes were computed; however, provisions for future obligations under the Texas gross margin tax were computed.
·Future net cash flows were discounted at an annual rate of 10%.
The standardized measure of discounted future net cash flows relating to estimated proved oil, natural gas and natural gas liquids reserves is presented below for the years ended December 31:
As specified by the SEC, the prices for oil, natural gas and natural gas liquids used in this calculation were the average prices during the year determined using the price on the first day of each month, except for volumes subject to fixed price contracts. The prices utilized in calculating our total estimated proved reserves at December 31, 2014, 2013 and 2012 were $94.99 per Bbl of oil, $4.35 per MMBtu of natural gas; $96.78 per Bbl of oil, $3.666 per MMBtu of natural gas; and $94.71 per Bbl of oil and $2.757 per MMBtu of natural gas, respectively. We do not include our commodity derivatives in the determination of our oil, natural gas and natural gas liquids reserves.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
The principal sources of changes in the standardized measure of future net cash flows are as follows for the years ended December 31:
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) issued an updated version of its Internal Control - Integrated Framework (the “2013 Framework”). Originally issued in 1992 (the “1992 Framework”), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. We adopted the 2013 Framework as of December 31, 2014.
Evaluation of Disclosure Controls and Procedures
In accordance with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2014 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to provide reasonable assurance that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control Over Financial Reporting
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management included a report of their assessment of the design and effectiveness of our internal controls over financial reporting as part of this Annual Report on Form 10-K for the fiscal year ended December 31, 2014. Deloitte & Touche LLP, our independent registered public accounting firm, has issued an attestation report on the effectiveness of our internal control over financial reporting. Management’s report and the independent registered public accounting firm’s attestation report are included in Item 8 under the caption entitled “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” and are incorporated herein by reference.
Change in Internal Controls Over Financial Reporting
There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended December 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
The information regarding the vesting of Mr. Houser’s phantom units, the changes in Mr. Mercer’s compensation and Mr. Bobrowski’s compensation set forth in this report on Form 10-K under the caption “Item 11. Executive Compensation - Compensation following 2015 Management Changes” is incorporated herein by reference.
The information regarding the amendment to our credit facility set forth under “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Long-Term Debt” is incorporated herein by reference. A copy of the amendment is filed as Exhibit 10.17 to this annual report on Form 10-K and incorporated herein by reference.
On February, 25, 2015, our Board of Directors, after receiving the recommendation of our conflicts committee, approved an extension of our Omnibus Agreement with EnerVest through the end of 2015, at a monthly fee of $1,096,160. A copy of the extension agreement is filed as Exhibit 10.6 to this annual report on Form 10-K and incorporated herein by reference.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
As is the case with many publicly traded partnerships, we do not directly employ officers, directors or employees. Our operations and activities are managed by EV Management, the general partner of our general partner. EV Management is a wholly owned subsidiary of EnerVest. References to our officers, directors and employees are references to the officers, directors and employees of EV Management.
Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of EV Management or directly or indirectly participate in our management or operation. Our general partner is owned 71.25% by EnerVest, 23.75% by EnCap and 5.00% by EV Investors. As of December 31, 2014, EV Investors is owned 70% by EnerVest and 30% by our senior management.
Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it.
Board Leadership Structure
Our board of directors has no policy regarding the separation of the positions of chief executive officer and chairman. We do not have a lead independent director. All of our directors are appointed by EnerVest, and EnCap is entitled to designate one director. Holders of our common units have limited voting rights on matters affecting our governance or business, subject to any unitholder rights set forth in our partnership agreement.
In selecting our independent board members, EnerVest sought candidates with experience in the energy business and in developing and implementing successful growth strategies and who have diverse expertise in areas important to our success. Directors were selected with strong professional reputations, a history of success, and who exemplify the highest standards of personal and professional integrity. Our independent directors were selected because they could be expected to constructively challenge management through their participation on our board of directors and its committees.
Board Oversight of Risk
Like all businesses, we face risks in our business activities. Many of these risks are discussed under the caption “Risk Factors” elsewhere in this annual report. Our board of directors has oversight of our risk management program, working directly with senior management. Our senior management, subject to board oversight, is responsible for ensuring that our risk management program, comprised of strategic, operational, financial, and legal risk identification and prioritization, is reflected in our policies and actions. Our senior management, subject to board oversight, is also responsible for day to day risk management and implementation of our risk management policies.
In addition, our audit committee considers our practices regarding risk assessment and risk management, reviews our contingent liabilities, reviews our reserve estimation practices, as well as major legislative and regulatory developments that could affect us. Our audit committee also oversees our code of business conduct and responses to any alleged violations of our policies made by whistleblowers. Our compensation committee reviews and attempts to mitigate risks which may result from our compensation policies, including working directly with senior management to determine whether such programs improperly encourage management to take risks relating to the business and/or whether risks arising from our compensation programs are likely to have a material adverse effect on us. Our conflicts committee reviews transactions in which we engage with affiliates of EnerVest or EnCap, and, if appropriate, approves these transactions or the manner in which any conflicts were resolved.
Our board of directors believes that this division of risk management related roles among our independent directors fosters an atmosphere of significant involvement in the oversight of risk and that this shared oversight is appropriate for us.
Recently Announced Management Changes
Mr. Houser has resigned his position as President and Chief Executive Officer of EV Management effective February 28, 2015. Mr. Houser will remain a director of EV Management. The board of directors appointed Mr. Mercer to replace Mr. Houser as President and Chief Executive Officer, effective March 1, 2015. The board also appointed Nicholas P. Bobrowski as Vice President and Chief Financial Officer to replace Mr. Mercer, also effective March 1, 2015. Mr. Bobrowski currently is our Director of Finance.
In addition, EnerVest has elected Mr. Mercer and Kenneth Mariani, President of EnerVest, Ltd., to the board of directors of EV Management effective March 1, 2015. The following sets forth information about Mr. Bobrowski and Mr. Mariani:
Nicholas P. Bobrowski, 37, has been Director of Finance of EV Management since 2013. From 2007 to 2012, Mr. Bobrowski was an energy investment banker with Citigroup Global Markets, where he rose to the level of Vice President in the Financial Strategy Group advising clients on valuation, liability, risk management and capital structure. Prior to that, he rose to the rank of Captain in the 25th Infantry Division of the United States Army after graduating with a BS in Economics from the United States Military Academy at West Point. Mr. Bobrowski also holds a MBA from the Sloan School of Management at MIT.
Kenneth Mariani, 53, currently serves as the President of EnerVest, Ltd., and has more than 30 years of executive leadership and operational management experience in the upstream oil and natural gas industry. He joined EnerVest in 2000 and was Senior Vice President and General Manager-Eastern Division for 11 years. He served as President and Chief Executive Officer of EnerVest Operating Company and Executive Vice President of EnerVest from January 2012 - January 2014. Prior to joining EnerVest, from 1991 to 2000, he served as Vice President of Operations for Energy Corporation of America (“ECA”), a privately held exploration and production company, and was responsible for engineering, land, geology and production operations. Prior to his role at ECA, he held various engineering positions at Conoco, Inc., in the Midland, TX, and Rocky Mountain Divisions. Mr. Mariani holds a degree in Chemical Engineering from the University of Pittsburgh, graduating cum laude with a petroleum option. He received his Master of Business Administration from The University of Texas (Permian Basin) and is a licensed Professional Engineer. Mr. Mariani serves on the Board of Directors of AXPC - American Exploration and Production Council. He is an active member of various independent oil and natural gas associations, and recently served on the Board of Directors in the Michigan, Ohio and West Virginia associations. Mr. Mariani is past Chairman of the Society of Petroleum Engineers and is a member of IPAA.
Directors and Executive Officers
All of our executive management personnel, other than Mr. Mercer, are employees of EnerVest. Mr. Mercer is an employee of EV Management and devotes all of his time to our business and affairs.
We estimate that Messrs. Walker, Houser and Flory devote approximately 25%, 50% and 35%, respectively, of their time to our business. We also utilize a significant number of employees of EnerVest to operate our properties and provide us with certain general and administrative services. Under the omnibus agreement, we pay EnerVest a fee for its operational personnel who perform services for our benefit. During 2014, we paid EnerVest $12.1 million for general and administrative services, which fee will increase or decrease as we purchase or divest assets or as the costs to provide these services increase or decrease.
The following table shows information as of February 13, 2015 regarding members of our Board of Directors and executive officers of EV Management. Members of our Board of Directors are elected for one-year terms.
Name
Age
Position with EV Management
John B. Walker
Executive Chairman and Director
Mark A. Houser (1)
President, Chief Executive Officer and Director
Michael E. Mercer
Senior Vice President and Chief Financial Officer
Ryan J. Flory
Controller
Victor Burk (2) (3)
Director
James R. Larson (2)
Director
George Lindahl III (2) (3)
Director
Gary R. Petersen (3)
Director
(1)Mr. Houser resigned his position as President and Chief Executive Officer effective February 28, 2015, and Mr. Mercer was appointed President and Chief Executive Officer, and a director, effective March 1, 2015. In addition, Nicholas Bobrowski will replace Mr. Mercer as Vice President and Chief Financial Officer of EV Management effective March 1, 2015.
(2)Member of the audit committee and the conflicts committee.
(3)Member of the compensation committee.
John B. Walker has served as our Executive Chairman since January 2012 and has been a director since 2006. Prior to serving as Executive Chairman, he served as our Chairman and Chief Executive Officer since 2006. Mr. Walker also serves as the Chief Executive Officer of EnerVest, Ltd. from its inception in 1992, and was the President of EnerVest, Ltd. from its formation in 1992 until 2014. He has been Chief Executive Officer of EnerVest, Ltd. since 2014. Prior to that, Mr. Walker was President and Chief Operating Officer of Torch Energy Advisors Incorporated, a company which formed and managed partnerships for institutional investors in the oil and natural gas business, and Chief Executive Officer of Walker Energy Partners, a master limited partnership engaged in the exploration and production business. In his early career on Wall Street, Mr. Walker was selected by Institutional Investor as an “All American” energy analyst for six years in a row. He served the Independent Petroleum Association of America (IPAA) as Chairman from 2003 - 2005. In November 2007, he received the oil and natural gas industry’s highest award, the Chief Roughneck Award. He is a member of the National Petroleum Council and All-American Wildcatters. He serves or has served on the boards of the Houston Producers’ Forum, Foundation for Energy Education, Petroleum Club of Houston, and the Texas Independent Producers and Royalty Owners Association. His civic activities include having served as Chairman of the Board of Stewards of Chapelwood United Methodist Church and Chairman of the Board of Directors of the Sam Houston Area Council of the Boys Scouts of America. In 2001, he received the Silver Beaver Award and in May 2007 the Distinguished Eagle from the Boy Scouts of America. In 2004, he was named Distinguished Alumni at Texas Tech University and, in January 2012, he was appointed by Gov. Rick Perry to serve on the Board of Regents. He holds a BBA with Honors from Texas Tech University and an MBA (with distinction) from New York University.
Mark A. Houser has served as our President and Chief Executive Officer since January 2012. Prior to that, he served as our President and Chief Operating Officer since 2006. He also serves as Executive Vice President and Chief Operating Officer of EnerVest, Ltd. since 1999. Prior to that, Mr. Houser was Vice President, United States Exploration and Production, for Occidental Petroleum Corporation (“Oxy”), where he helped lead Oxy’s reorganization of its domestic reserve base, including the successful $3.65 billion acquisition of the Elk Hills Naval Petroleum Reserve. In 1989 he joined Canadian Occidental Petroleum, Ltd. (now Nexen Inc.), where he held positions of increasing responsibility, including Vice President of Corporate Planning and Investor Relations in Calgary and Vice President of Exploration for CXY Energy, Canadian Oxy’s United States subsidiary. Mr. Houser began his career as an engineer with Kerr-McGee Corporation. He holds a petroleum engineering degree from Texas A&M University and an MBA from Southern Methodist University. Mr. Houser serves as the chairman of the industry board of the Texas A&M University Department of Petroleum Engineering and is a member of the Society of Petroleum Engineers. Mr. Houser was recently inducted into the Texas A&M Petroleum Engineering Academy of Distinguished Graduates. Additionally, he serves on the board of directors for the Methodist Hospital System and on the administrative board of Chapelwood United Methodist Church. Mr. Houser resigned as our President and Chief Executive Officer effective February 28, 2015.
Michael E. Mercer has served as our Senior Vice President and Chief Financial Officer since 2006. He was a consultant to EnerVest, Ltd. from 2001 to 2006. Prior to that, Mr. Mercer was an investment banker for 12 years. He was a Director in the Energy Group at Credit Suisse First Boston in Houston and a Director in the Energy Group at Salomon Smith Barney in New York and London. He holds a BBA in Petroleum Land Management from the University of Texas at Austin and an MBA from the University of Chicago Booth School of Business. Mr. Mercer was appointed our President and Chief Executive Officer, and director, effective March 1, 2015.
Ryan J. Flory has served as Controller of EV Management since February 2014 and as Vice President and Controller of EnerVest, Ltd. since January 2014. Prior to that, Mr. Flory served as Corporate Controller of EnerVest, Ltd. since 2013. From 2005 to 2013, he served as Manager of Financial Reporting for EnerVest, Ltd, and from 2003 to 2005, he worked for Belden & Blake Corporation where he held various management and supervisory positions. Mr. Flory began his career with Deloitte & Touche. He holds a Bachelor’s of Business Administration, Accounting, from Kent State University and is a CPA and a member of the American Institute of Certified Public Accountants.
Victor Burk was appointed to our board of directors in September 2006. Since 2009, Mr. Burk has been a Managing Director for Alvarez and Marsal, a privately owned professional services firm. From 2005 to 2009, Mr. Burk was the global energy practice leader for Spencer Stuart, a privately owned executive recruiting firm. Prior to joining Spencer Stuart, Mr. Burk served as managing partner of Deloitte & Touche’s global oil and natural gas group from 2002 to 2005. He began his professional career in 1972 with Arthur Andersen and served as managing partner of Arthur Andersen’s global oil and natural gas group from 1989 until 2002. Mr. Burk is a current board member of PAA GP Holdings, LLC, the general partner of Plains GP Holding, L.P. (NYSE: PAGP). He is also a board member of the Independent Petroleum Association of America (Southeast Texas Region) and Sam Houston Area Council of the Boy Scouts of America. He holds a BBA in Accounting from Stephen F. Austin University, graduating with highest honors. Mr. Burk has over 30 years of experience in the oil and natural gas industry, with extensive experience in public accounting and consulting. Mr. Burk brings to our board wide expertise in financial and accounting matters relating to the oil and natural gas industry as well as providing leadership in complex business organizations.
James R. Larson was appointed to our board of directors in September 2006. Since January 1, 2006, Mr. Larson has been retired. From September 2005 until January 1, 2006, Mr. Larson served as Senior Vice President of Anadarko Petroleum Corporation. From December 2003 to September 2005, Mr. Larson served as Senior Vice President, Finance and Chief Financial Officer of Anadarko. From 2002 to 2003, Mr. Larson served as Senior Vice President, Finance of Anadarko where he oversaw treasury, investor relations, internal audits and acquisitions and divestitures. From 1995 to 2002, Mr. Larson served as Vice President and Controller of Anadarko where he was responsible for accounting, financial reporting, budgeting, forecasting and tax. Prior to that, he held various tax and financial positions within Anadarko after joining the company in 1981. Mr. Larson is a current member of the American Institute of Certified Public Accountants, Financial Executives International, Tax Executives Institute and the National Association of Corporate Directors. Mr. Larson also serves on the board of CSI Compressco GP Inc., general partner of CSI Compressco L.P. He holds a BBA in Business from the University of Iowa. Mr. Larson has over 30 years of experience in the oil and natural gas business, and has served as chief financial officer of a large independent oil and natural gas company. We believe that his knowledge of the industry and finance and accounting provide a critical resource and skill set to our board of directors.
George Lindahl III was appointed to our board of directors in September 2006. From 2007 to the present, Mr. Lindahl manages GL III Investments. From 2001 to 2007, he was a Managing Partner for Sandefer Capital Partners. From 2000 to 2001 he served as Vice Chairman of Anadarko Petroleum Corporation. From 1987 to 2000, he was with Union Pacific Resources, serving as President and Chief Operating Officer from 1996 to 1999 and as Chairman, President and CEO from 1999 to 2000. He holds a BS in Geology from the University of Alabama and has completed the Advanced Management program at Harvard Business School. Mr. Lindahl has extensive geological and engineering experience, as well as leadership skills and a proven track record of successful investments in the oil and natural gas business. We believe that Mr. Lindahl’s technical knowledge and experience and his leadership skills provide an important resource to our board of directors.
Gary R. Petersen was appointed to our board of directors in September 2006. Mr. Peterson is a Managing Partner and co-founder of EnCap Investments L.P., an investment manager and leading provider of private equity capital to the upstream and midstream sectors of the oil and natural gas industry. The firm has raised 17 institutional oil and natural gas investment funds totaling approximately $18 billion and currently manages capital on behalf of more than 250 U.S. and institutional investors. Prior to the formation of EnCap Investments in 1988, Mr. Petersen was a Senior Vice President and Manager of the Corporate Finance Division of the Energy Banking Group for Republic Bank Corporation from 1985 to 1988. His duties and responsibilities included mergers and acquisitions, financial advisory services and institutional fund raising activities for the energy industry. Prior to his position at Republic Bank, Mr. Petersen was an Executive Vice President and a member of the board of directors of Nicklos Oil & Gas Company in Houston from 1979 to 1984. Previously, Mr. Petersen was a Group Vice President in the Petroleum and Minerals Division of Republic Bank Dallas. He served from 1970 to 1971 in the U.S. Army in Washington D.C. as a First Lieutenant in the Finance Corps and as an Army Officer in the Army Security Agency. Mr. Petersen is a distinguished Alumni of Texas Tech University and holds B.B.A. and M.B.A. degrees in Finance. He has also done post-graduate work at American University and the Stonier Graduate School of Banking at Rutgers University. Mr. Petersen serves on the board of multiple EnCap portfolio companies and is a member of the board of directors of the general partner of Plains All American Pipeline, L.P. (NYSE: PAA) and Canacol Energy Ltd. (TSXV: CNE). He is a member of the Independent Petroleum Association of America, the Houston Producers’ Forum and the Petroleum Club of Houston. He is also a member and past Chairman of Chapelwood United Methodist Church, Chairman of the Memorial Hermann Healthcare Foundation and a past Chairman of the Council on Alcohol and Drugs in Houston. Mr. Petersen brings to our board the expertise he has acquired from being involved in the energy sector for more than 30 years, including extensive knowledge of the energy sector’s various cycles, as well as the current market and industry knowledge that comes with management of approximately $11 billion of energy-related investments.
Composition of the Board of Directors
During 2014, EV Management’s board of directors consisted of six members, one of which, Mr. Petersen, was appointed by EnCap, and the remainder of which were appointed by EnerVest. Effective March 1, 2015, the board was expanded to eight members, and EnerVest elected Mr. Mercer and Mr. Mariani as directors.
EV Management’s board of directors holds regular and special meetings at any time as may be necessary. Regular meetings may be held without notice on dates set by the board from time to time. Special meetings of the board may be called with reasonable notice to each member upon request of the chairman of the board or upon the written request of any three board members. A quorum for a regular or special meeting will exist when a majority of the members are participating in the meeting either in person or by telephone conference. Any action required or permitted to be taken at a board meeting may be taken without a meeting, without prior notice and without a vote if all of the members sign a written consent authorizing the action.
Unitholder Communications
Interested parties can communicate directly with non-management directors by mail in care of EV Energy Partners, L.P., 1001 Fannin Street, Suite 800, Houston, Texas 77002. Such communications should specify the intended recipient or recipients. Commercial solicitations or communications will not be forwarded.
Committees of the Board of Directors
EV Management’s board of directors established an audit committee, a compensation committee and a conflicts committee. The charters for our audit and compensation committees are posted under the “Investor Relations” section of our website at www.evenergypartners.com. Our conflicts committee was created in our partnership agreement and does not have a charter.
Because we are a limited partnership, the listing standards of the NASDAQ do not require that we or our general partner have a majority of independent directors or a nominating or compensation committee of the board of directors. We are, however, required to have an audit committee, a majority of whose members are required to be “independent” under NASDAQ standards as described below.
Audit Committee
The audit committee is comprised of Messrs. Larson (Chairman), Burk and Lindahl, all of whom meet the independence and experience standards established by the NASDAQ and the Exchange Act. The board of directors has determined that each of Messrs. Larson and Burk is an “audit committee financial expert” as defined under SEC rules.
The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee also reviews our reserve estimation processes.
The audit committee has the sole authority and responsibility to retain and terminate our independent registered public accounting firm, resolve disputes with such firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and meets with the audit committee on a regularly scheduled basis. During 2014, representatives of our independent registered public accounting firm attended all of our audit committee meetings. The audit committee may also engage the services of advisors and accountants as it deems advisable.
Compensation Committee
Although not required by the listing requirements of the NASDAQ, the board of directors established and maintains a compensation committee comprised of non-employee directors. The compensation committee is comprised of Messrs. Lindahl (Chairman), Burk and Petersen. The compensation committee reviews the compensation and benefits of our executive officers, establishes and reviews general policies related to our compensation and benefits and administers our long-term incentive plan (the “Plan”).
Conflicts Committee
The conflicts committee is comprised of Messrs. Burk (Chairman), Larson and Lindahl, all of whom meet the independence standards established by the NASDAQ. The conflicts committee reviews specific matters that our management or board of directors believes may involve conflicts of interest. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.
Meetings and Other Information
During 2014, the board of directors had five regularly scheduled and special meetings, the audit committee had four meetings, the compensation committee had one meeting and the conflicts committee had seven meetings. None of our directors attended fewer than 75% of the aggregate number of meetings of the board of directors and committees of the board on which the director served.
Our partnership agreement provides that the general partner manages and operates us and that, unlike holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business or governance. Accordingly, we do not hold annual meetings of unitholders.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires executive officers and directors of EV Management and persons who beneficially own more than 10% of a class of our equity securities registered pursuant to Section 12 of the Exchange Act to file certain reports with the SEC and the NASDAQ concerning their beneficial ownership of such securities.
Based solely on a review of the copies of reports on Forms 3, 4 and 5 and amendments thereto furnished to us and written representations from the executive officers and directors of EV Management, we believe that during 2014, the officers and directors of EV Management and beneficial owners of more than 10% of our equity securities registered pursuant to Section 12 were in compliance with the applicable requirements of Section 16(a).
Code of Business Conduct
The corporate governance of EV Management is, in effect, the corporate governance of our partnership, subject in all cases to any specific unitholder rights contained in our partnership agreement.
EV Management has adopted a code of business conduct that applies to all officers, directors and employees of EV Management and its affiliates. A copy of our code of business conduct is available on our website at www.evenergypartners.com. We will provide a copy of our code of business conduct to any person, without charge, upon request to EV Management, LLC, 1001 Fannin, Suite 800, Houston, Texas 77002, Attn: Corporate Secretary.
Reimbursement of Expenses of our General Partner
Our general partner does not receive any management fee or other compensation for its management of our partnership. Under the terms of the omnibus agreement, we pay EnerVest a fee for general and administrative services undertaken for our benefit and for our allocable portion of the premiums on insurance policies covering our assets. In addition, we reimburse EV Management for the costs of employee, officer and director compensation and benefits properly allocable to us, as well as for other expenses necessary or appropriate to the conduct of our business and properly allocable to us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Because our general partner is a limited partnership, its general partner, EV Management, manages our operations and activities. We do not directly employ any of the persons responsible for managing our business. Mr. Mercer is, and prior to April 2014, Dr. Gajdica was, an employee of EV Management, and we reimburse EV Management for the costs of their compensation. Mr. Mercer does not currently perform services for EnerVest or its affiliates (other than EV Management). Their compensation was, and Mr. Mercer’s will continue to be, approved by the compensation committee of EV Management’s board of directors, which we refer to as our compensation committee. In addition, following his appointment as our Vice President and Chief Financial Officer effective March 1, 2015, Mr. Bobrowski’s compensation will be approved by our compensation committee.
Messrs. Walker and Houser (until his resignation effective February 28, 2015) are officers of EV Management and also are officers and employees of other subsidiaries of EnerVest. In these capacities, they perform services for us as well as for EnerVest and its other affiliates. In order to compensate Messrs. Walker and Houser for the time they devote to our business and to provide our compensation committee with oversight of the portion of their annual bonuses reflecting their services to us, a portion of their cash bonus was reviewed and approved by our compensation committee, and we reimburse EnerVest for these cash bonuses. In addition, Messrs. Walker and Houser (subject to the terms of his resignation effective February 28, 2015) continue to participate in the Plan.
Our compensation committee discusses with EnerVest the philosophy used by EnerVest in setting the salaries and bonus compensation for its employees who perform services for us under the omnibus agreement. However, except for the bonus payments noted in the previous paragraph, the compensation committee has no role in determining the base salary and short-term and long-term incentive compensation paid to EnerVest employees. We pay EnerVest a fee under the omnibus agreement which is based in part on the compensation paid to EnerVest employees who perform work for us, but other than the portion of Messrs. Walker’s and Houser’s cash bonus charged to us, we do not directly reimburse EnerVest for the costs of the compensation of Messrs. Walker and Houser and our compensation committee does not oversee their annual compensation. Awards made to Messrs. Walker and Houser and other employees of EnerVest under the Plan are determined by our compensation committee.
Our compensation committee has overall responsibility for the approval, evaluation and oversight of all of our compensation programs. The committee’s primary purpose is to assist the board of directors in the discharge of its fiduciary responsibilities relating to fair and competitive compensation. The compensation committee meets in the fourth quarter of each year to review the compensation program and to determine cash compensation levels for the ensuing fiscal year and long term incentive awards for the then current fiscal year. The compensation committee may meet at other times as required.
Objectives of Our Compensation Program
Our executive compensation program is intended to align the interests of our management team with those of our unitholders by motivating our executive officers to achieve strong financial and operating results for us, which we believe closely correlate to long-term unitholder value. In addition, our program is designed to achieve the following objectives:
·attract and retain talented executive officers by providing reasonable total compensation levels competitive with that of executives holding comparable positions in similarly situated organizations;
·provide total compensation that takes into account individual performance;
·provide performance-based compensation that balances rewards for short-term and long-term results and is tied to both individual and our performance; and
·encourage the long-term commitment of our executive officers to us and our unitholders’ long-term interests.
What Our Compensation Program is Designed to Reward
Our compensation program is designed to reward performance that contributes to the achievement of our business strategy on both a short-term and long-term basis. The primary long-term measure of our performance is our ability to sustain or increase our quarterly distributions to our unitholders. In addition, we reward qualities that we believe help achieve our strategy such as teamwork; individual performance in light of general economic and industry specific conditions; performance that supports our core values; resourcefulness; the ability to manage our existing assets; the ability to explore new avenues to increase oil, natural gas and natural gas liquids production and reserves; level of job responsibility; and tenure.
Compensation Consultant
Our compensation committee did not retain an independent compensation consultant. Since 2010, EnerVest has retained Longnecker & Associates to provide compensation advice and data to EnerVest regarding its employees, including our executive officers. In general, the role of the outside compensation consultant is to assist EnerVest with the analysis of executive pay packages; however EnerVest is under no obligation to follow the advice or recommendations of any compensation consultant.
EnerVest provided our compensation committee with a summary of Longnecker & Associates’ analysis of the compensation of EnerVest employees who perform services for us, as well as Mr. Mercer, which the committee considered in approving the compensation of our executive officers. Like EnerVest, the compensation committee is under no obligation to follow the advice or recommendations on any compensation consultant. In conducting its analysis, Longnecker & Associates took into account factors including: current compensation for the named executives and directors, size of the company compared to the peer group, market talent pool conditions and market trends, commodity market factors, company performance, executive responsibility as compared to similar positions in the market and competitive compensation within the our market.
Benchmarking
As part of the proposed compensation plan, our chief executive officer asked Longnecker & Associates to prepare an analysis of the compensation paid (based on survey data and proxy analysis) by a peer group composed of the following companies: Atlas Resource Partners, L.P., Bill Barrett Corp., BreitBurn Energy Partners, L.P., Carrizo Oil & Gas, Inc., Comstock Resources, Inc.; Laredo Petroleum Holdings, Inc., Legacy Reserves LP, Linn Energy, LLC, Magnum Hunter Resources Corp.; Matador Resources Company; Memorial Production Partners, L.P., PDC Energy, Inc., Penn Virginia Corporation; Sanchez Energy Corporation; and Vanguard Natural Resources, LLC. The compensation committee reviews the composition of the peer group each year. Longnecker & Associates reviewed peer group and survey data and made recommendations regarding executive and director compensation.
In connection with setting base salary for 2015 and bonus and long-term equity incentive compensation for 2014, our management and compensation committee used information regarding peer companies to check their base salary and bonus compensation decisions for reasonableness and to benchmark with respect to base salary, bonus and long-term equity incentive compensation.
Performance Metrics
With respect to bonus and long-term incentive awards, our compensation committee did not establish performance metrics for our executive officers for 2014 in order to remain flexible in our compensation practices. The compensation committee makes a subjective determination at the end of the fiscal year as to the appropriate compensation based on a recommendation from our chief executive officer and given their view of our performance for the year.
Elements of Our Compensation Program and Why We Pay Each Element
To accomplish our objectives, we seek to offer a total direct compensation program to our executive officers that, when valued in its entirety, serves to attract, motivate and retain executives with the character, experience and professional accomplishments required for our growth and development. Our compensation program is comprised of four elements:
·base salary;
·cash bonus;
·long-term equity-based compensation; and
·benefits.
While the allocation of total compensation among base salary, cash bonus and long-term incentive compensation will vary from year to year based on performance and market conditions, we generally allocate a greater portion of total compensation to long-term equity based compensation because we believe this better aligns the interests of our executives with those of our unit holders. In addition, the annual grant of phantom units under the Plan is intended to provide an incentive to our key employees to focus their efforts on increasing the market price of our publicly traded common units and to increase the cash distributions we pay to our unitholders.
In 2011, EnerVest established the EnerVest Ltd. Retirement Plan (the "Retirement Plan"), a defined benefit plan under ERISA, for certain of the officers and other highly compensated employees of EnerVest and its subsidiaries. The purpose of the Retirement Plan is to provide a company funded tax-qualified plan for retirement benefits on a tax advantaged basis. Employees who are eligible to participate in the Retirement Plan receive their cash compensation in two forms: (i) base salary and annual bonus, subject to applicable taxes and withholdings and (ii) a fully vested annual company contribution to the Retirement Plan. Therefore, the overall level of compensation is not enhanced for the Retirement Plan participants because a portion of compensation is contributed to the Retirement Plan by the company in lieu of current cash compensation. The participants accrue a benefit based on their age, designated "allocation group," the investment yield on the Retirement Plan’s assets and other factors, subject to the limits on benefits prescribed under the Internal Revenue Code. The benefit is payable in various annuity forms or as a lump sum. All benefit election forms are actuarially equivalent, and there are no subsidies to any election.
At the time of the adoption of the Retirement Plan, EnerVest amended its 401(k) Plan with regard to EnerVest’s contributions. Under the 401(k) Plan, all employees who are eligible to participate receive a 3% "safe harbor" contribution from EnerVest. EnerVest may also make an additional discretionary "safe harbor" contribution to all employees who are entitled to participate in the 401(k) plan. In addition, under the 401(k) plan, EnerVest may make a discretionary profit sharing contribution that is allocated to participant accounts based on their designated "allocation group." The allocation groups are structured so that certain of the officers and other highly paid employees receive a profit sharing contribution that is a greater percentage of compensation than the percentage applicable to other participants.
Mr. Mercer participates, and Dr. Gajdica participated, in the Retirement Plan and received discretionary profit sharing 401(k) contributions in an allocation group which paid a higher percent of their compensation than allocated to other participants.
When setting base salary for 2014 for Mr. Mercer and Dr. Gajdica, the total base salary (“Total Base Salary”), inclusive of the amount delivered in cash and in company contributions under the Retirement Plan, was considered. We reimburse EnerVest for any amounts contributed to the Retirement Plan and the 401(k) plan attributable to Mr. Mercer and Dr. Gajdica. In the Summary Compensation Table, the present value of benefits under the Retirement Plan are reflected under the column “Change in Pension Value and Nonqualified Deferred Compensation Earnings” and the contributions to the 401(k) plan are included under “All Other Compensation.” Additional information about the Retirement Plan is set forth under “-Retirement Plan,” below.
Base Salary
We pay base salary in order to recognize each executive officer's unique value and historical contributions to our success in light of salary norms in the industry and the general marketplace; to match competitors for executive talent; to provide executives with sufficient, regularly-paid income; and to reflect position and level of responsibility.
To provide stability and appropriate incentive, Mr. Mercer is party to an employment agreement which sets his minimum base salary per annum. In the compensation committee’s discretion, however, his base salary may be increased based upon performance and subjective factors.
For 2014, after comparing our executives’ base salary with our peer group, and based on the recommendation of our chief executive officer, the compensation committee targeted Total Base Salary at approximately the 25th percentile of the peer group. This resulted in a Total Base Salary for Mr. Mercer of $275,000, which compares with a Total Base Salary of $262,253 for 2013. Of these amounts, $89,261 and $84,608 represent the estimates of the amounts to be contributed to the Retirement Plan for 2014 and 2013, respectively, so Mr. Mercer’s salary delivered in cash was $185,739 and $177,645 for 2014 and 2013, respectively. For 2014, the compensation committee set the Total Base Salary for Dr. Gajdica at $265,000, which compares with a Total Base Salary of $256,789 for 2013. Of these amounts, $76,016 and $72,053 represent the estimate of the amounts to be contributed to the Retirement Plan for 2014 and 2013, respectively. Dr. Gajdica’s salary delivered in cash for 2013 was $184,736. Dr. Gadjica’s employment with us terminated in April 2014. As a result, he did not receive his full annual salary. His actual pro rated base salary received for 2014 was $65,407 delivered in cash with $25,339 actually contributed to the Retirement Plan.
For 2015, after comparing Mr. Mercer’s base salary with our peer group, and based on the recommendation of our chief executive officer, the committee approved Mr. Mercer’s salary for 2015 at $286,000. The committee targeted Mr. Mercer’s total direct compensation (base salary, bonus and long-term incentive) between the 25th and 50th percentile of the peer group.
Cash Bonus
We include an annual cash bonus as part of our compensation program because we believe this element of compensation helps to motivate management to achieve key operational objectives by rewarding the achievement of these objectives. The annual cash bonus also allows us to be competitive from a total remuneration standpoint. Our compensation committee reviewed and approved a portion of the cash bonuses paid to Messrs. Walker and Houser.
Mr. Mercer’s employment agreement provides that the cash bonus element of compensation will be equal to a percentage of the executive's Total Base Salary paid during each such annual period, such percentage to be established by the compensation committee in its sole discretion. Generally, for Mr. Mercer, our compensation committee targets between 40% and 80% of Total Base Salary for performance deemed by our compensation committee to be good and exceptional, respectively, with the possibility of no bonus for poor performance and higher for exceptional corporate or individual performance.
Our chief executive officer recommended the cash bonus to be paid to Mr. Mercer. In this recommendation and the employment agreement, the compensation committee, in determining the cash bonus amount, took into account its belief that Mr. Mercer’s efforts directly affected our success in 2014, in particular, by contributing to our achievement of the following milestones:
·our quarterly distributions increased from $0.771 per unit to $0.774 per unit, notwithstanding a challenging commodity price environment;
·we achieved strong operating performance within production guidance, even with reduced capital spending;
·we, along with certain institutional partnerships managed by EnerVest, closed on the sale of certain deep rights in the Eagle Ford formation, and our share of the proceeds was $33.8 million; and
·we closed on the sale of our 9% interest in Cardinal for $161.1 million.
In 2014, Mr. Mercer received a cash bonus of $225,000, representing 82% of his Total Base Salary, which amount placed Mr. Mercer between the 25th and 50th percentiles of cash bonus compensation of our peer group. The bonus for Mr. Mercer also reflected the committee’s determination that his performance in accomplishing the milestones for 2014 described above was very strong.
In addition, each of Messrs. Walker and Houser were awarded cash bonuses of $150,000, representing a portion of their total annual compensation paid by us and EnerVest. The amount of bonuses were recommended to our compensation committee by Messrs. Walker and Houser based on their subjective view as to appropriate compensation levels taking into account the performance milestones discussed above and, in the case of Messrs. Walker and Houser, the amount of time they spent on our business activities. The compensation committee then determined to accept these recommendations.
In connection with Dr. Gajdica’s termination of employment in April 2014, he received a separation payment of $700,000 pursuant to a separation agreement entered into between Dr. Gajdica and EV Management.
Long-term Equity-based Compensation
Long-term equity-based compensation is an element of our compensation policy because we believe it aligns executives’ interests with the interests of our unitholders; rewards long-term performance; is required in order for us to be competitive from a total remuneration standpoint; encourages executive retention; and gives executives the opportunity to share in our long-term performance. We generally seek to allocate a greater portion of total compensation to long-term equity compensation, generally targeting between the 50th and 75th percentiles of our peer group for such compensation, with higher amounts for performance our compensation committee views as exceptional.
The compensation committee acts as the administrator of the Plan and performs functions that include selecting award recipients (or the manner in which such recipients will be chosen), determining the timing of grants and assigning the number of units subject to each award (or the manner in which such assignments will be made), fixing the time and manner in which awards are exercisable, setting exercise prices and vesting and expiration dates, and from time to time adopting rules and regulations for carrying out the purposes of our plan. For compensation decisions regarding the grant of equity compensation to executive officers, our compensation committee will consider recommendations from our chief executive officer. Typically, awards vest over multiple years, but the compensation committee maintains the discretionary authority to vest the equity grant immediately if the individual situation merits. In the event of a termination of employment upon a change of control, all outstanding equity based awards will immediately vest. In the event of termination of a grantee’s employment upon the death, disability, or termination of a grantee’s employment without good reason, all outstanding equity based awards will vest effective upon the normal vesting date that coincides with, or immediately follows, the termination. We have provided for full acceleration provisions in the equity award agreements under our Plan upon a change in control because we believe that it is important to provide the named executive officers with a sense of stability in the middle of transactions that may create uncertainty regarding their future employment as well as maximize unitholder value by encouraging the named executive officers to review objectively any proposed transaction in determining whether such proposal is in the best interest of our unitholders, whether or not the executive will continue to be employed.
The Plan permits the compensation committee to delegate its authority to grant awards, except for awards to executive officers and directors, to one or more of our executive officers.
We have no set formula for granting awards to our executives or employees. In determining whether to grant awards and the amount of any awards, our compensation committee takes into consideration discretionary factors such as the individual’s current and expected future performance, level of responsibility, retention considerations and the total compensation package.
Awards under the Plan may be unit options, phantom units, performance units, restricted units and deferred equity rights, or DERs, and the aggregate amount of our common units that may be awarded under the Plan is 4.5 million units. As of December 31, 2014, there are 1.9 million units available for issuance. 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.
Although the Plan generally provides for the grant of unit options, Internal Revenue Code Section 409A and authoritative guidance thereunder provides that options can generally only be granted to employees of the entity granting the option and certain affiliates without being required to comply with Section 409A as nonqualified deferred compensation. Until further guidance is issued by the Treasury Department and Internal Revenue Service under Section 409A, we do not intend to grant unit options.
In addition, because we are a partnership, tax and accounting conventions make it more costly for us to issue additional common units or options as incentive compensation. Consequently, we have no outstanding options or restricted units and have no plans to issue options or restricted units in the future. Instead, we have issued phantom units and performance units to our executive officers. A phantom unit is the right to receive, upon satisfaction of the vesting criteria specified in the grant, a common unit or, at the discretion of our compensation committee, cash based on the average closing price of our common units for the five day trading period prior to vesting. The phantom units typically vest in equal annual installments over a four year period beginning January 15th of the year following the first full year after the date of grant. Unlike “vesting” of an option, vesting of a phantom unit results in the delivery of a common unit or cash equivalent value as opposed to a right to exercise. These phantom and performance unit awards entitle the recipients of the unit awards to receive, with respect to each unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per units made by us on our units promptly following each such distribution by us to our unitholders.
Phantom Units - Mr. Mercer was granted 22,000 phantom units in December 2014. These phantom units vest as described above over a four year period. This award was recommended to our compensation committee by our chief executive officer based on his subjective view as to appropriate compensation levels taking into consideration the performance milestones described above. Our compensation committee reviewed this recommendation with our chief executive officer and president. In addition, our compensation committee compared the recommended award amount with similar awards to our peer group. In determining final grant amounts, the committee also took into account the leadership role of Mr. Mercer in causing us to achieve the milestones described above. The phantom units granted to Mr. Mercer were approximately at the 50th percentile of the peer group.
Messrs. Walker and Houser made recommendations to the compensation committee for the appropriate level of awards to be made to Messrs. Walker and Houser based on their subjective view as to the appropriate compensation given the milestones achieved as discussed above. The compensation committee reviewed these recommendations and made a subjective determination as to the appropriate award levels given the achievement of such milestones. The committee also compared these award determinations to similar awards by our peer group. In determining final grant amounts, the committee took into account the executives’ leadership roles in causing us to achieve the milestones described above and considered the peer group review. Accordingly, Messrs. Walker and Houser were each granted 25,000 phantom units in December 2014. The 2014 awards put Mr. Walker at just above the 75th percentile and Mr. Houser at just above the 50th percentile, after taking into account the percentage of their time devoted to our business. The value of the phantom units granted to Messrs. Walker and Houser are deducted in calculating the omnibus fee we pay to EnerVest.
In connection with Dr. Gajdica’s termination of employment in April 2014, all phantom units granted to Dr. Gajdica prior to his retirement automatically vested on January 15, 2015.
Benefits
We believe in a simple, straight-forward compensation program and, as such, Mr. Mercer is not provided unique perquisites or other personal benefits. Consistent with this strategy, no perquisites or other personal benefits have or are expected to exceed $10,000 for Mr. Mercer.
Through EnerVest, we provide company benefits that we believe are standard in the industry. These benefits consist of a group medical and dental insurance program for employees and their qualified dependents, group life insurance for employees, accidental death and dismemberment coverage for employees, a company sponsored cafeteria plan, a 401(k) employee savings and investment plan, and a defined benefit plan.
How Elements of Our Compensation Program are Related to Each Other
We view the various components of compensation as related but distinct and emphasize “pay for performance” with a significant portion of total compensation reflecting a risk aspect tied to long-term and short-term financial and strategic goals. Our compensation philosophy is to foster entrepreneurship at all levels of the organization by making long-term equity-based incentives, in particular unit grants, a significant component of executive compensation. We determine the appropriate level for each compensation component based in part, but not exclusively, on our view of internal equity and consistency, and other considerations we deem relevant, such as rewarding extraordinary performance.
Our compensation committee, however, has not adopted any formal or informal policies or guidelines for allocating compensation between long-term and currently paid out compensation, between cash and non-cash compensation, or among different forms of non-cash compensation.
Assessment of Risk
The compensation committee is aware of the need to take risk into account when making compensation decisions and periodically conducts a compensation risk analysis. In conducting this analysis, our compensation committee took into account that, by design, our compensation program for executive officers is designed to avoid excessive risk taking. In particular, our compensation committee considered the following risk-limiting characteristics of our compensation program:
·Our programs balance short-term and long-term incentives, with a substantial portion of the total compensation for our executives provided in equity and focused on long-term performance.
·Incentive plan awards are not tied to formulas that could focus executives on specific short-term outcomes.
·Members of the compensation committee approve final incentive awards in their discretion, after the review of executive and corporate performance.
Our compensation committee has determined that there are no risks arising from our compensation policies and practices that are reasonably likely to have a material adverse effect on us.
Other Compensation Related Matters
Although we encourage our named executive officers to acquire and retain ownership in us, we do not have a policy requiring maintenance of a specified equity ownership level. As of February 13, 2015, our named executive officers beneficially owned in the aggregate approximately 9.2% of our common units (excluding any unvested equity awards). In addition, through their ownership of EnerVest and EV Investors, our executive officers also have a substantial indirect ownership interest in our general partner.
Accounting and Tax Considerations
If an executive is entitled to nonqualified deferred compensation benefits that are subject to Internal Revenue Code Section 409A, and such benefits do not comply with Section 409A, then the benefits are taxable in the first year they are not subject to a substantial risk of forfeiture. In such case, the service provider is subject to regular federal income tax, interest and an additional federal penalty tax of 20% of the benefit includible in income.
When the compensation committee makes awards under the Plan, they also review the effect the awards will have on our consolidated financial statements.
Compensation Committee Report
We have reviewed and discussed with management the compensation discussion and analysis required by Item 402(b) of Regulation S-K. Based on the review and discussion referred to above, we recommend to the board of directors that the compensation discussion and analysis be included in this Form 10-K.
Compensation Committee:
George Lindahl III (Chairman)
Victor Burk	
Gary R. Petersen
Compensation Following 2015 Management Changes
On February 25, 2015, in connection with Mr. Houser’s resignation, our compensation committee approved the vesting of 61,000 phantom units owned by Mr. Houser on February 28, 2015. We will recognize $2.3 million of compensation cost related to these phantom units in the first quarter of 2015.
On February 25, 2015, our compensation committee also approved an increase in Mr. Mercer’s base salary to $350,000, and approved a base salary of $230,000 for Mr. Bobrowski. In addition, the compensation committee awarded Mr. Bobrowski an additional 10,000 phantom units which will vest 25% each year beginning in January 2016.
Summary Compensation Table
The following table sets forth certain information with respect to compensation of our named executive officers. We reimburse EV Management for the costs of Mr. Mercer’s and, prior to April 2014, Dr. Gajdica’s salaries and bonuses. Our compensation committee approved, and we reimbursed EnerVest for cash bonuses paid to Messrs. Walker and Houser in 2014, 2013 and 2012 and listed in the table below. Messrs. Walker and Houser are compensated by EnerVest. We pay EnerVest a fee under the omnibus agreement, but, other than the cash bonuses listed in the table below, we do not directly reimburse EnerVest for the costs of their salaries and bonuses. Compensation for Mr. Flory is not included in the table as it was less than $100,000.
There was no compensation awarded to, earned by or paid to any of the named executive officers related to option awards or non-equity incentive compensation plans.
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(1)Represents amounts paid in December 2014, 2013 and 2012 as bonuses for services in 2014, 2013 and 2012, respectively.
(2)Reflects the aggregate grant date fair value of the phantom units granted computed in accordance with ASC Topic 718. See “Item 8. Financial Statements and Supplementary Data” for the assumptions used in estimating the grant date fair value of the phantom units granted in 2014, 2013 and 2012.
(3)Amounts in this column reflect the increase during 2014, 2013 and 2012 in the actuarial present value of the executive’s accumulated benefit under the Retirement Plan. We do not provide above market rates of return (defined by SEC rules as a rate that exceeds 120% of the federal long-term rate) under the Retirement Plan.
(4)Represents cash distributions received on unvested phantom and performance units and, for Mr. Mercer and Dr. Gajdica, the amounts contributed by us to their 401(k) plans. In 2014, we contributed $34,580 to both Mr. Mercer’s and Dr. Gajdica’s 401(k) plans. Any perquisites or other personal benefits received were less than $10,000. In addition, includes the payments made to Dr. Gajdica described in footnote (5) below.
(5)Dr. Gajdica’s employment with us terminated in April 2014 and so he did not receive his full annual salary, a bonus amount or unit awards in 2014. Per a separation agreement, he received a separation payment of $700,000 and an additional $25,000 to pay the costs of continuing health insurance under the company’s plans, in each case, less required withholding taxes. These amounts are included in the “All Other Compensation” column. In addition, under the terms of the award agreements, all phantom unit awards granted to Dr. Gajdica prior to his retirement automatically vested on January 15, 2015. The value realized on vesting, which is not included in the table above, was $901,430.
Grants of Plan-Based Awards
The following table sets forth certain information with respect to grants of phantom units to our named executive officers in 2014. There were no grants of non-equity incentives or option awards.
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(1)These phantom units vest 25% each year beginning in January 2016.
(2)Reflects the aggregate grant date fair value of the phantom units granted computed in accordance with ASC Topic 718. See “Item 8. Financial Statements and Supplementary Data” for the assumptions used in estimating the grant date fair value of the phantom units granted in 2014.
Outstanding Equity Awards at Fiscal Year End
The following table sets forth certain information with respect to outstanding equity awards at December 31, 2014. There were no option awards outstanding.
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(1)Based on the closing price of our common units on December 31, 2014 of $19.27.
(2)These phantom units vested in January 2015.
(3)One-half of these phantom units vested in January 2015, with the remaining one-half vesting in January 2016.
(4)One-third of these phantom units vested in January 2015, with one-third each vesting in January 2016 and January 2017.
(5)These phantom units vested 25% in January 2015, with 25% each vesting in January 2016, January 2017 and January 2018.
(6)These phantom units vest 25% each year beginning in January 2016.
(7)The first tranche of these performance units was earned in September 2011 and vested 25% each year beginning in January 2012. The remaining tranches were not earned and will be forfeited in January 2015.
(8)Dr. Gajdica’s employment with us terminated in April 2014 and, under the terms of the award agreements, all phantom unit awards granted to Dr. Gajdica prior to his retirement automatically vested on January 15, 2015. The value realized on vesting was $901,430.
Option Exercises and Units Vested
The following table sets forth certain information with respect to phantom units and performance units vested during 2014. There were no option awards that vested.
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(1)Represents the aggregate dollar amount realized on the date of vesting based on the market price of our common units on the NASDAQ Global Market on January 15, 2014.
Pension Benefits
The following table sets forth certain information with respect to the Retirement Plan:
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(1)The present value of the accumulated benefit is based on the RP 2014 IRS Combined Static Mortality Table, the applicable interest rates under IRC Section 430(h)(2)(D) and age 62 normal retirement age. These assumptions are prescribed under ERISA and could be considered reasonable under accounting standards generally accepted in the United States.
(2)Dr. Gajdica terminated employment in April 2014.
Retirement benefits are provided through the Retirement Plan, which is a defined benefit retirement plan. The Retirement Plan provides that the ultimate lump sum value of the benefit a participant will be eligible to receive is equal to the contributions made to the Retirement Plan on the participant’s behalf, adjusted by investment returns experienced during participation in the Retirement Plan. Payment of the benefit may begin on or after the participant has either terminated employment or attained age 62. Participants are always 100% vested in their benefit.
The Retirement Plan is a tax-qualified plan subject to Internal Revenue Code provisions that, as of December 31, 2014, limit the benefits under a defined benefit plan to $210,000.
Nonqualified Deferred Compensation
We do not have a nonqualified deferred compensation plan.
Termination of Employment and Change-in-Control Provisions
Mr. Mercer is party to an employment agreement with EV Management which provides him with post-termination benefits in a variety of circumstances. The amount of compensation payable in some cases may vary depending on the nature of the termination, whether as a result of retirement/voluntary termination, involuntary not-for-cause termination, termination following a change of control and in the event of disability or death of the executive. The discussion below describes the varying amounts payable in each of these situations. It assumes, in each case, that Mr. Mercer’s termination was effective as of December 31, 2014. In presenting this disclosure, we describe amounts earned through December 31, 2014 and, in those cases where the actual amounts to be paid out can only be determined at the time of Mr. Mercer’s separation from EV Management, our estimates of the amounts which would be paid out to him upon his termination.
Provisions Under the Employment Agreement
Under Mr. Mercer’s employment agreement, if his employment with EV Management and its affiliates terminates, he is entitled to unpaid salary for the full month in which the termination date occurred. However, if he is terminated for cause, he is only entitled to receive accrued but unpaid salary through the termination date. In addition, if his employment terminates, he is entitled to unpaid vacation days for that year which have accrued through the termination date, reimbursement of reasonable business expenses that were incurred but unpaid as of the termination date, and COBRA coverage as required by law. Salary and accrued vacation days are payable in cash lump sum less applicable withholdings. Business expenses are reimbursable in accordance with normal procedures.
If Mr. Mercer's employment is involuntarily terminated by EV Management (except for cause or due to the death of the executive) or if his employment is terminated due to disability or retirement, EV Management is obligated to pay as additional compensation an amount in cash equal to 104 weeks of his base salary in effect as of the termination date. Assuming he was terminated as of December 31, 2014, this amount would have been $371,748. In addition, he is entitled to continued group health plan coverage following the termination date for him and his eligible spouse and dependents for the maximum period for which such qualified beneficiaries are eligible to receive COBRA coverage. He shall not be required to pay more for COBRA coverage than officers who are then in active service for EV Management and receiving coverage under the plan. Assuming he was terminated as of December 31, 2014, this amount would have been $37,052.
In the event Mr. Mercer’s employment terminates within the 12-month period immediately following the effective date of a change in control other than by reason of death, disability or for cause, he will be entitled to receive payment of the compensation and benefits as set forth above and to become 100% fully vested in all unvested shares or units of equity compensation granted as of the effective date of the change in control. Assuming a change in control as of December 31, 2014, this amount would have been $371,748, representing 104 weeks of base salary, $1,527,148, representing vesting of unvested units and vesting of unearned units, and $37,052 representing COBRA coverage.
If the compensation is paid or benefits are provided under the employment agreement by reason of a change in control, no additional compensation will be payable or benefits provided by reason of a subsequent change in control during the term of the agreement.
“Cause” generally means:
·his conviction by a court of competent jurisdiction as to which no further appeal can be taken of a felony or entering the plea of nolo contendere to such crime by the executive;
·the commission by him of a demonstrable act of fraud, or a misappropriation of funds or property, of or upon the company or any affiliate;
·the engagement by him without approval of the board of directors or compensation committee in any material activity which directly competes with the business of the company or any affiliate or which would directly result in a material injury to the business or reputation of the company or any affiliate; or
·the material breach by him of the employment agreement, or the repeated nonperformance of his duties to the company or any affiliate (other than by reason of illness or incapacity).
In some cases, he has the opportunity to cure the breach or nonperformance before being terminated for cause.
A “change in control" generally means the occurrence of any of following events:
·a corporation, person, or group acquires, directly or indirectly, beneficial ownership of more than 50% of the equity interests in EV Management and is then entitled to vote generally in the election of the board of directors; or
·the withdrawal, removal or resignation of EV Management as the general partner of our general partner or the withdrawal, removal or resignation of our general partner as the general partner of the partnership; or
·the effective date of a merger, consolidation, or reorganization plan that is adopted by the board of directors of EV Management involving EV Management in which EV Management is not the surviving entity, or a sale of all or substantially all of our assets; or
·any other transactions or series of related transactions which have substantially the same effect as the foregoing.
“Retirement” means the termination of his employment for normal retirement at or after attaining age sixty-five provided that he has been with the company for at least five years.
Provisions Under Phantom Unit and Performance Unit Award Agreements
Both the phantom unit award agreements and performance unit award agreements provide that any unvested units will vest upon Mr. Mercer’s death, disability, termination of employment other than for cause and upon a change of control. Assuming termination of employment or change of control as of December 31, 2014, the value of the awards would have been $1,527,148. If he resigns or his employment or is terminated for cause, all unvested units are forfeited. Upon vesting, the units may be paid in cash equal to the fair market value of the units on the date immediately preceding the vesting date, at the option of our general partner. The definitions of the terms such as “cause” and “change in control” in the award agreements are substantially similar to the definitions in the employment agreements.
Compensation of Directors
We use a combination of cash and unit-based incentive compensation to attract and retain qualified candidates to serve on EV Management’s board. In setting director compensation, we consider the significant amount of time that directors expend in fulfilling their duties to us as well as the skill level we require of members of the board. In addition, our compensation committee reviews director compensation at our peer group companies.
In 2014, directors who were not officers or employees of EV Management, EnCap or their respective affiliates received an annual retainer of $40,000, with the chairmen of the audit committee and conflicts committee receiving an additional annual fee of $10,000 and the chairman of the compensation committee receiving an additional annual fee of $5,000. In addition, each non-employee director receives $1,000 per committee meeting attended ($500 if by phone) and is reimbursed for his out of pocket expenses in connection with attending meetings. We indemnify each director for his actions associated with being a director to the fullest extent permitted under Delaware law.
Each of the directors was awarded 3,000 phantom units in December 2014. These phantom units vest 25% each year beginning in January 2016.
The following table discloses the cash unit awards and other compensation earned, paid or awarded to each of EV Management’s directors during year ended December 31, 2014:
___________
(1)Messrs. Walker and Houser are not included in this table as they are employees of EnerVest and receive no compensation for their services as directors. Mr. Petersen is not an independent director because of his affiliations with EnCap and does not receive a cash director’s fee.
(2)Reflects the aggregate grant date fair value of the phantom units granted in December 2014 computed in accordance with ASC Topic 718.
(3)	Reflects the dollar amount of compensation recognized for financial statement reporting purposes for 2014 for distributions paid on the unvested phantom units.
(4)	As of December 31, 2014, Messrs. Burk, Larson and Lindahl each have 9,155 equity awards outstanding and Mr. Petersen has 8,262 equity awards outstanding
Compensation Committee Interlocks and Insider Participation
None of our executive officers serves as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of EV Management’s board of directors or compensation committee.
None of the members of the compensation committee have served as an officer or employee of us, our general partner or its general partner. Furthermore, except for compensation arrangements discussed in this Form 10-K and as set forth in the next sentences, we have not participated in any contracts, loans, fees, awards or financial interests, direct or indirect, with any committee member, nor are we aware of any means, directly or indirectly, by which a committee member could receive a material benefit from us.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
Security Ownership of Certain Beneficial Owners and Management
Based solely on a review of the copies of reports on Schedules 13D and 13G and amendments thereto furnished to us, we believe that there were no beneficial owners of more than 5% of our common units as of February 13, 2015 other than as set forth below.
The following table sets forth the beneficial ownership of our units as of February 14, 2014 held by:
·each person who is known to us to beneficially own 5% or more of our outstanding common units;
·each member of the Board of Directors of EV Management, as well as Mr. Mariani, who will become a director of EV Management on March 1, 2015;
·each named executive officer of EV Management and Mr. Bobrowski, who will become a named executive officer of EV Management on March 1, 2015; and
·all directors and executive officers of EV Management as a group.
___________
*	Less than 1%
(1)Unless otherwise indicated, the address for all beneficial owners in this table is 1001 Fannin Street, Suite 800, Houston, TX 77002.
(2)All information in this table is based solely on a Schedule 13G filed on January 30, 2015 by the following persons (“Filing Parties”): Robert J. Raymond, RR Advisors, LLC, RCH Energy MLP Fund GP, L.P., RCH Energy MLP Fund, L.P., and RCH Energy MLP Fund-A, L.P. The Filing Parties report beneficial ownership over all or a portion of 3,197,076 common units. In addition, Robert J. Raymond reported the sole power to vote or to direct the voting of and the sole dispositive power over 100,000 of our common units set forth in the table above. Each reporting person expressly disclaims (a) the existence of any group and (b) beneficial ownership with respect to any common units other than the common units owned of record by such reporting person.
(3)All information in the table with respect to Brookfield Investment Management, Inc. (“Brookfield”) is based solely on the Schedule 13G filed by Brookfield with the SEC on February 17, 2015. According to the Schedule 13G, Brookfield is the beneficial owner of 2,947,573 common units, or approximately 6.0% of our outstanding common units. Brookfield disclaims beneficial ownership of such units.
(3)All information in the table with respect to Piper Jaffray Companies (“Piper Jaffray”) is based solely on the Schedule 13G/A filed by Piper Jaffray with the SEC on February 17, 2015. According to the Schedule 13G/A, Advisory Research, Inc. (“ARI”), a wholly-owned subsidiary of Piper Jaffray and an investment advisor registered under Section 203 of the Investment Advisers Act of 1940, is the beneficial owner of 2,683,721 common units, or approximately 5.5% of our outstanding common units, as a result of acting as investment advisor to various clients. Piper Jaffray may be deemed to be the beneficial owner of the common units through control of ARI. However, Piper Jaffray disclaims beneficial ownership of such units.
(5)Includes 1,808,098 common units owned by John B. and Lisa A. Walker, L.P. and 13,400 common units owned by Mr. Walker’s spouse. Mr. Walker disclaims beneficial ownership of these common units. Also includes 155,600 common units owned by EnerVest. Mr. Walker, by virtue of his direct and indirect ownership of the limited liability company that acts as EnerVest’s general partner, may be deemed to beneficially own the common units owned by EnerVest.
(6)Includes 320,488 common units owned by DSEA II, LP, a limited partnership of which Mr. Houser and his spouse manage the general partner and 190,800 common units owned by trusts for Mr. Houser’s children. Mr. Houser disclaims beneficial ownership of these common units.
(7)Includes 20,000 common units owned by a trust for Mr. Lindahl’s daughters and 300 common units owned by Mr. Lindahl’s spouse. Mr. Lindahl disclaims beneficial ownership of these common units.
(8)Includes 519,688 common units owned by EnCap Energy Capital Fund V, L.P. and 411,116 common units owned by EnCap V-B Acquisitions, L.P. EnCap V-B Acquisitions GP, LLC, as the general partner of EnCap V-B Acquisitions, L.P., EnCap Energy Capital Fund V-B, L.P., as the general partner of EnCap V-B Acquisitions GP, LLC, EnCap Equity Fund V GP, L.P., as the general partner of each of EnCap Energy Capital Fund V, L.P. and EnCap Energy Capital Fund V-B, L.P., EnCap Investments L.P., as the general partner of EnCap Equity Fund V GP, L.P., EnCap Investments GP, L.L.C., as the general partner of EnCap Investments L.P., RNBD GP LLC, as the sole member of EnCap Investments GP, L.L.C., may be deemed to share voting and dispositive control over the common units owned by EnCap Energy Capital Fund V, L.P. and EnCap V-B Acquisitions, L.P. Each of EnCap V-B Acquisitions GP, LLC, EnCap Energy Capital Fund V-B, L.P., EnCap Equity Fund V GP, L.P., EnCap Investments L.P., EnCap Investments GP, L.L.C., RNBD GP LLC, disclaim beneficial ownership of the securities in excess of such entity’s respective pecuniary interest in the securities. Gary R. Petersen is a member of RNBD GP LLC, and disclaims beneficial ownership of the securities owned by EnCap Energy Capital Fund V, L.P. and EnCap V-B Acquisitions, L.P.
(9)Includes 124,097 common units owned by KS Mariani, LP, a limited partnership owned by Mr. Mariani and his spouse, and 30,000 common units owned by trusts for Mr. Mariani’s children. Mr. Mariani disclaims beneficial ownership of these common units.
Beneficial Ownership of Our General Partner
EV Management, the general partner of our general partner, is a limited liability company wholly owned by EnerVest, a limited partnership. Jones EnerVest Ltd., a limited partnership managed by its general partner, Jones-Tucker Corporation, whose directors are Jon Rex Jones, A.V. Jones, Jr. and Jean Jones Tucker, and members of EnerVest’s executive management team, including Messrs. Walker Houser and Mariani, own substantially all of the partnership interests in EnerVest. The address for Jones EnerVest Ltd. and the members of EnerVest’s executive management team which own interests in EnerVest, is 1001 Fannin Street, Suite 800, Houston, Texas 77002.
Securities Authorized for Issuance under Equity Compensation Plans
The number of common units which we may issue under the Plan is 4.5 million. The following table summarizes information about our equity compensation plans as of December 31, 2014:
For a description of our equity compensation plan, please see the discussion under Item 11 above.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Our partnership agreement provides that whenever a potential conflict exists or arises between our general partner or its affiliates, on the one hand, and us, on the other hand, any resolution or course of action by the general partner shall be permitted and deemed approved by all of the partners, and shall not constitute a breach of the partnership agreement or any duty stated or implied by law or equity if the resolution or the course of action taken in respect of such conflict of interest is approved by a vote of a majority of the members of our conflicts committee. Our partnership agreement does not require that we submit potential conflicts to our conflicts committee, but as a matter of course, our general partner submits to our conflicts committee for review any transaction that involves or may involve a conflict of interest. Other than the provision of our partnership agreement, we have no written policies or procedures for the conflicts committee to follow in making these determinations.
Ownership in Our General Partner by the Management of EV Management and EnCap
Our general partner, EV Energy GP, is owned 71.25% by EnerVest, 23.75% by EnCap and 5% by EV Investors. Our general partner has a 2% interest in us and owns all of the incentive distribution rights, which entitle our general partner to a portion of the distributions we make. The distributions we will make to our general partner are described under Item 5. While EnerVest and EV Investors are under common control with us, EnCap may be deemed our affiliate because EnCap has designated a director to the board of directors of EV Management.
Contracts with EnerVest and Its Affiliates
EnerVest owns all of the membership interests in EV Management, the general partner of our general partner. Messrs. Walker, Houser and Mariani own partnership interests in EnerVest. In addition, some of the employees of EnerVest who perform services for us under the administrative services agreement and operating agreement described below are owners of EnerVest.
We have entered into agreements with EnerVest. The following is a description of these agreements.
Omnibus Agreement
In connection with our initial public offering, we entered into an omnibus agreement with EnerVest, our general partner and others that addressed the following matters:
·our obligation to pay EnerVest a monthly fee for providing us general and administrative and all other services with respect to our existing business and operations;
·our obligation to reimburse EnerVest for any insurance coverage expenses it incurs with respect to our business and operations; and
·EnerVest’s obligation to indemnify us for certain liabilities and our obligation to indemnify EnerVest for certain liabilities.
Pursuant to the omnibus agreement, EnerVest performs certain centralized corporate functions for us, such as accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering and senior management oversight.
Any or all of the provisions of the omnibus agreement, other than the indemnification provisions described below, will be terminable by EnerVest at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The omnibus agreement will also terminate in the event of a change of control of us, our general partner or the general partner of our general partner.
Under the omnibus agreement, EnerVest indemnified us for losses attributable to title defects, retained assets and liabilities (including any preclosing litigation relating to assets contributed to us) and income taxes attributable to preclosing operations. EnerVest’s maximum liability for these indemnification obligations will not exceed $1.5 million and EnerVest will not have any obligation under this indemnification until our aggregate losses exceed $200,000. We also will indemnify EnerVest for all losses attributable to the operations of the assets contributed to us after September 29, 2006, to the extent not subject to EnerVest’s indemnification obligations.
During 2014, we paid EnerVest $12.1 million in monthly administrative fees under the omnibus agreement. These fees are based on an allocation of charges between EnerVest and us based on the estimated use of such services by each party, and includes a deduction for the value of the awards we issue to EnerVest employees (including Messrs. Walker and Houser) who perform services for us. We believe that the allocation method employed by EnerVest is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis. The initial term of the omnibus agreement expired on December 31, 2014. In February 2015, EV Management and EnerVest extended the term of the omnibus agreement through December 2015.
Operating Agreements
We are party to operating agreements under which a subsidiary of EnerVest acts as contract operator of all wells in which we own an interest and are entitled to appoint the operator. As contract operator, EnerVest designs and manages the drilling and completion of our wells and the day-to-day operating and maintenance activities of our wells and facilities.
Under the operating agreements, EnerVest establishes a joint account for each well in which we have an interest. The joint account is charged with all direct expenses incurred in the operation of our wells and related gathering systems and production facilities, and we are required to pay our working interest share of amounts charged to the joint account. 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 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 well, gathering and other equipment used on our properties. In addition, direct expenses will include the allocable share of the cost of the EnerVest employees who perform services on our properties. The allocation of the cost of EnerVest employees who perform services on our properties are based on time sheets maintained by EnerVest’s employees. Direct expenses charged to the joint account will 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.
During 2014, we reimbursed EnerVest approximately $17.0 million for direct expenses incurred in the operation of our wells and related gathering systems and production facilities and for the allocable share of the costs of EnerVest employees who performed services on our properties. As the vast majority of such expenses are charged to us on an actual basis (i.e., no mark-up or subsidy is charged or received by EnerVest), we believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market and are representative of what the amounts would have been on a standalone basis.
Divestitures with Institutional Partnerships Managed by EnerVest Ltd.
In 2014, we, along with certain institutional partnerships managed by EnerVest, closed on the sale of certain deep rights in the Eagle Ford formation in Burleson, Brazos and Grimes Counties, Texas for $233.3 million. Our share of the proceeds was $33.8 million.
In addition, we, along with certain institutional partnerships managed by EnerVest, closed on the sale of additional Utica Shale acreage in Ohio for $8.4 million. Our share of the proceeds was $1.5 million.
The purchasers were not affiliated with us or the institutional funds. The sales prices we received was proportional to the sales price of the properties sold by the funds, based on the interests in the properties owned.
Overriding Royalty Interest Partnership
In 2011, we and certain institutional partnerships managed by EnerVest carved out a 7.5% ORRI from certain acres in Ohio (the "Underlying Properties"), 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 entitles 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. In 2014, we recognized $0.4million of income from unconsolidated affiliates, and we received $0.3 million of distributions.
Development of the Knox Acreage
We and certain institutional partnerships managed by EnerVest own acreage in the Knox formation in the Appalachian Basin. In December 2009, we entered into an area of mutual interest (“AMI”) agreement with these institutional partnerships to jointly explore and develop these properties. Under the AMI agreement, we and the institutional partnerships contributed approximately 7,760 net acres and approximately 1,740 net acres, respectively, to the AMI. We and the institutional partnerships will share 3-D seismic, development, acquisition and other costs associated with developing these properties. The revenues and costs will be shared based on the net acres contributed to the AMI, and any additional properties acquired in the area will be acquired based on such interest.
Long-Term Incentive Awards
We award phantom units under the Plan to employees of EverVest who provide services to us. These units are awarded to particular employees based on the recommendation of EnerVest’s senior management. During 2014, we awarded an aggregate of 0.3 million phantom units to such employees. The market value of these units on the date of grant was approximately $7.2 million.
Director Independence
During 2014, all members of the board of directors of EV Management, other than Messrs. Walker, Houser and Petersen, are independent as defined under the independence standards established by the NASDAQ. Following the March 1, 2015 effective date of their appointment to our board of directors, Messrs. Mercer and Mariani will not be independent directors. The NASDAQ does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The audit committee of EV Management selected Deloitte & Touche LLP, an independent registered public accounting firm, to audit our consolidated financial statements for the year ended December 31, 2014. The audit committee’s charter requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit-related, tax and all other fees categories below with respect to this Annual Report on Form 10-K for the year ended December 31, 2014 were approved by the audit committee.
Fees approved to be paid to Deloitte & Touche LLP are as follows:
_____________
(1)Represents fees for professional services provided in connection with the audit of our annual financial statements and review of our quarterly financial statements.
(2)Represents fees for potential transactions.
(3)Represents fees for our public equity offering in October 2013.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)List of Documents filed as part of this Report
(1)Financial Statements
All financial statements of the Registrant as set forth under Item 8 of this Annual Report on Form 10-K.
(2)Financial Statement Schedules
Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in our consolidated financial statements and related notes.
(3)Exhibits
The exhibits listed below are filed or furnished as part of this report:
3.1First Amended and Restated Partnership Agreement EV Energy Partners, L.P. (incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
3.2First Amended and Restated Partnership Agreement of EV Energy GP, L.P. (incorporated by reference from Exhibit 3.2 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
3.3Amended and Restated Limited Liability Company Agreement of EV Management, LLC. (incorporated by reference from Exhibit 3.3 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
3.4First Amendment dated April 15, 2008 to First Amended and Restated Partnership Agreement of EV Energy Partners, L.P., effective as of January 1, 2007 (incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on April 18, 2008).
4.1Indenture, dated as of March 22, 2011, by and among EV Energy Partners, L.P., EV Energy Finance Corp., the Guarantors named therein and U.S. National Bank Association, as trustee (incorporated by reference from Exhibit 4.1 to EV Energy Partners L.P.’s current report on Form 8-K filed with the SEC on March 22, 2011).
10.1Omnibus Agreement, dated September 29, 2006, by and among EnerVest Management Partners, Ltd., EV Management, LLC, EV Energy GP, L.P., EV Energy Partners, L.P., and EV Properties, L.P. (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
10.2Contract Operating Agreement, dated September 29, 2006, by and among EnerVest Operating, L.L.C. and EnerVest Production Partners, L.P. (incorporated by reference from Exhibit 10.2 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
10.3Contract Operating Agreement, dated September 29, 2006, by and among EnerVest Operating, L.L.C. and CGAS Properties, L.P. (incorporated by reference from Exhibit 10.3 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
*10.4EV Energy Partners, L.P. Long-Term Incentive Plan (incorporated by reference from Exhibit 10.4 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
*10.5Employment Agreement, dated October 1, 2006, by and between EV Management, LLC and Michael E. Mercer (incorporated by reference from Exhibit 10.7 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
+10.6Omnibus Agreement Extension, dated February 25, 2015, by and between EnerVest, Ltd. and EV Energy GP, L.P.
*10.7Form of EV Energy Partners, L.P. Incentive Unit Agreements (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on March 18, 2009).
10.8Second Amended and Restated Credit Agreement, dated as of April 26, 2011 by and among EV Energy Partners, L.P., EV Properties, L.P., and JPMorgan Chase Bank, N.A. as Administrative Agent for the lenders named therein (incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s current report on Form 8-K filed with the SEC on April 29, 2011).
10.9First Amendment dated December 21, 2011 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s current report on Form 8-K filed with the SEC on December 27, 2011).
10.10Second Amendment dated March 29, 2012 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s current report on Form 8-K filed with the SEC on April 4, 2012).
10.11Third Amendment dated September 27, 2012 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s current report on Form 8-K filed with the SEC on October 3, 2012).
10.12Amended and Restated Assignment Agreement dated October 1, 2012 between M3 Ohio Gathering LLC, Utica Gas Services, L.L.C., CGAS Properties, L.P. and Utica East Ohio Midstream L.L.C. (incorporated by reference from Exhibit 10.17 to EV Energy Partners L.P.’s annual report on Form 10-K filed with the SEC on March 1, 2013).
10.13Fourth Agreement dated as of February 26, 2013 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.18 to EV Energy Partners L.P.’s annual report on Form 10-K filed with the SEC on March 1, 2013).
10.14Fifth Agreement dated as of August 7, 2013 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on August 9, 2013).
10.15Ronald J. Gajdica Separation Agreement, dated April 30, 2014 (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on May 6, 2014).
10.16Sixth Agreement dated as of September 19, 2014 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on September 25, 2014).
+10.17Seventh Amendment dated as of February 26, 2015 to Second Amended and Restated Credit Agreement.
+21.1Subsidiaries of EV Energy Partners, L.P.
+23.1Consent of Cawley, Gillespie & Associates, Inc.
+23.2Consent of Deloitte & Touche LLP.
+31.1Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
+31.2Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
+32.1Section 1350 Certification of Chief Executive Officer
+32.2Section 1350 Certification of Chief Financial Officer
+99.1Cawley, Gillespie and Associates, Inc. Reserve Report.
+101Interactive Data Files
________________
*Management contract or compensatory plan or arrangement
+Filed herewith
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EV Energy Partners, L.P.
(Registrant)
Date: February 27, 2015 By: /s/ MICHAEL E. MERCER
Michael E. Mercer
Senior Vice President and Chief Financial Officer
Pursuant to the requirement of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/JOHN B. WALKER
Executive Chairman and Director
February 27, 2015
John B. Walker
(principal executive officer)
/s/MARK A. HOUSER
President, Chief Executive Officer and Director
February 27, 2015
Mark A. Houser
/s/MICHAEL E. MERCER
Senior Vice President and Chief Financial Officer
February 27, 2015
Michael E. Mercer
(principal financial officer)
/s/RYAN J. FLORY
Controller
February 27, 2015
Ryan J. Flory
(principal accounting officer)
/s/VICTOR BURK
Director
February 27, 2015
Victor Burk
/s/JAMES R. LARSON
Director
February 27, 2015
James R. Larson
/s/GEORGE LINDAHL III
Director
February 27, 2015
George Lindahl, III
/s/GARY R. PETERSEN
Director
February 27, 2015
Gary R. Petersen
EXHIBIT INDEX
3.1First Amended and Restated Partnership Agreement EV Energy Partners, L.P. (incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
3.2First Amended and Restated Partnership Agreement of EV Energy GP, L.P. (incorporated by reference from Exhibit 3.2 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
3.3Amended and Restated Limited Liability Company Agreement of EV Management, LLC. (incorporated by reference from Exhibit 3.3 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
3.4First Amendment dated April 15, 2008 to First Amended and Restated Partnership Agreement of EV Energy Partners, L.P., effective as of January 1, 2007 (incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on April 18, 2008).
4.1Indenture, dated as of March 22, 2011, by and among EV Energy Partners, L.P., EV Energy Finance Corp., the Guarantors named therein and U.S. National Bank Association, as trustee (incorporated by reference from Exhibit 4.1 to EV Energy Partners L.P.’s current report on Form 8-K filed with the SEC on March 22, 2011).
10.1Omnibus Agreement, dated September 29, 2006, by and among EnerVest Management Partners, Ltd., EV Management, LLC, EV Energy GP, L.P., EV Energy Partners, L.P., and EV Properties, L.P. (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
10.2Contract Operating Agreement, dated September 29, 2006, by and among EnerVest Operating, L.L.C. and EnerVest Production Partners, L.P. (incorporated by reference from Exhibit 10.2 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
10.3Contract Operating Agreement, dated September 29, 2006, by and among EnerVest Operating, L.L.C. and CGAS Properties, L.P. (incorporated by reference from Exhibit 10.3 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
*10.4EV Energy Partners, L.P. Long-Term Incentive Plan (incorporated by reference from Exhibit 10.4 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
*10.5Employment Agreement, dated October 1, 2006, by and between EV Management, LLC and Michael E. Mercer (incorporated by reference from Exhibit 10.7 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).
+10.6Omnibus Agreement Extension, dated February 25, 2015, by and between EnerVest, Ltd. and EV Energy GP, L.P.
*10.7Form of EV Energy Partners, L.P. Incentive Unit Agreements (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on March 18, 2009).
10.8Second Amended and Restated Credit Agreement, dated as of April 26, 2011 by and among EV Energy Partners, L.P., EV Properties, L.P., and JPMorgan Chase Bank, N.A. as Administrative Agent for the lenders named therein (incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s current report on Form 8-K filed with the SEC on April 29, 2011).
10.9First Amendment dated December 21, 2011 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s current report on Form 8-K filed with the SEC on December 27, 2011).
10.10Second Amendment dated March 29, 2012 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s current report on Form 8-K filed with the SEC on April 4, 2012).
10.11Third Amendment dated September 27, 2012 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s current report on Form 8-K filed with the SEC on October 3, 2012).
10.12Amended and Restated Assignment Agreement dated October 1, 2012 between M3 Ohio Gathering LLC, Utica Gas Services, L.L.C., CGAS Properties, L.P. and Utica East Ohio Midstream L.L.C. (incorporated by reference from Exhibit 10.17 to EV Energy Partners L.P.’s annual report on Form 10-K filed with the SEC on March 1, 2013).
10.13Fourth Agreement dated as of February 26, 2013 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.18 to EV Energy Partners L.P.’s annual report on Form 10-K filed with the SEC on March 1, 2013).
10.14Fifth Agreement dated as of August 7, 2013 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on August 9, 2013).
10.15Ronald J. Gajdica Separation Agreement, dated April 30, 2014 (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on May 6, 2014).
10.16Sixth Agreement dated as of September 19, 2014 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on September 25, 2014).
+10.17Seventh Amendment dated as of February 26, 2015 to Second Amended and Restated Credit Agreement.
+21.1Subsidiaries of EV Energy Partners, L.P.
+23.1Consent of Cawley, Gillespie & Associates, Inc.
+23.2Consent of Deloitte & Touche LLP.
+31.1Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
+31.2Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
+32.1Section 1350 Certification of Chief Executive Officer
+32.2Section 1350 Certification of Chief Financial Officer
+99.1Cawley, Gillespie and Associates, Inc. Reserve Report.
+101Interactive Data Files
________________
*Management contract or compensatory plan or arrangement
+Filed herewith