ITEM 1. BUSINESS
Overview
EV Energy Partners, L.P. (“we,” “our,” “us” or the “Partnership”) is a publicly held Delaware limited partnership formed in 2006. 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.
As of December 31, 2016, our oil and natural gas properties were located in the Barnett Shale, the San Juan Basin, the Appalachian Basin (which includes the Utica Shale), Michigan, Central Texas (which includes the Austin Chalk area), the Monroe Field in Northern Louisiana, the Mid-Continent areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana and the Permian Basin.
Oil, natural gas and natural gas liquids reserve information is derived from our reserve reports prepared by Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”) and Wright & Company, Inc. (“Wright”), 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, 2016:
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(1)At December 31, 2016, our standardized measure of discounted future net cash flows was $371.1 million. Because we are a limited partnership, we made no provision for federal income taxes in the calculation of standardized measure; however, we made a provision for future obligations under the Texas gross margin tax. The present value of future net pre-tax cash flows attributable to estimated net proved reserves, discounted at 10% per annum (“PV-10”), is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is computed on the same basis as standardized measure but does not include a provision for federal income taxes or the Texas gross margin tax. PV-10 is considered a non-GAAP financial measure under the regulations of the Securities and Exchange Commission (the “SEC”). We believe PV-10 to be an important measure for evaluating the relative significance of our oil and natural gas properties. We further believe investors and creditors may utilize our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. PV-10, however, is not a substitute for the standardized measure. Our PV-10 measure and the standardized measure do not purport to present the fair value of our reserves.
The table below provides a reconciliation of PV-10 to the standardized measure at December 31, 2016 (dollars in millions):
Current Developments
Oil, natural gas and natural gas liquids prices are determined by many factors that are outside of our control. Historically, these prices have been volatile, and we expect them to remain volatile. In late 2014, prices for oil, natural gas and natural gas liquids declined precipitously, and prices remained low through 2015 and most of 2016. While prices showed some improvement during the second half of 2016 and the beginning of 2017, they have continued to fluctuate.
Factors contributing to lower oil prices include real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle East; lower forecasted levels of global economic growth combined with excess global supply; actions taken by the Organization of Petroleum Exporting Countries; and the strength of the U.S. dollar in international currency markets. Factors contributing to lower natural gas prices include increased supplies of natural gas due to greater exploration and development activities; higher levels of natural gas in storage; and competition from other energy sources. Prices for natural gas liquids generally correlate to the price of oil and, accordingly, prices remain lower than historical levels and are likely to continue to directionally follow the market for oil.
In 2016, these low prices negatively affected our revenues, earnings and cash flows, and continued volatility in prices for oil, natural gas and natural gas liquids could have a material adverse effect on our liquidity. Continued volatility or further declines in prices could also have a significant adverse impact on the value and quantities of our reserves, assuming no other changes in our development plans.
In 2016, in response to continued lower prices, we took a number of actions to preserve our liquidity and financial flexibility, including:
·repurchased $82.7 million of our outstanding senior notes due April 2019 for $35.0 million;
·reduced the amount of capital spending we dedicated to the development of our reserves by approximately 75%;
·continued to reduce operating and capital costs;
·amended our credit facility to, among other things, ease the leverage covenants until 2018;
·continued to evaluate strategic divestitures such as our recent Barnett Shale divestiture described below and acquisitions of long-life, producing oil and natural gas properties; and
·reevaluated our common unit distribution policy and suspended our common unit distribution to conserve excess cash.
As a result of the steps above, as of December 31, 2016, we have over $205 million of liquidity between our borrowing base capacity, cash on hand and restricted cash. However, given current forward oil and natural gas prices and the fact that we have less production hedged at lower prices in 2017 relative to previous years, we have taken additional steps going forward into 2017 to continue to preserve our liquidity and financial flexibility. These steps include:
·focusing on managing and enhancing our base business through continued reductions in operating costs;
·increasing our capital spending budget to $30 - $45 million from $10.7 million in 2016, in an effort to maintain current production levels;
·maintaining a sufficient liquidity position to manage through the current environment, which includes continuing to assess the appropriate distribution levels every quarter;
·continuing to evaluate strategic acquisitions of long-life, producing oil and natural gas properties such as our Eagle Ford Acquisition described below; and
·further realizing the value of our undeveloped acreage through either alternative sources of capital, including farmouts, production payments and joint ventures, or potential monetization of acreage.
During 2016, the board of directors of EV Management announced that it had elected to suspend distributions for the first three quarters of 2016. The board of directors also elected to suspend distributions for the fourth quarter of 2016. The company continues to generate positive distributable cash flow, albeit at significantly lower levels than previous years. The board of directors continues to evaluate the distribution on a quarterly basis and may elect to reinstate the distribution at the appropriate time when commodity prices and operating cash flows have increased to a level that can support a sustainable distribution in compliance with the covenants in our credit agreement. In order to reinstate distributions, we must be in compliance with the covenants contained in our credit agreement. We are currently in compliance with all of the covenants contained in the most recent ninth amendment of our credit agreement and expect to be in compliance through the end of 2017. Absent a rebound in commodity prices or an amendment to our credit facility, we currently project that we will not be in compliance with our leverage covenant at the end of the first quarter of 2018. See 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 resume cash distributions to holders of our common units.
We have suspended cash distributions to the holders of our common units in order to conserve cash and improve our liquidity.
We may not have sufficient available cash from operating surplus each quarter to enable us to resume making cash distributions 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, we may not have sufficient available cash to resume our quarterly cash distributions to our common unitholders. Even if we were able to resume a quarterly cash distribution, the amount of available cash that we could distribute may fluctuate significantly from quarter to quarter. In order to reinstate distributions, we must be in compliance with the covenants contained in our credit agreement. We are currently in compliance with all of the covenants contained in the most recent ninth amendment of our credit agreement and expect to be in compliance through the end of 2017. Absent a rebound in commodity prices or an amendment to our credit facility, we currently project that we will not be in compliance with our leverage covenant at the end of the first quarter of 2018. See Item 1A. Risk Factors - Covenants in our credit agreement may restrict our ability to resume and sustain distributions.
Covenants in our credit agreement may restrict our ability to resume and sustain distributions.
The terms of our credit agreement may restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility. Prior to reinstating distributions, we will ensure that we are, and will continue to be, in compliance with the covenants contained in our credit agreement. We are currently in compliance with all of the covenants contained in the most recent ninth amendment of our credit agreement and, at current forward prices, expect to be in compliance through the end of 2017. At the end of first quarter of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we may have a total debt to EBITDAX ratio higher than the level prescribed in the most recent ninth amendment of our credit agreement. Absent a rebound in commodity prices, we currently project that we will not be in compliance with our leverage covenant at the end of the first quarter of 2018, and this may require us to make payments on our debt facilities or require us to work with our bank syndicate to amend our credit agreement. Our inability to amend our credit agreement or otherwise comply with the covenants in our credit agreement could have a material, adverse effect on our business, including our ability to resume and sustain distributions.
Oil, natural gas and natural gas liquids prices are highly volatile and depressed prices can significantly and adversely affect our cash flows from operations and our ability to service our debt obligations and resume distributions on our common units.
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 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 recent change in federal regulations removing the longstanding prohibition of the export of oil produced in the U.S.;
·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.
Low commodity prices or further declines would have a material adverse effect on our business.
Our financial position, results of operations, access to capital and the quantities of oil and natural gas that may be economically produced would be negatively impacted if oil and natural gas prices decrease further or remain depressed for an extended period of time. The ways in which such price decreases could have a material negative effect include:
·a significant decrease in the number of wells we drill on our acreage, thereby reducing our production and cash flows;
·a reduction in cash flow, which would decrease funds available for capital expenditures employed to replace reserves and maintain or increase production;
·a decrease in future undiscounted and discounted net cash flows from producing properties, possibly resulting in impairment expense that may be significant;
·lower proved reserves, production and cash flow as certain reserves may no longer be economic to produce;
·access to sources of capital, such as equity or long-term debt markets could be severely limited or unavailable; and
·a reduction in the borrowing base on our credit facility.
Future oil and natural gas price declines may result in a write-down of our asset carrying values.
Accounting rules require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties in the event we have impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write-down. During 2016, we recorded impairment charges of approximately $131.3 million. The impairment charges during 2016 included $89.5 million related to oil and natural gas properties in the Barnett Shale that were written down to their fair value as determined based on the sale of these properties during December 2016. We also may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred. Since December 31, 2016, commodity prices have continued to fluctuate. If commodity prices significantly decrease before March 31, 2017, or in future quarters, we could have additional impairments of our oil and natural gas properties.
We may be limited in our ability to maintain or book additional proved undeveloped reserves under the SEC’s rules.
Our estimates of our proved reserves as of December 31, 2016 have been prepared in a manner consistent with our interpretation of the SEC rules relating to reserve estimation and disclosure requirements for oil and natural gas companies, as well as the interpretation of our independent petroleum consultants performing an audit of our reserve estimates. Included within these SEC reserve rules is a general requirement that, subject to limited exceptions, PUD’s may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional PUD’s as we pursue our drilling program. Further, if we postpone drilling of PUD’s beyond this five-year development horizon, whether in response to a continued depressed commodity price environment or otherwise, we may have to write off reserves previously recognized as PUD’s. Our long-term plans may change based on commodity prices, costs or our liquidity in a manner that would require us to reduce our proved reserve estimate in the future due to the five year development rule or otherwise.
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, 2016, we had over 3,014 gross identified potential drilling locations, of which approximately 1,400 were located in the Barnett Shale and approximately 1,000 were located in the Appalachian Basin. This inventory was developed using data gathered from our appraisal efforts and development drilling, along with offset operators drilling activities. As of December 31, 2016, we included reserves attributable to 144 of our gross identified potential drilling locations in our proved undeveloped reserves category, of which approximately 90 were located in the Barnett Shale. 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 10% of our total estimated proved reserves as of December 31, 2016 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 costs 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 and Central Texas, and these properties represent approximately 49% of our estimated net proved reserves as of December 31, 2016. 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 an entity 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 resume 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 to resume 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 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. Relative to previous years, we have less volumes hedged at lower prices. This makes our near-term oil, natural gas and natural gas liquids revenues more sensitive to changes in commodity prices.
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 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 issued on December 5, 2016, a re-proposed rule imposing position limits for certain futures and option contracts in various commodities (including crude oil and natural gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. A final rule has not yet been issued. Similarly, on December 2, 2016, the CFTC has re-issued a proposed rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, but the CFTC has not yet issued a final rule.
The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types of swap transactions. 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 financial derivative transactions to hedge or mitigate our exposure to commodity price volatility 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 capital requirements, depending on our ability to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate our commercial risks, these rules and regulations may require us to comply with position limits and with certain clearing and trade-execution requirements in connection with our financial derivative activities. When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require our current swap dealer counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which capital requirements rule could increase the costs to us of future financial derivatives transactions. The Volcker Rule provisions of the Dodd-Frank Act may also require our current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as creditworthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us, as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.
As a result, the Dodd-Frank Act and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect our capital available for other commercial operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.
If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
Should we fail to comply with all applicable statutes, rules, regulations and orders administered by the CFTC or the Federal Energy Regulatory Commission (“FERC”), we could be subject to substantial penalties and fines.
Under the Energy Policy Act of 2005, FERC has been given greater civil penalty authority under the Natural Gas Act (“NGA”), including the ability to impose penalties of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC under the NGA. Under the Commodity Exchange Act (as amended by the Dodd-Frank Act) and regulations promulgated thereunder by the CFTC, the CFTC has also adopted anti-market manipulation, fraud and market disruption rules relating to the prices of commodities, futures contracts, options on futures, and swaps. Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, the FERC, or the CFTC from time to time. Failure to comply with those statutes, regulations, rules and orders could subject us to civil penalty liability.
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.
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 resume and sustain 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.
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 resume or sustain 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 resume, maintain and 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 and Wright, independent petroleum engineering firms 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 and development operations will require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of 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.
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; 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 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 has focused 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, particularly in the current commodity price environment. 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.
Our business strategy involves the use of the latest available horizontal drilling, completion and production technology, which involve risks and uncertainties in their application.
Our operations involve the use of the latest horizontal drilling, completion and production technologies, as developed by us and our service providers, in an effort to improve efficiencies in recovery of hydrocarbons. Use of these new technologies may not prove successful and could result in significant cost overruns or delays or reduction in production, and in extreme cases, the abandonment of a well. The difficulties we face drilling horizontal wells include:
·landing our wellbore in the desired drilling zone;
·staying in the desired drilling zone while drilling horizontally through the formation;
·running our production casing the entire length of the wellbore; and
·running tools and other equipment consistently through the horizontal wellbore.
Difficulties that we face while completing our wells include the following:
·designing and executing the optimum fracture stimulation program for a specific target zone;
·running tools the entire length of the wellbore during completion operations; and
·cleaning out the wellbore after completion of the fracture stimulation.
In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the application of technology developed in drilling, completing and producing in one productive formation may not be successful in other prospective formations with little or no horizontal drilling history. If our use of the latest technologies does not prove successful, our drilling and production results may be less than anticipated or we may experience cost overruns, delays in obtaining production or abandonment of a well. As a result, the return on our investment will be adversely affected, we could incur material write-downs of unevaluated properties or undeveloped reserves and the value of our undeveloped acreage and reserves could decline in the future.
We could experience periods of higher costs if oil and natural gas prices rise or as drilling activity otherwise increases in our area of operations. Higher costs could reduce our profitability, cash flow and ability to pursue our drilling program as planned.
Historically, our capital and operating costs typically rise during periods of sustained increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control as drilling activity increases, such as increases in the cost of electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that we and our vendors rely upon; and the cost of services and labor especially those required in horizontal drilling and completion. Since late 2014, oil and natural gas prices declined substantially resulting in decreased levels of drilling activity in the U.S. oil and natural gas industry, including in our area of operations. This led to significantly lower costs of some drilling and completion equipment, services, materials and supplies. As commodity prices rise or stabilize or drilling activity otherwise increases in our area of operations, these lower cost levels may not be sustainable over long periods. As a result, such costs may rise thereby negatively impacting our profitability, cash flow and causing us to possibly reconfigure or reduce our drilling program.
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;
·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 are owned by others. If these plants were to cease operations for any reason, we would need to arrange for alternative transportation and processing facilities. These alternative facilities may not be available, which could cause us to shut-in our natural gas production, or the alternative facilities could be more expensive than the facilities we currently use.
Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and 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 business depends on gathering and compression facilities owned by third parties and transportation facilities owned by third-party transporters and we rely on third parties to gather and deliver our oil, natural gas and NGLs to certain designated interconnects with third-party transporters. Any limitation in the availability of those facilities or delay in providing interconnections to newly drilled wells would interfere with our ability to market the oil, natural gas and natural gas liquids we produce and could reduce our revenues and cash available for distribution.
The marketability of our oil, natural gas and natural gas liquids production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties in the respective operating areas. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, compression or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the oil and natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering, compression and transportation facilities, could reduce our revenues and cash available for distribution.
The third parties on whom we rely for gathering, compression and transportation services are subject to complex federal, state and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
The operations of the third parties on whom we rely for gathering, compression and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to resume distributions to our unitholders.
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 subjects 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 operations are subject to complex and stringent laws and regulations, which are continuously being reviewed for amendment and/or expansion. 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, and may incur liabilities under, federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration and production of oil, natural gas and natural gas liquids.
For example, several states have enacted Surface Damage Acts (“SDAs”) that are designed to compensate surface owners/users for damages caused by mineral owners. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. In addition, many states, including Texas, impose a production, ad valorem or severance tax with respect to the production and sale of oil and gas within their jurisdiction.
Other activities subject to regulation are:
●the location and spacing of wells;
●the method of drilling and completing and operating wells;
●the rate and method of production;
●the surface use and restoration of properties upon which wells are drilled and other exploration activities;
●notice to surface owners and other third parties;
●the venting or flaring of natural gas;
●the plugging and abandoning of wells;
●the discharge of contaminants into water and the emission of contaminants into air;
●the disposal of fluids used or other wastes obtained in connection with operations;
●the marketing, transportation and reporting of production; and
●the valuation and payment of royalties.
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 has adopted rules to regulate methane emissions, including from new and modified oil and gas production sources and natural gas processing and transmission sources, and has announced its intention to regulate methane emissions from existing oil and gas sources, although it remains unclear the status of future rulemaking under the new administration, This rule is also the subject of pending appeals. In late 2016, BLM adopted rules governing flaring and venting on public and tribal lands, which could require additional equipment and emissions controls as well as inspection requirements. These rules have been challenged in court and remain in litigation. Additionally, the US House of Representatives has passed a resolution under the Congressional Review Act disapproving the rules; Senate action remains pending.
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 EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. This interpretation by the EPA may constitute an expansion of federal jurisdiction over waters of the United States. The rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 as that appellate court and several other courts hear lawsuits opposing implementation of the rule. In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Litigation surrounding this rule is ongoing. Further, the EPA has published guidance on hydraulic fracturing using diesel and has published an advanced notice of public rulemaking under the Toxic Substances Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. Further, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. This ongoing scrutiny of hydraulic fracturing, depending on the degree of pursuit and any meaningful results obtained, could result in further regulation of hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory programs.
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. 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 depends 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.
The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flows and not our profitability.
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, or other borrowings, and not solely on profitability, which is affected by noncash items. As a result, we may be unable to resume the payment of distributions even when we record net income and we may be able to resume the payment of distributions during periods when we incur net losses.
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 $450.0 million. 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. Additional 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, 2016, we had outstanding borrowings of $265.0 million which bore a weighted average effective interest rate of 3.75%. 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 April 2019. Restrictions in our credit facility and our 8% senior notes due April 2019 may limit our ability to resume and sustain distributions to our unitholders and may limit our ability to capitalize on acquisitions and other business opportunities.
Our credit facility and 8% senior notes due April 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. The requirement that we comply with these provisions may materially adversely affect our ability to make distributions to our unitholders, react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continued or future downturn in our business. We are currently in compliance with all of the covenants contained in the most recent ninth amendment of our credit agreement and expect to be in compliance through the end of 2017. Absent a rebound in commodity prices or an amendment to our credit facility, we currently project that we will not be in compliance with our leverage covenant at the end of the first quarter of 2018. See Item 1A. Risk Factors - Covenants in our credit agreement may restrict our ability to resume and sustain distributions.
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 resume or sustain distributions to our unitholders and service our debt obligations.
Our business requires a significant amount of capital expenditures to maintain and grow production levels. Commodity prices have historically been volatile, and we cannot predict the prices we will receive in the future. 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.
Oil and gas exploration and production activities are complex and involves risks that could lead to legal proceedings resulting in the incurrence of substantial liabilities.
Like many oil and gas companies, we are from time to time involved in various legal and other proceedings in the ordinary course our business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liabilities, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
Loss of our information and computer systems could adversely affect our business.
We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
Cyber-attacks targeting systems and infrastructure used by the oil and natural gas industry may adversely impact our operations.
Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and natural gas distribution systems in the U.S. and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and natural gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.
While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.
Risks Inherent in an Investment in Us
The price of our units could be subject to wide fluctuations and unitholders could lose a significant part of their investment.
From the beginning of 2015 through the fourth quarter of 2016, the quoted market prices of our common units fluctuated from a high of $21.38 to a low of $1.51. The market prices of our common units are subject to fluctuations in response to a number of factors, most of which we cannot control, including, but not limited to:
●fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publically traded limited partnerships and limited liability companies;
●changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry, including fluctuations in commodity prices;
●changes in securities analysts’ recommendations and their estimates of our financial performance;
●the public’s reaction to our press releases, announcements and our filings with the SEC;
●changes in market valuations of similar companies;
●departures of key personnel;
●commencement of or involvement in litigation;
●variations in our quarterly results of operations or those of other oil and natural gas companies;
●variations in the amount of our quarterly cash distributions; and
●future issuances and sales of our units.
In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.
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. John B. 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. Kenneth Mariani, a director of EV Management, is also President 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 15, 2017, officers and directors of EV Management owned an aggregate of 10.5% of our outstanding common units. Accordingly, it may be difficult for holders of our common units to remove our general partner.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
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.
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.
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.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by legislative, judicial or administrative changes and differing interpretations at any time. Specifically, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, such a proposal could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, it is anticipated that the Trump administration will pass tax reform, and it is possible that such legislation could negatively impact our U.S. federal income taxation. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
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, 2016.
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 15, 2017, based upon information received from our transfer agent and brokers and nominees, we had 351 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 2016 and 2015:
_____________
(1)Cash distributions are declared and paid in the following calendar quarter.
(2)During 2016, the board of directors of EV Management announced that it had elected to suspend distributions for the first three quarters of 2016. The board of directors also elected to suspend distributions for the fourth quarter of 2016.
Cash Distributions to Unitholders
We have suspended cash distributions to unitholders in order to conserve cash and improve our liquidity. Prior to reinstating distributions, we will ensure that we are, and will continue to be, in compliance with the covenants contained in our credit agreement. We are currently in compliance with all of the covenants contained in the most recent ninth amendment of our credit agreement and, at current forward prices, expect to be in compliance through the end of 2017. At the end of first quarter of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we may have a total debt to EBITDAX ratio higher than the level prescribed in the most recent Ninth Amendment of our credit agreement. Absent a rebound in commodity prices, we currently project that we will not be in compliance with our leverage covenant at the end of the first quarter of 2018, and this may require us to make payments on our debt facilities or require us to work with our bank syndicate to amend our credit agreement. Our inability to amend our credit agreement or otherwise comply with the covenants in our credit agreement could have a material, adverse effect on our business, including our ability to resume and sustain distributions. 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 11 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 financial statements. With the sale of our interest in Cardinal in October 2014 and UEO in June 2015, we no longer operate in the midstream segment, and we have reclassified our consolidated financial statements for all periods presented to reflect the operations of our midstream segment as discontinued operations. Accordingly, in the consolidated statements of operations, amounts previously included in “Equity in income of unconsolidated affiliates” have been reclassified to “Income from discontinued operations.” 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.
As of December 31, 2016, our oil and natural gas properties were located in the Barnett Shale, the San Juan Basin, the Appalachian Basin (which includes the Utica Shale), Michigan, Central Texas (which includes the Austin Chalk area), the Monroe Field in Northern Louisiana, the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana and the Permian Basin. As of December 31, 2016, we had estimated net proved reserves of 12.6 MMBbls of oil, 575.3 Bcf of natural gas and 33.4 MMBbls of natural gas liquids, or 851.2 Bcfe, and a standardized measure of $371.1 million.
Current Price Environment
Oil, natural gas and natural gas liquids prices are determined by many factors that are outside of our control. Historically, these prices have been volatile, and we expect them to remain volatile. In late 2014, prices for oil, natural gas and natural gas liquids declined precipitously, and prices remained low through 2015 and most of 2016. While prices showed some improvement during the second half of 2016 and the beginning of 2017, they have continued to fluctuate.
Factors contributing to lower oil prices include real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle East; lower forecasted levels of global economic growth combined with excess global supply; actions taken by the Organization of Petroleum Exporting Countries; and the strength of the U.S. dollar in international currency markets. Factors contributing to lower natural gas prices include increased supplies of natural gas due to greater exploration and development activities; higher levels of natural gas in storage; and competition from other energy sources. Prices for natural gas liquids generally correlate to the price of oil and, accordingly, prices remain lower than historical levels and are likely to continue to directionally follow the market for oil.
In 2016, these low prices negatively affected our revenues, earnings and cash flows, and continued volatility in prices for oil, natural gas and natural gas liquids could have a material adverse effect on our liquidity. Continued volatility or further declines in prices could also have a significant adverse impact on the value and quantities of our reserves, assuming no other changes in our development plans.
As specified by the SEC, the prices for oil, natural gas and natural gas liquids used to calculate our reserves were the average prices during the year determined using the price on the first day of each month. The prices utilized in calculating our total estimated proved reserves at December 31, 2016 were $42.75 per Bbl of oil and $2.481 per MMBtu of natural gas, which is significantly lower than current forward strip prices. Had we used the forward strip prices at December 31, 2016 through December 2029, we estimate that the present value (discounted at 10% per annum) of estimated future net revenues of our proved reserves would have been approximately 111% higher and that our reserves on an Mcfe basis would have been approximately 50% higher than our reserves calculated using SEC prices.
Our Response to the Current Price Environment
In 2016, in response to continued lower prices, we took a number of actions to preserve our liquidity and financial flexibility, including:
·repurchased $82.7 million of our outstanding senior notes due April 2019 for $35.0 million;
·reduced the amount of capital spending we dedicated to the development of our reserves by approximately 75%;
·continued to reduce operating and capital costs;
·amended our credit facility to, among other things, ease the leverage covenants until 2018;
·continued to evaluate strategic divestitures such as our recent Barnett Shale divestiture and acquisitions of long-life, producing oil and natural gas properties; and
·reevaluated our common unit distribution policy and suspended our common unit distribution to conserve excess cash.
As a result of the steps above, as of December 31, 2016, we have over $205 million of liquidity between our borrowing base capacity, cash on hand and restricted cash. However, given current forward oil and natural gas prices and the fact that we have less production hedged at lower prices beginning in 2017 relative to previous years, we have taken additional steps going forward into 2017 to continue to preserve our liquidity and financial flexibility. These steps include:
·focusing on managing and enhancing our base business through continued reductions in operating costs;
·increasing our capital spending budget to $30 - $45 million from $10.7 million in 2016, in an effort to maintain current production levels;
·maintaining a sufficient liquidity position to manage through the current environment, which includes continuing to assess the appropriate distribution levels every quarter;
·continuing to evaluate strategic acquisitions of long-life, producing oil and natural gas properties such as our Eagle Ford Acquisition in January 2017; and
·further realizing the value of our undeveloped acreage through either alternative sources of capital, including farmouts, production payments and joint ventures, or potential monetization of acreage.
During 2016, the board of directors of EV Management announced that it had elected to suspend distributions for the first three quarters of 2016. The board of directors also elected to suspend distributions for the fourth quarter of 2016. The company continues to generate positive distributable cash flow, albeit at significantly lower levels than in previous years. The board of directors continues to evaluate the distribution on a quarterly basis and may elect to reinstate the distribution at the appropriate time when commodity prices and operating cash flows have increased to a level that can support a sustainable distribution.
In December 2016, we sold a portion of our Barnett Shale natural gas properties for $52.1 million (before post-closing adjustments), which proceeds were deposited into a 1031 ‘like-kind' exchange account. On January 31, 2017, we acquired a 5.8% working interest in 9,151 gross acres (529 net acres) in Karnes County, TX for $58.7 million (before post-closing purchase price adjustments) with the proceeds and $6.6 million of borrowings under our credit facility (the “Eagle Ford Acquisition”). Certain EnerVest institutional partnerships own an 87% working interest in, and EnerVest acts as operator of, the properties.
Business Environment
One of our primary business objectives is to generate sufficient excess cash flow that will allow us to reinstate a stable distribution, which we will be able to grow over time. Prior to reinstating distributions, we will ensure that we are, and will continue to be, in compliance with the covenants in our credit agreement. We are currently in compliance with all of the covenants contained in our credit agreement and, at current forward prices, expect to be in compliance through the end of 2017. At the end of first quarter of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we may have a total debt to EBITDAX ratio higher than the level prescribed in the most recent Ninth Amendment of our credit agreement. Absent a rebound in commodity prices, we currently project that we will not be in compliance with our leverage covenant at the end of the first quarter of 2018, and this may require us to make payments on our debt facilities or require us to work with our bank syndicate to amend our credit agreement. Our inability to amend our credit agreement or otherwise comply with the covenants in our credit agreement could have a material, adverse effect on our business, including our ability to resume and sustain distributions. The amount of cash we can distribute on our units principally depends upon the amount of cash generated from our operations, which will fluctuate from quarter to quarter based on, among other things:
·the prices at which we will sell our oil, natural gas liquids and natural gas production;
·our ability to hedge commodity prices;
·the amount of oil, natural gas liquids and natural gas we produce; and
·the level of our operating and administrative costs.
In order to mitigate the impact of these lower 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. Although we have entered into derivative contracts covering a portion of our future production through March 2018, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future. We have mitigated, but not eliminated, the potential effects of changing prices on our cash flows from operations for those periods. An extended period of depressed commodity prices would alter our acquisition and development plans, adversely affect our growth strategy and our ability to access additional capital in the capital markets and reduce the cash we have available to pay distributions, which may require us to further delay our ability to reinstate our quarterly distribution amount.
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.
In 2016, we spent significantly less capital drilling wells relative to previous years. As a result, we saw our total production decline throughout the year, when adjusting for the oil and natural gas properties that we acquired on October 1, 2015. For 2017, we plan to spend $30 - $45 million of capital in an effort to keep our production flat. We will continue monitoring the ongoing commodity price environment and expect to retain the financial flexibility to adjust plans in response to market conditions as needed.
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 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, our credit worthiness 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.
Goodwill
Goodwill is an asset representing the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. In accounting for a business combination, the purchase price is allocated to the identifiable assets and liabilities based upon the estimated fair values as of the acquisition date. Goodwill is the excess of the purchase price over the estimated fair values of the assets acquired net of the liabilities assumed in the acquisition. Goodwill is not amortized, but is evaluated for impairment at the reporting unit level.
We have the option of performing either a qualitative or quantitative assessment to determine if impairment may have occurred. If the qualitative assessment indicates that it is more likely than not that the fair value of our reporting unit is less than its carrying amount, then we would be required to perform the two step impairment test.
Under the first step in the impairment test, we compare the fair value of our reporting unit with its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step of the goodwill impairment test is performed. Under the second step in the impairment test, the implied fair value of goodwill is compared with its carrying amount. The implied fair value of goodwill is calculated by subtracting the estimated fair values of our reporting unit’s assets net of liabilities from the fair value of our reporting unit. If the carrying amount of goodwill exceeds its implied fair value, an impairment loss shall be recognized in an amount equal to that excess.
We determine the fair value of the reporting unit using a combination of the market approach and the income approach. Under the market approach, the fair value is based on the quoted market price for our common units adjusted for a control premium, which is the premium over current market price a market participant may be willing to pay to obtain the synergies and other benefits that control would provide. Under the income approach, the fair value was based on the expected present value of the future net cash flows. Significant assumptions associated with the calculation of the fair value include estimates of the appropriate control premium, future prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates and other relevant data. Given the nature of these estimates and their application to specific assets and liabilities and time frames, it is not possible to reasonably quantify the impact of changes in these assumptions.
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, 2016 Compared with the Year Ended December 31, 2015
Net loss for 2016 was $242.9 million compared with net income of $21.3 million for 2015. The significant factors in this change were (i) a $255.5 million decrease in income from discontinued operations; (ii) a $114.1 million unfavorable change in gain (loss) on derivatives; partially offset by (iii) a $65.9 million decrease in impairment of goodwill; and (iv) a $23.7 million increase in gain on early extinguishment of debt.
Oil, natural gas and natural gas liquids revenues for 2016 totaled $182.7 million, an increase of $7.6 million compared with 2015. This was the result of increases of $18.5 million related to increased oil, natural gas and natural gas liquids production as a result of the October 2015 acquisitions offset by decreases of $10.9 million related to lower prices for oil, natural gas and natural gas liquids.
Lease operating expenses for 2016 increased $3.7 million compared with 2015 as the result of $9.9 million from increased oil and natural gas production offset by $6.2 million from a lower cost per Mcfe. The lower unit cost per Mcfe reflects the downward trend in operating costs throughout the oil and natural gas industry. Lease operating expenses per Mcfe were $1.46 in 2016 compared with $1.56 in 2015.
Dry hole and exploration costs for 2016 decreased $3.0 million compared with 2015 as a result of our decreased drilling program during 2016.
Production taxes for 2016 increased $0.6 million compared with 2015 due to higher oil, natural gas and natural gas liquids revenues. Production taxes for 2016 were $0.10 per Mcfe compared with $0.11 per Mcfe for 2015.
Depreciation, depletion and amortization (“DD&A”) for 2016 increased $13.2 million compared with 2015 due to $11.5 million of increased oil and natural gas production combined with $1.7 million from a higher average DD&A rate per Mcfe. The higher average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates. DD&A for 2016 was $1.69 per Mcfe compared with $1.66 per Mcfe for 2015.
General and administrative expenses for 2016 totaled $33.6 million, a decrease of $5.4 million compared with 2015. This decrease is primarily the result of (i) $5.4 million of lower equity compensation costs, of which $2.3 million related to the accelerated vesting of the phantom units of a former officer in 2015; (ii) $1.3 million of decreased compensation costs, of which $0.8 million related to the vesting of our phantom units under our equity compensation plan; partially offset by (iii) $1.7 million of higher fees paid to EnerVest under the omnibus agreement related to our October 2015 acquisition. General and administrative expenses were $0.48 per Mcfe in 2016 compared with $0.62 per Mcfe in 2015.
As a result of a reduction in estimated future net cash flows primarily caused by the decrease in prices for oil, natural gas and natural gas liquids and the disposition of oil and gas properties, we incurred impairment charges of $131.3 million and $136.7 million in 2016 and 2015, respectively. Of these amounts, $89.5 million and $86.9 million in 2016 and 2015, respectively, 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. The $89.5 million of impairment for 2016 related to oil and natural gas properties in the Barnett Shale which were sold during December 2016 (see Note 5). Significant 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 our estimated reserves, appropriate risk-adjusted discount rates and other relevant data. The remainder of the impairment charges in 2016 consisted of $41.8 million of leasehold impairments, of which $35.8 million related to a change in our development plans for acreage in the Appalachian Basin, primarily in the Utica Shale. The remainder of the impairment charges in 2015 consisted of $49.8 million of leasehold impairments, of which $49.2 million related to a change in our development plans for acreage in the Utica Shale.
In conjunction with our October 2015 acquisitions of oil and natural gas properties, we recorded $65.9 million of goodwill. As of December 31, 2015, we determined that the carrying amount of goodwill was impaired due to the continued decline in oil, natural gas and natural gas liquids prices. We determined the fair value of the reporting unit using a combination of the market approach and the income approach. Significant assumptions associated with the calculation of the fair value included estimates of future prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates and other relevant data. We then determined the implied fair value of goodwill by subtracting the estimated fair values of the reporting unit’s assets net of liabilities from the fair value of the reporting unit. As the carrying amount of the goodwill exceeded the implied fair value of the goodwill, we recognized a $65.9 million impairment loss for the difference between the carrying amount and the implied fair value of goodwill.
In 2015, we recognized a gain of $0.6 million on the sale of certain non-core oil and natural gas properties.
Loss on derivatives, net was $36.0 million for 2016 compared with a gain on derivatives, net of $78.1 million for 2015. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at December 31, 2016 for oil averaged $56.19 per Bbl compared with $40.45 at December 31, 2015, and the 12 month forward prices at December 31, 2016 for natural gas averaged $3.61 per MmBtu compared with $2.49 at December 31, 2015. The 12 month forward price at December 31, 2015 for oil averaged $40.45 per Bbl compared with $56.46 per Bbl at December 31, 2014, and the 12 month forward price at December 31, 2015 for natural gas averaged $2.49 per MmBtu compared with $3.03 at December 31, 2014.
Interest expense for 2016 decreased $7.8 million compared with 2015 due to $9.4 million from a lower weighted average long-term debt balance, partially offset by $0.1 million from a higher weighted average effective interest rate and the write-off of $1.5 million of loan costs due to the reduction in the borrowing base and the redemption of the senior notes due April 2019.
In 2016, we recognized a $47.7 million gain on the early extinguishment of debt as we redeemed $82.7 million of our Notes due April 2019 for $35.0 million. In 2015, we recognized a $24.0 million gain on the early extinguishment of debt as we redeemed $74.0 million of our Notes due April 2019 for $50.0 million.
In 2016, we recorded approximately $2.4 million of tax benefits as a result of tax refunds and lower taxes. In December 2015, we converted our wholly-owned subsidiary Belden and Blake Corporation (“Belden”) from a corporation into a single member limited liability company. As a result, the $13.4 million of deferred taxes recorded in the acquisition of Belden were realized. The benefit was offset by an $11.7 million current tax liability for the estimated federal and state taxes based on the fair value of Belden as of the date of conversion.
Income from discontinued operations was $255.5 million in 2015. Included in 2015 was the $246.7 million gain on the sale of UEO.
Year Ended December 31, 2015 Compared with the Year Ended December 31, 2014
Net income for 2015 was $21.3 million compared with $129.7 million for 2014. The significant factors in this change were (i) a $159.6 million decrease in oil, natural gas and natural gas liquids revenues; (ii) a $32.8 million decrease in gain on sale of oil and natural gas properties; (iii) a $65.9 million impairment of goodwill; (iv) a $22.7 million increase in impairment of oil and natural gas properties; and (v) a $21.6 million unfavorable change in gain (loss) on derivatives; offset by (v) a $148.0 million increase in income (loss) from discontinued operations; (vi) a $24.0 million gain on early extinguishment of debt and (vii) a $21.2 million decrease in operating costs and expenses (excluding impairment of oil and natural gas properties and impairment of goodwill).
Oil, natural gas and natural gas liquids revenues for 2015 totaled $175.1 million, a decrease of $159.6 million compared with 2014. This was the result of decreases of $159.8 million related to lower prices for oil, natural gas and natural gas liquids and $0.5 million from decreased oil production from our reduced capital spending program and natural decline offset by $0.7 million related to increased oil and natural gas production as a result of the October 2015 acquisitions.
Lease operating expenses for 2015 decreased $6.2 million compared with 2014 as the result of $6.6 million from a lower cost per Mcfe offset by $0.4 million from increased oil and natural gas production. The lower unit cost per Mcfe reflects the downward trend in operating costs throughout the oil and natural gas industry. Lease operating expenses per Mcfe were $1.56 in 2015 compared with $1.66 in 2014.
Dry hole and exploration costs for 2015 decreased $3.0 million compared with 2014 as a result of lower costs at certain of our oil and natural gas properties in the Appalachian Basin and the Austin Chalk.
Production taxes for 2015 decreased $5.2 million compared with 2014 due to lower oil, natural gas and natural gas liquids revenues. Production taxes for 2015 were $0.11 per Mcfe compared with $0.19 per Mcfe for 2014.
Depreciation, depletion and amortization (“DD&A”) for 2015 decreased $0.1 million compared with 2014 due to $0.5 million from a lower average DD&A rate per Mcfe offset by $0.4 million of increased oil and natural gas production. The lower average DD&A rate per Mcfe reflects the change that 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 2014. DD&A for 2015 was $1.66 per Mcfe compared with $1.67 per Mcfe for 2014.
General and administrative expenses for 2015 totaled $39.0 million, a decrease of $6.0 million compared with 2014. This decrease is primarily the result of (i) $7.3 million of lower equity compensation costs; (ii) $1.0 million of costs incurred in 2014 related to the departure of a former officer; and (iii) $0.9 million of decreased compensation costs related to the vesting of our phantom units issued under our equity based compensation plan; offset by (iv) $2.1 million of higher fees paid to EnerVest under the omnibus agreement, (v) $0.8 million of increased audit and reserve fees as a result of our October 2015 acquisitions; and (vi) $0.9 million of due diligence costs related to our October 2015 acquisitions. General and administrative expenses were $0.62 per Mcfe in 2015 compared with $0.71 per Mcfe in 2014.
As a result of a reduction in estimated future net cash flows primarily caused by the decrease in prices for oil, natural gas and natural gas liquids, we incurred impairment charges of $136.7 million and $114.0 million in 2015 and 2014, respectively. Of these amounts, $86.9 million and $103.1 million in 2015 and 2014, respectively, 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 prices, production costs, development expenditures, anticipated production of our estimated reserves, appropriate risk-adjusted discount rates and other relevant data. The remainder of the impairment charges in 2015 consisted of $49.8 million of leasehold impairments, of which $49.2 million related to a change in our development plans for acreage in the Utica Shale. The remainder of the impairment charges in 2014 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 conjunction with our October 2015 acquisitions of oil and natural gas properties, we recorded $65.9 million of goodwill. As of December 31, 2015, we determined that the carrying amount of goodwill was impaired due to the continued decline in oil, natural gas and natural gas liquids prices. We determined the fair value of the reporting unit using a combination of the market approach and the income approach. Significant assumptions associated with the calculation of the fair value included estimates of future prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates and other relevant data. We then determined the implied fair value of goodwill by subtracting the estimated fair values of the reporting unit’s assets net of liabilities from the fair value of the reporting unit. As the carrying amount of the goodwill exceeded the implied fair value of the goodwill, we recognized a $65.9 million impairment loss for the difference between the carrying amount and the implied fair value of goodwill.
In 2015, we recognized a gain of $0.6 million on the sale of certain non-core oil and natural gas properties. 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.
Gain on derivatives, net was $78.1 million for 2015 compared with $99.7 million for 2014. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at December 31, 2015 for oil averaged $40.45 per Bbl compared with $56.46 at December 31, 2014, and the 12 month forward prices at December 31, 2015 for natural gas averaged $2.49 per MmBtu compared with $3.03 at December 31, 2014. 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.
Interest expense for 2015 decreased $2.2 million compared with 2014 due to $10.6 million from a higher weighted effective average interest rate and $5.7 million from a decrease in capitalized interest offset by $18.5 million from a lower weighted average long-term debt balance.
In 2015, we recognized a $24.0 million gain on the early extinguishment of debt as we redeemed $74.0 million of our Notes due April 2019 for $50.0 million.
In December 2015, we converted Belden from a corporation into a single member limited liability company. As a result, the $13.4 million of deferred taxes recorded in the acquisition of Belden were realized. The benefit was offset by an $11.7 million current tax liability for the estimated federal and state taxes based on the fair value of Belden as of the date of conversion.
Income from discontinued operations was $255.5 million for 2015 compared with $107.5 million in 2014. Included in 2015 and 2014 were the $246.7 million gain on the sale of UEO and the $92.1 million gain of the sale of Cardinal, respectively.
LIQUIDITY AND CAPITAL RESOURCES
Historically, our primary sources of liquidity and capital have been issuances of equity and debt securities, borrowings under our credit facility and cash flows from operations. Our primary uses of cash have been acquisitions of oil and natural gas properties and related assets, development of our oil and natural gas properties, distributions to our unitholders and general partner and working capital needs.
In 2016, in response to continued lower prices, we took a number of actions, including repurchasing outstanding senior notes, reducing capital spending and operating costs, suspending distributions on our common units and strategic divestitures of non-core assets, to preserve our liquidity and financial flexibility. As a result of these steps, as of December 31, 2016, we have over $205 million of liquidity between our borrowing base capacity, cash on hand and restricted cash. However, given current forward oil and natural gas prices and the fact that we have less production hedged at lower prices beginning in 2017 relative to previous years, we have taken additional steps going forward into 2017 to continue to preserve our liquidity and financial flexibility. These steps include:
·focusing on managing and enhancing our base business through continued reductions in operating costs;
·increasing our capital spending budget to $30 - $45 million from $10.7 million in 2016, in an effort to maintain current production levels;
·maintaining a sufficient liquidity position to manage through the current environment, which includes continuing to assess the appropriate distribution levels every quarter;
·continuing to evaluate strategic acquisitions of long-life, producing oil and natural gas properties such as our Eagle Ford Acquisition in January 2017; and
·further realizing the value of our undeveloped acreage through either alternative sources of capital, including farmouts, production payments and joint ventures, or potential monetization of acreage.
For 2017, 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 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.
Long-term Debt
As of December 31, 2016, we have a $1.0 billion credit facility that expires in February 2020. 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, 2016, the borrowing base was $450.0 million, and we had $265.0 million outstanding. We believe we will maintain sufficient short-term liquidity. However, should prices decline significantly from current levels, the borrowing base could be reduced again in future redeterminations, which would impact our short-term liquidity.
In April 2016, we entered into an amendment to our credit facility that eased leverage covenants and added an interest coverage ratio. Specifically, the amendment:
·decreased the borrowing base to $450.0 million;
·changed the senior secured funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016, 3.0 to 1.0, (b) for the fiscal quarters ending March 31, 2017 and June 30, 2017, 3.5 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and December 31, 2017, 4.0 to 1.0;
·changed the total funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2018, 5.50 to 1.0, (b) for the fiscal quarters ending June 30, 2018 and September 30, 2018, 5.25 to 1.0 and (c) for the fiscal quarter ending December 31, 2018 and thereafter, 4.25 to 1.0;
·added an EBITDAX to cash interest expense ratio covenant to be no less than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016 and September 30, 2016, 2.5 to 1.0, (b) for the fiscal quarters ending December 31, 2016, March 31, 2017 and June 30, 2017, 2.0 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and thereafter, 1.5 to 1.0;
·allowed for up to $35.0 million of cash, reduced dollar for dollar by the amount of any quarterly distributions for the remainder of 2016, to be used for the redemption of our senior notes due April 2019; and
·limited cash held by us to the greater of 5% of the current borrowing base or $30.0 million.
As of December 31, 2016, we have $343.3 million in aggregate principal amount outstanding of 8.0% senior notes due April 2019. As of December 31, 2016, the aggregate carrying amount of the senior notes due April 2019 was $341.9 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, 2016, we had $5.6 million of cash and cash equivalents, which included $0.7 million of short-term investments. With regard to our short-term investments, we invest in money market accounts with major financial institutions.
Restricted Cash
At December 31, 2016, we had $52.1 million of restricted cash, which represents proceeds from the Barnett Shale divestiture we deposited with a qualified intermediary to facilitate like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code. In January 2017, these proceeds were used to fund, in part, the Eagle Ford Acquisition.
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, 2016, all of our counterparties have performed pursuant to their derivative contracts.
Cash Flows
Operating Activities
Cash flows from operating activities provided $33.9 million and $141.3 million in 2016 and 2015, respectively. The significant factors in the change were $85.8 million of decreased cash settlements from our matured derivative contracts, an $11.7 million federal tax payment related to the conversion of an acquired corporation to a single member LLC and a $28.9 million change in working capital, primarily related to higher accounts receivable as a result of higher oil, natural gas and natural gas liquids production during 2016.
Cash flows from operating activities provided $141.3 million and $148.2 million in 2015 and 2014, respectively. The significant factors in the change were a $161.1 million decrease in our revenues offset by $135.3 million of increased cash settlements from our matured derivative contracts and the effects of our efforts to increase our financial flexibility through asset sales and accretive acquisitions.
Investing Activities
During 2016, cash flows used in investing activities from continuing operations totaled $9.8 million. This consisted of $52.1 million of restricted cash deposited with a qualified intermediary to facilitate like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code and $15.3 million for additions to our oil and natural gas properties offset by $54.5 million from the sale of oil and natural gas properties and $3.0 million in cash settlements from acquired derivative contracts.
During 2015, cash flows used in investing activities from continuing operations totaled $280.4 million. This consisted of $250.4 million for acquisitions of oil and natural gas properties, $67.9 million for additions to our oil and natural gas properties offset by $33.8 million from the release of cash deposited with a qualified intermediary to facilitate like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code, $2.6 million in cash settlements from acquired derivative contracts and $1.5 million in proceeds from the sales of oil and natural gas properties. Net cash flows provided by investing activities from discontinued operations of $572.2 million consisted of the proceeds from the sale of our interest in UEO.
During 2014, cash flows used in investing activities from continuing operations totaled $93.8 million, consisting of $102.8 million for additions to our oil and natural gas properties and an increase of $33.8 million related to cash deposited with a qualified intermediary to facilitate like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code offset by $45.2 million in proceeds from the sale of oil and natural gas properties. Net cash flows provided by investing activities from discontinued operations of $47.0 million consisted of $161.1 million in proceeds from the sale of our interest in Cardinal offset by $114.1 million of additions to our investment in UEO.
Financing Activities
During 2016, we received $57.0 million from borrowings under our credit facility, repaid $57.0 million of borrowings under our credit facility, and paid distributions of $3.9 million to holders of our common units, phantom units and our general partner. We also redeemed $82.7 million of our senior notes due April 2019 for $35.0 million.
During 2015, we repaid $561.0 million of borrowings under our credit facility with proceeds from the sale of our investment in UEO and the release of our restricted cash. We also redeemed $74.0 million of our senior notes due April 2019 for $50.0 million, received $295.0 million from borrowings under our credit facility, incurred loan costs of $4.1 million related to the amendments of our credit facility and paid distributions of $101.0 million to holders of our common units, phantom units and our general partner.
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.
Capital Requirements
We currently expect spending in 2017 for additions to our oil and natural gas properties to be between $30 million and $45 million, an increase from the amounts spent in 2016. In addition, we spent $58.7 million (before post-closing purchase price adjustments) for the Eagle Ford Shale properties we acquired on January 31, 2017.
We expect to fund these amounts with cash on hand, restricted cash, 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 2017 through the issuance of equity or debt securities.
Contractual Obligations
(1)Amounts represent the expected cash payments for interest based on (i) the amount outstanding under our credit facility as of December 31, 2016 and the weighted average interest rate for 2016 of 3.75%, and (ii) our $343.3 million in aggregate principal amount of 8.0% senior notes due April 2019. Such amounts do not include the effects of our interest rate swaps.
(2)Amounts represent commitments under a firm transportation agreement at current rates.
(3)Amounts represent payments to be made under our omnibus agreement with EnerVest based on the amount that we will pay in 2017. This amount will increase or decrease as we purchase or divest assets. While these payments will continue for periods subsequent to December 31, 2017, 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, 2016 is $183.5 million.
Off-Balance Sheet Arrangements
In the normal course of business, we may enter into off-balance sheet arrangements that give rise to off-balance sheet obligations. As of December 31, 2016, we have entered into off-balance sheet arrangements which totaled $0.3 million.
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 resume and sustain distributions;
·our business strategy and plans, and future capital expenditures, including plans to optimize the value of our assets;
·our estimated net proved reserves, PV-10 value and standardized measure;
·market prices;
·our future derivative activities; and
·our plans and forecasts.
We have based these forward-looking statements on our current assumptions, expectations and projections about future events.
The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward-looking statements. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Form 10-K including, but not limited to:
·fluctuations in prices of oil, 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;
·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 March 2018. As of December 31, 2016, we have derivatives covering approximately 85% of our production attributable to our estimated net proved reserves through March 2018, 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, 2016 was a liability of $22.6 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 $17.4 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, 2016.
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, 2016 which is included in “Item 8. Financial Statements and Supplementary Data” contained herein.
/s/ MICHAEL E. MERCER
/s/ NICHOLAS BOBROWSKI
Michael E. Mercer
Nicholas Bobrowski
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 28, 2017
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, 2016 and 2015, 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, 2016. We also have audited the Partnership's internal control over financial reporting as of December 31, 2016, 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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 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, 2016, 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 28, 2017
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)
EV Energy Partners, L.P.
Consolidated Statements of Cash Flows (continued)
(In thousands)
See accompanying notes to consolidated financial statements.
EV Energy Partners, L.P.
Consolidated Statements of Changes in Owners’ Equity
(In thousands, except number of units)
See accompanying notes to consolidated financial statements.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
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 operates one reportable segment engaged in the acquisition, development and production of oil and natural gas properties and all of our operations are located in the United States.
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 units, 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, 2016 and 2015, we did not have any reserves for doubtful accounts, and we did not incur any expense related to bad debts. We do not have any off-balance sheet credit exposure related to our customers
Property and Depreciation
Our oil, 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 $20.9 million and $67.6 million as of December 31, 2016 and 2015, 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 2016, 2015 and 2014, we recorded dry hole and exploration costs of $0.7 million, $3.7 million and $6.7 million, respectively.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
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 Oil and Natural Gas Properties
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 2016, 2015 and 2014, we recorded impairment charges of $89.5 million, $86.9 million and $103.3 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 7). The $89.5 million of impairment for 2016 related to oil and natural gas properties in the Barnett Shale which were sold during December 2016 (see Note 5). Since December 31, 2016, commodity prices have continued to fluctuate. If commodity prices significantly decrease before March 31, 2017, or in future quarters, we could have additional impairments of our oil and natural gas properties.
Unproved oil and natural gas properties are assessed periodically on a property-by-property basis, and any impairment in value is recognized. For 2016, 2015 and 2014, we recorded impairment charges of $41.8 million, $49.8 million and $10.7 million, respectively, related to unproved oil and natural gas properties where we had a change in development plans for the acreage.
Goodwill
We recorded $65.9 million of goodwill in conjunction with our October 2015 acquisitions (see Note 4). Goodwill was calculated as the excess of the purchase price over the estimated fair values of the assets acquired net of the liabilities assumed in the acquisitions. The goodwill was not amortized, but was evaluated for impairment as the declining oil and natural price environment indicated the carrying value of goodwill may not be recoverable (see Note 7).
The changes in the carrying amount of goodwill are as follows:
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.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
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.
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, 2016 or 2015.
We own and operate a network of natural gas gathering systems in the Appalachian Basin and 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.
In October 2015, we acquired Belden & Blake Corporation (“Belden”), a taxable entity (see Note 4). We used the asset and liability method of accounting for income taxes. Under this method, deferred taxes were provided for temporary differences as of the date of acquisition between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. In December 2015, Belden was converted from a corporation into a single member limited liability company (see Note 12).
Earnings per Limited Partner Unit
We use the two-class method to compute earnings per limited partner unit. The two-class method is an earnings allocation formula that determines earnings per unit for our common units and participating securities as if all earnings for the period had been distributed. As our unvested phantom units and our earned but unvested performance units participate in dividends on an equal basis with our common units, they are considered to be participating securities. Earnings used in the determination of earnings per limited partner unit for the current reporting period are reduced by the amount of earnings allocated to the general partner and available cash that will be distributed to the limited partners and the participating securities. The undistributed earnings, if any, are then allocated to the limited partners and the participating securities in accordance with the terms of the partnership agreement. Basic and diluted earnings per limited partner unit are then calculated by dividing earnings, after deducting the amount allocated to the general partner and the earnings attributable to the participating securities, by the weighted average number of outstanding limited partner units during the period.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
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.
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, 2016, 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 2016, three customers accounted for 18.5%, 13.4% and 10.4%, respectively, of our consolidated oil, natural gas and natural gas liquids revenues. In 2015, two customers accounted for 17.1% and 10.8%, respectively, of our consolidated oil, natural gas and natural gas liquids revenues. In 2014, 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 May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers. This ASU superseded 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, 2017 and interim periods within those annual periods. We plan to implement ASU 2014-09 as of January 1, 2018 using the modified retrospective method with the cumulative effect, if any, of initial adoption to be recognized at the date of initial application. We are in the initial stages of our evaluation of the impact of the new standard on our accounting policies, processes, system requirements and financial reporting. Based on the evaluation performed to date, we expect to identify similar performance obligations as compared with deliverables and separate units of account previously identified, and we expect the timing of our revenue to remain the same. We will continue to assess the impact of adopting this ASU.
In August 2014, the FASB issued ASU 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 the annual reporting period ending after December 15, 2016 and for annual periods and interim periods thereafter. The adoption of this ASU did not have a material impact on our consolidated financial statements.
In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement Period Adjustments. To simplify the accounting for adjustments made to provisional amounts, ASU 2015-16 requires that the acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amount is determined. The provisions of ASU 2015-16 are effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years. The adoption of this ASU did not have a material impact on our consolidated financial statements.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
In February 2016, the FASB issued ASU No. 2016-02, Leases. The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. ASU 2016-02 further defines a lease as a contract that conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. Control over the use of the identified asset means that the customer has both (1) the right to obtain substantially all of the economic benefit from the use of the asset and (2) the right to direct the use of the asset. ASU 2016-02 requires disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. We are in the initial stages of our evaluation of the impact of this new standard on our accounting policies, processes, system requirements and financial reporting.
In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation. This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures and statutory withholding requirements, as well as classification in the statement of cash flows. The provisions of ASU 2016-09 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for financial statements that have not yet been previously issued. We do not expect that adopting this ASU will have a material impact on our consolidated financial statements.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows. This ASU addresses certain cash flow issues with the objective of reducing the existing diversity in practice in how the cash receipts and cash payments are presented and classified in the statement of cash flows. The provisions of ASU 2016-15 are applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. Early adoption is permitted for financial statements that have not yet been previously issued. We do not expect that adopting this ASU will have a material impact on our consolidated financial statements.
In November 2016, the FASB issued ASU No. 2016-18: Statement of Cash Flows- Restricted Cash. The main objective of ASU 2016-18 is to address the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows. The amendments in ASU 2016-18 require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Thus, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flows. For public entities, ASU 2016-18 is effective for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years; early application is permitted. 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, 2016 have had or are expected to have a material impact on our consolidated financial statements.
Subsequent Events
We evaluated subsequent events for appropriate accounting and disclosure through the date these consolidated financial statements were issued.
NOTE 3. EQUITY-BASED COMPENSATION
EV Management has two long-term incentive plans, the 2006 Long-Term Incentive Plan (the “2006 Plan”) and the 2016 Long-Term Incentive Plan (the “2016 Plan” and together, the “Plans”) for employees, consultants and directors of EV Management and its affiliates who perform services for us. The 2006 Plan expired on September 20, 2016, and on August 30, 2016, the unitholders approved the adoption of the 2016 Plan, which replaced the 2006 Plan with respect to future awards. The 2016 Plan provides for the issuance of up to 5,000,000 units and allows for the award of unit options, phantom units, performance units, restricted units and deferred equity rights. As of December 31, 2016, the aggregate amount of our common units that may be awarded under the 2016 Plan was 4.0 million units. The compensation committee of the board of directors administers the Plans.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
Phantom Units
Equity Awards
We account for phantom units 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 2016, 2015 and 2014 was $8.4 million, $15.2 million and $11.9 million, respectively.
We recognized compensation cost related to these phantom units of $6.6 million, $11.8 million and $13.9 million in 2016, 2015 and 2014, respectively. These costs are included in “General and administrative expenses” in our consolidated statements of operations.
As of December 31, 2016, there was $9.2 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.4 years.
Performance Units
In September 2011, we issued 0.3 million performance units to certain employees and executive officers of EV Management and its affiliates. These performance units vested 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. These performance units were fully vested as of January 2015.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
The total grant date fair value of the performance units vested in 2015 and 2014 was $1.6 million and $1.4 million, respectively.
We recognized compensation cost related to our performance units of $0.2 million and $5.4 million in 2015 and 2014, respectively. These costs are included in “General and administrative expenses” in our consolidated statements of operations.
NOTE 4. ACQUISITIONS
On January 31, 2017, we acquired a 5.8% working interest in acreage in Karnes County, TX for $58.7 million (before post-closing purchase price adjustments) with the $52.1 million of proceeds from the divestiture of our Barnett Shale natural gas properties (see Note 5) and $6.6 million of borrowings under our credit facility (the “Eagle Ford Acquisition”). Certain EnerVest institutional partnerships own an 87% working interest in, and EnerVest acts as operator of, the properties.
In October 2015, we made the following acquisitions from certain institutional partnerships managed by EverVest, a related party:
·we acquired Belden for $111.1 million, and we recognized $5.6 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations for 2015;
·we acquired oil and natural gas properties in the Austin Chalk for $25.9 million, and we recognized $4.9 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations for 2015; and
·we acquired oil and natural gas properties in the Appalachian Basin and the San Juan Basin for $122.0 million, and we recognized $4.5 million of oil, natural gas and natural gas liquids revenues related to this acquisition in our consolidated statement of operations for 2015.
These acquisitions were not accounted for as common control transactions as EnerVest does not control the institutional partnerships that sold the oil and natural gas properties.
As part of the acquisition of oil and natural gas properties in the San Juan Basin, we assumed an obligation to deliver approximately 2.4 billion cubic feet (“Bcf”) of natural gas through December 31, 2016 under previously existing volumetric production payment (“VPP”) agreements. Under these agreements, certain of these oil and natural gas properties are subject to fixed-term overriding royalty interests which had been conveyed to the VPP purchaser. While we were obligated under these agreements to produce and deliver to the purchaser its portion of natural gas production from these oil and natural gas properties, we retain control of these oil and natural gas properties and rights to future development drilling. If production from the oil and natural gas properties subject to the VPP were inadequate to deliver the natural gas provided for in the VPP, we had an obligation to make up the shortfall in accordance with the provisions of the agreements.
At December 31, 2016, we had no remaining obligation under these agreements and no liability for the cost to produce and deliver to the VPP purchasers their portion of future natural gas production from these oil and natural gas properties. At December 31, 2015, the remaining obligation under these agreements was approximately 1.9 Bcf of natural gas, and we had a liability of $4.0 million for the cost to produce and deliver to the VPP purchasers their portion of future natural gas production from these oil and natural gas properties. In 2016 and 2015, we recorded $0.1 million and $0.1 million, respectively, of accretion expense related to this VPP obligation.
We accounted for these acquisitions as business combinations. The following table reflects pro forma revenues and net income for the years ended December 31, 2015 and 2014 as if these acquisitions had taken place on January 1, 2014. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
The recognized fair values of the identifiable assets acquired and liabilities assumed in connection with these acquisitions are as follows:
The amounts allocated to goodwill represent the future benefits arising from acquiring these assets from EnerVest, which has experience operating these properties, and from adding balance to our existing portfolio by increasing our positions in the Appalachian Basin, Michigan, the San Juan Basin and the Austin Chalk. Of the $65.9 million allocated to goodwill, $20.2 of the amount will be deductible for income tax purposes.
NOTE 5. DIVESTITURES
In December 2016, we, along with certain institutional partnerships managed by EnerVest, closed on the sale of a portion of our Barnett Shale natural gas properties, and our share of the proceeds was $52.1 million (before post-closing adjustments). Also, during 2016, we received proceeds of $2.4 million for the sale of other oil and gas properties.
In 2015, we closed on the sale of non-core oil and natural gas properties for aggregate proceeds of $1.5 million.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
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.
We sold oil and natural gas properties in East Texas for $5.8 million. In conjunction with the sale, we incurred an additional impairment charge of $0.2 million (see Note 7). Operating results related to these properties were included in our exploration and production segment.
In addition, we closed on the sale of 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.
NOTE 6. RISK MANAGEMENT
Our business activities expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids. In addition, our floating rate credit facility exposes us to risks associated with changes in interest rates. As such, future earnings are subject to fluctuation due to changes in 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, 2016, we had entered into oil, natural gas and natural gas liquids derivatives with the following terms:
As of December 31, 2016, 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, 2016 and 2015, we were not required to post any collateral nor did we hold any collateral associated with our derivatives.
NOTE 7. FAIR VALUE MEASUREMENTS
The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value. Level 1 refers to fair values determined based on quoted prices in active markets for identical assets or liabilities. Level 2 refers to fair values determined based on quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration. Level 3 refers to fair values determined based on our own assumptions used to measure assets and liabilities at fair value.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
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. Furthermore, fair values are adjusted to reflect the credit risk inherent in the transaction, which may include amounts to reflect counterparty credit quality and/or the effect of our own creditworthiness. These assumed credit risk adjustments are based on published credit ratings, public bond yield spreads and credit default swap spreads. There were no changes in valuation techniques or related inputs in 2016.
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
We did not incur any impairment charges in 2016 for any of our oil and natural gas properties that were held and used as December 31, 2016. As a result of reductions in estimated future net cash flows primarily caused by the decrease in prices for oil, natural gas and natural gas liquids, we incurred impairment charges of $86.9 million and $103.1 million in 2015 and 2014, respectively, to write down oil and natural gas properties to their fair value. These impairment charges were included in earnings in 2015 and 2014, respectively.
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, appropriate risk-adjusted discount rates and other relevant data.
Long-lived Assets Held for Sale
In 2014, we incurred additional impairment charges of $0.2 million to write down assets held for sale to their fair value. These impairment charges were included in earnings for 2014.
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.
Goodwill
In 2015, we determined that the carrying amount of goodwill was impaired due to the continued decline in oil, natural gas and natural gas liquids prices. We have only one reporting unit, and we determined the fair value of the reporting unit using a combination of the market approach and the income approach. Under the market approach, the fair value was based on the quoted market price for our common units as of December 31, 2015 (our market capitalization), adjusted for a control premium. The determination of the control premium was based on our judgment as to what we believe would be standard in our industry. Under the income approach, the fair value was based on the expected present value of the future net cash flows. Significant Level 3 assumptions associated with the calculation of the fair value included estimates of future prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates and other relevant data. We then determined the implied fair value of goodwill by subtracting the estimated fair values of the reporting unit’s assets net of liabilities from the fair value of the reporting unit. As the carrying amount of the goodwill exceeded the implied fair value of the goodwill, we recognized a $65.9 million impairment loss for the difference between the carrying amount and the implied fair value of goodwill.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
Financial Instruments
The estimated fair values of our financial instruments have been determined at discrete points in time based on relevant market information. Our financial instruments consist of cash and cash equivalents, restricted cash, 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, 2016 and December 31, 2015, the estimated fair value of our senior notes due April 2019 was $242.6 million and $211.9 million, respectively, which differs from the carrying value of $341.9 million and $423.6 million, respectively. The fair value of the senior notes due April 2019 was determined using Level 2 inputs.
NOTE 8. ASSET RETIREMENT OBLIGATIONS
The changes in the aggregate ARO are as follows:
As of December 31, 2016 and 2015, $3.2 million and $2.9 million, respectively, of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our consolidated balance sheets.
NOTE 9. LONG-TERM DEBT, NET
Long-term debt, net consisted of the following as of December 31:
(1)Imputed interest rate of 8.99% and 8.87% for 2016 and 2015, respectively.
(2)Imputed interest rate of 7.22% and 7.35% for 2016 and 2015, respectively.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
Credit Facility
As of December 31, 2016, we have a $1.0 billion credit facility that expires in February 2020. 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. As of December 31, 2016, we have a $0.3 million letter of credit outstanding.
The facility does not require any repayments of amounts outstanding until it expires in February 2020. Borrowings under the facility bear interest at a floating rate based on, at our election, a base rate or the London Inter-Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that we have outstanding (weighted average effective interest rate of 3.75% and 3.73% at December 31, 2016 and 2015, 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, 2016, the borrowing base under the facility was $450.0 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.
In April 2016, we entered into an amendment to our credit facility that eased leverage covenants and added an interest coverage ratio. Specifically, the amendment:
·decreased the borrowing base to $450.0 million;
·changed the senior secured funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016, 3.0 to 1.0, (b) for the fiscal quarters ending March 31, 2017 and June 30, 2017, 3.5 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and December 31, 2017, 4.0 to 1.0;
·changed the total funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2018, 5.50 to 1.0, (b) for the fiscal quarters ending June 30, 2018 and September 30, 2018, 5.25 to 1.0 and (c) for the fiscal quarter ending December 31, 2018 and thereafter, 4.25 to 1.0;
·added an EBITDAX to cash interest expense ratio covenant to be no less than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016 and September 30, 2016, 2.5 to 1.0, (b) for the fiscal quarters ending December 31, 2016, March 31, 2017 and June 30, 2017, 2.0 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and thereafter, 1.5 to 1.0;
·allowed for up to $35.0 million of cash, reduced dollar for dollar by the amount of any quarterly distributions for the remainder of 2016, to be used for the redemption of our senior notes due April 2019; and
·limited cash held by us to the greater of 5% of the current borrowing base or $30.0 million.
As of December 31, 2016, we were in compliance with these financial covenants.
8.0% Senior Notes due April 2019
Our 8.0% senior unsecured notes due April 2019 (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.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
In 2016, we redeemed $82.7 million of the Notes for $35.0 million, resulting in a gain on the early extinguishment of debt of $47.7 million. In 2015, we redeemed $74.0 million of the Notes for $50.0 million, resulting in a gain on the early extinguishment of debt of $24.0 million.
The remaining Notes are subject to redemption, at our option, 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:
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.
NOTE 10. COMMITMENTS AND CONTINGENCIES
We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material effect on our consolidated financial statements, and no amounts have been accrued at December 31, 2016 and 2015.
We are subject to firm agreements for the future transportation and processing of natural gas. We are obligated to transport minimum daily natural gas volumes. As of December 31, 2016, our future minimum transportation fees under these agreements are as follows for the years ended December 31:
NOTE 11. OWNERS’ EQUITY
Units Outstanding
At December 31, 2016, owner’s equity consists of 49,055,214 common units outstanding (including 5,032,399 common units held by our executive officers and directors), collectively representing a 98% limited partnership interest in us and a 2% general partnership interest.
Common Units
The common units have limited voting rights as set forth in our partnership agreement.
Pursuant to our partnership agreement, if at any time our general partner and its affiliates own more than 80% of the common units outstanding, our general partner has the right, but not the obligation, to “call” or acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then current market value. Our general partner may assign this call right to any of its affiliates or to us.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
General Partner Interest
Our general partner owns a 2% interest in us. This interest entitles our general partner to receive distributions of available cash from operating surplus as discussed further below under Cash Distributions. Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, Class B unitholders and general partner will receive.
The general partner has the management rights as set forth in our partnership agreement.
Allocations of Net Income
Net income is allocated between our general partner and the limited partners in accordance with the provisions of our partnership agreement. Net income is generally allocated first to our general partner and the limited partners in an amount equal to the net losses allocated to our general partner and the limited partners in the current and prior tax years under the partnership agreement. The remaining net income is allocated to our general partner and the limited partners in accordance with their respective percentage interests of the general partner and limited partners.
Cash Distributions
In the future, we intend 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.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
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, 2016 and 2015:
During 2016, the board of directors of EV Management announced that it had elected to suspend distributions for the first three quarters of 2016. The board of directors also elected to suspend distributions for the fourth quarter of 2016.
NOTE 12. INCOME TAXES
In December 2015, we converted Belden from a corporation into a single member limited liability company. As a result, the $13.4 million of deferred taxes recorded in the acquisition of Belden were realized. The benefit was offset by an $11.7 million current tax liability for the estimated federal and state taxes based on the fair value of Belden as of the date of conversion. As of December 31, 2015, Belden is no longer a tax paying entity.
Income taxes were as follows for the year ended December 31, 2015:
Of the $236.0 million of loss from continuing operations before income taxes for the year ended December 31, 2015, $45.7 million represents the loss that is subject to federal taxation.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
The effective tax rate on the loss subject to federal taxation differs from the U.S. statutory rate as follows for 2015:
Our tax filings for four years are subject to examination by federal and state tax authorities where we conduct our business. These examinations may result in assessments of additional tax that are resolved with the authorities or through the courts. We have evaluated whether any material tax position we have taken will more likely than not be sustained upon examination by the appropriate taxing authority. As we believe that all such material tax positions we have taken are supportable by existing laws and related interpretations, we believe there are no material uncertain tax positions to consider.
In 2016, we recorded approximately $2.4 million of tax benefits as a result of tax refunds and lower taxes.
NOTE 13. DISCONTINUED OPERATIONS
Our midstream segment, which consisted of our investments in Utica East Ohio Midstream LLC (“UEO”) and Cardinal Gas Services, LLC (“Cardinal”), was 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. In June 2015, we sold our interest in UEO and received net proceeds of $572.2 million and recognized a gain of $246.7 million. In October 2014, we sold our interest in Cardinal and received net proceeds of $161.1 million and recognized a gain of $92.1 million. These gains are included in “Income from discontinued operations.” As a result of these sales, the Partnership no longer operates in the midstream segment.
As a result of the reduction in the borrowing base under our facility upon the sale of our interest in UEO, we were required to repay $25.0 million of outstanding borrowings. Accordingly, $1.5 million of interest related to this $25.0 million and the write off of deferred financing costs related to the reduction in the borrowing base have been allocated to “Income from discontinued operations” in 2015.
Summarized financial information for our midstream segment was as follows:
(1)Information is for UEO on a stand-alone basis through the date of divestiture.
(2)Information is for UEO and Cardinal on a combined basis.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
NOTE 14. EARNINGS PER LIMITED PARTNER UNIT
The following sets forth the calculation of earnings per limited partner unit for the years ended December 31:
As of December 31, 2016 and 2015, there are no unearned performance units outstanding. As of December 31, 2014, 0.2 million unearned performance units were not included in the computation of diluted net income (loss) per limited partner unit because the effect would have been anti-dilutive.
NOTE 15. RELATED PARTY TRANSACTIONS
Pursuant to our omnibus agreement with EnerVest, we paid EnerVest $15.9 million, $14.2 million and $12.1 million in 2016, 2015 and 2014, 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 2016, 2015 and 2014, we reimbursed EnerVest approximately $21.2 million, $17.2 million and $17.0 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.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
As of December 31, 2016, we owed EnerVest Operating $5.8 million and partnerships managed by EnerVest owed us $0.7 million.
In October 2015, we acquired oil and natural gas properties in the Appalachian Basin, the San Juan Basin, Michigan and the Austin Chalk from certain institutional partnerships managed by EverVest for a combined cash consideration of $259.0 million (see Note 4).
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 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 and account for our investment using the equity method of accounting. We recognized $0.1 million, $0.2 million and $0.4 million of income in 2016, 2015 and 2014, respectively, and we received $0.1 million, $0.2 million and $0.3 million of distributions in 2016, 2015 and 2014, respectively.
NOTE 16. 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:
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
NOTE 17. QUARTERLY DATA (UNAUDITED)
(1)Represents total revenues less lease operating expenses, cost of purchased natural gas and production taxes.
(2)Includes impairment charges of $131.3 million, primarily in the fourth quarter of 2016. Of this amount, $89.5 million related to oil and natural gas properties in the Barnett Shale that were written down to their fair value as determined based on the expected present value of the future net cash flows. The remainder of the impairment charges in 2016 consisted of $41.8 million of leasehold impairments, of which $35.8 million related to a change in our development plans for acreage in the Appalachian Basin, primarily in the Utica Shale.
(3)Includes the effects of the acquisitions of oil and natural gas properties in October 2015 (see Note 4).
(4)Includes gain on sale of our investment in UEO of $246.7 million in the second quarter of 2015.
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, 2016 and 2015 have been prepared by Cawley, Gillespie & Associates, Inc. and Wright & Company, Inc., independent petroleum consultants. The estimates of our proved reserves as of December 31, 2014 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.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
(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.
(4)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.
(5)Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (78.2 Bcfe) and the Appalachian Basin (33.0 Bcfe).
(6)Revisions were primarily attributable to the Barnett Shale (120.7 Bcfe) and the Appalachian Basin (76.9 Bcfe) and are the result of the decrease in prices for oil, natural gas and natural gas liquids used in our December 31, 2015 reserve estimates from prices used in our December 31, 2014 reserve estimates.
(7)Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (72.6 Bcfe) and the Appalachian Basin (16.9 Bcfe).
(8)Revisions were primarily attributable to reductions in the Appalachian Basin (51.8 Bcfe), the Barnett Shale (39.9 Bcfe) and Central Texas (13.5 Bcfe) and are the result of the decrease in prices for oil, natural gas and natural gas liquids used in our December 31, 2016 reserve estimates from prices used in our December 31, 2015 reserve estimates.
(9)Extensions and discoveries were primarily associated with drilling success in the Barnett Shale (13.0 Bcfe).
(10)Sales of minerals in place were primarily associated with the sale of a portion of our Barnett Shale natural gas properties (74.2 Bcfe) in December 2016.
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%.
EV Energy Partners, L.P.
Notes to Consolidated Financial Statements (continued)
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, 2016, 2015 and 2014 were $42.75 per Bbl of oil, $2.481 per MMBtu of natural gas; $50.28 per Bbl of oil, $2.587 per MMBtu of natural gas; and $94.99 per Bbl of oil, $4.35 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.
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
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, 2016 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, 2016. 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, 2016 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
On February 23, 2017, 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 2017, at a monthly fee of $1,175,000. 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, which 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. EnCap is entitled to designate one director and EnerVest appoints the remainder. 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.
Directors and Executive Officers
All of our executive management personnel, other than Messrs. Mercer and Bobrowski, are employees of EnerVest. Messrs. Mercer and Bobrowski are employees of EV Management and devote all of their time to our business and affairs.
We estimate that Messrs. Walker and Flory devote approximately 25% and 30%, 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 2016, we paid EnerVest $15.9 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 15, 2017 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
Michael E. Mercer
President, Chief Executive Officer and Director
Nicholas P. Bobrowski
Vice President and Chief Financial Officer
Ryan J. Flory
Controller
Mark A. Houser
Director
Kenneth Mariani
Director
Victor Burk (1) (2)
Director
James R. Larson (1)
Director
George Lindahl III (1) (2)
Director
Gary R. Petersen (2)
Director
(1)Member of the audit committee and the conflicts committee.
(2)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 currently include serving on the Board of Stewards of Chapelwood United Methodist Church, the Board of Directors of the Sam Houston Area Council of the Boy Scouts of America and the Board of Directors of Stoney Creek Ranch. 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.
Michael E. Mercer has served as our President and Chief Executive Officer since March 2015. Prior to that, he was 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.
Nicholas P. Bobrowski has served as Vice President and Chief Financial Officer since March 2015. Prior to that, Mr. Bobrowski served as Director of Finance of EV Management since 2013. From 2007 to 2012, he 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 an MBA from the Sloan School of Management at MIT.
Ryan J. Flory has served as Controller of EV Management since February 2014 and as Senior Vice President and Chief Accounting Officer of EnerVest, Ltd. since January 2017. Prior to that, Mr. Flory served as Vice President and Controller of EnerVest, Ltd. since January 2014 and Corporate Controller 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.
Mark A. Houser has been a member of our board since 2006. He was named Chief Executive Officer of University Lands in March 2015, where he oversees activities on 2.1 million acres of Permanent University lands that serve as a resource for both the University of Texas and Texas A&M University. Before joining University Lands, Mr. Houser served as our President and Chief Executive Officer from January 2012 through February 2015. Prior to that, he served as our President and Chief Operating Officer since 2006. He also served as Executive Vice President and Chief Operating Officer of EnerVest, Ltd. from 1999 through 2015. 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.
Kenneth Mariani was appointed to the board in February 2015. He currently serves as the President of EnerVest, Ltd., a position he has held since January 2014. Prior to that, he served as Executive Vice President of EnerVest, Ltd. and President and Chief Executive Officer of EnerVest Operating Company from January 2012 to January 2014. Mr. Mariani joined EnerVest in 2000 and was Senior Vice President and General Manager - Eastern Division for 11 years. 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 of the Permian Basin and is a licensed Professional Engineer.
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 Holdings, L.P. (NYSE: PAGP). He is also a board member of the 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
Effective March 1, 2015, EV Management’s board of directors was expanded from six to eight members, one of which, Mr. Petersen, was appointed by EnCap, and the remainder of which were appointed by EnerVest.
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 2016, 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 plans (the “Plans”).
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 2016, the board of directors had eight regularly scheduled and special meetings, the audit committee had four meetings, the compensation committee had two meetings and the conflicts committee had three 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 2016, 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. Michael E. Mercer and Mr. Nicholas P. Bobrowski are employees of EV Management, and we reimburse EV Management for the costs of their compensation. Messrs. Mercer and Bobrowski do not currently perform services for EnerVest or its affiliates (other than EV Management). Their compensation is approved by the compensation committee of EV Management’s board of directors, which we refer to as our compensation committee.
Mr. John B. Walker is an officer of EV Management and is also an officer and employee of other subsidiaries of EnerVest. In these capacities, he performs services for us as well as for EnerVest and its other affiliates. In order to compensate Mr. Walker for the time he devotes to our business and to provide our compensation committee with oversight of the portion of his annual bonus reflecting his services to us, a portion of his cash bonus was reviewed and approved by our compensation committee, and we reimburse EnerVest for this cash bonus. In addition, Mr. Walker continues to participate in the Plans.
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 payment 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 Mr. Walker’s cash bonus charged to us, we do not directly reimburse EnerVest for the costs of the compensation of Mr. Walker and our compensation committee does not oversee his annual compensation. Awards made to Messrs. Walker, Kenneth Mariani and Ryan J. Flory and other employees of EnerVest under the Plans 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 takes into account 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 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 Messrs. Mercer and Bobrowski, 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 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: Bill Barrett Corp.; Carrizo Oil & Gas, Inc.; Clayton Williams Energy, Inc.; Jones Energy, Inc.; Laredo Petroleum Holdings, Inc.; Legacy Reserves LP; Matador Resources Company; Memorial Production Partners, L.P.; Oasis Petroleum; PDC Energy, Inc.; Resolute Energy Corporation; Sanchez Energy Corporation; Unit 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 to management regarding executive and director compensation.
In connection with setting base salary for 2017 and bonus and long-term equity incentive compensation for 2016, 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. Our compensation committee does not employ a specific target or market percentile for any element of compensation. The compensation committee takes into consideration a number of factors in making compensation decisions.
Performance Metrics
With respect to bonus and long-term incentive awards, our compensation committee did not establish performance metrics for our executive officers for 2016 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 large 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 our long-term incentive plans 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.
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 effectively compete with others 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 2016, in an effort to further reduce costs, our chief executive officer recommended, and the committee approved, reducing the base salaries for Messrs. Mercer and Bobrowski from 2015 amounts ($350,000 and $230,000, respectively) by 10%, effective March 1, 2016. Accordingly, the actual pro-rated base salaries for 2016 were $320,833 for Mr. Mercer and $210,833 for Mr. Bobrowski. This results in total direct compensation (base salary, bonus and long-term incentive) for Messrs. Mercer and Bobrowski below the 25th percentile of the peer group.
In February 2015, Mr. Mercer’s base salary was increased to $350,000 in conjunction with his promotion to Chief Executive Officer of EV Management with an actual pro-rated base salary of $310,167.
In February 2015, in conjunction with Mr. Bobrowski’s appointment as the Chief Financial Officer of EV Management, the compensation committee set the base salary for Mr. Bobrowski at $230,000, with an actual pro-rated base salary of $225,000.
In December 2016, our chief executive officer recommended, and the committee approved, reinstating 50% of the 10% reduction taken in March 2016. Thus, the base salaries for 2017 for Messrs. Mercer and Bobrowski were only reduced by 5%, effective January 1, 2017, and the actual base salaries for 2017 will be $332,500 for Mr. Mercer and $218,500 for Mr. Bobrowski. This results in total direct compensation (base salary, bonus and long-term incentive) for Messrs. Mercer and Bobrowski below the 25th 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 also reviewed and approved a portion of the cash bonus paid to Mr. Walker.
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 Messrs. Mercer and Bobrowski. In this recommendation, the compensation committee, in determining the cash bonus amounts, took into account its belief that the efforts of Messrs. Mercer and Bobrowski directly affected the achievement of the following key operational objectives in 2016:
·we repurchased $82.7 million of our senior notes due April 2019 for $35.0 million;
·we amended our credit facility to, among other things, ease the leverage covenants until 2018; and
·we ended the year with over $205 million of liquidity between borrowing base capacity, cash on hand and restricted cash.
In 2016, Mr. Mercer received a total bonus of $140,348, of which $104,224 was contributed to the Retirement Plan and $36,124 was delivered in cash. The total bonus represents 44% of his total base salary, which amount placed Mr. Mercer below the 25th percentile of cash bonus compensation of our peer group. In 2016, Mr. Bobrowski received a total bonus of $80,000, of which $7,537 was the amount contributed to the Retirement Plan and $72,463 was delivered in cash. The total bonus represents 38% of his total base salary, which amount placed Mr. Bobrowski below the 25th percentile of cash bonus compensation of our peer group. The bonuses for Messrs. Mercer and Bobrowski also reflected the committee’s determination that their performances in accomplishing the 2016 objectives described above were very strong.
In addition, Mr. Walker was awarded a cash bonus of $75,000, representing a portion of his total annual compensation paid by us and EnerVest. The amount of his bonus was recommended to our compensation committee by Mr. Walker based on his subjective view as to appropriate compensation levels taking into account the performance objectives discussed above and, in the case of Mr. Walker, the amount of time he spent on our business activities. The compensation committee then determined to accept this recommendation.
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 large 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.
On August 30, 2016, the common unitholders approved the EV Energy Partners, L.P. 2016 Long-Term Incentive Plan (the “2016 Plan”), which provides for the issuance of up to 5,000,000 units. The 2016 Plan became effective by its terms on the date of approval by the unitholders and replaces the 2006 Long-Term Incentive Plan (the “2006 Plan” and together, the “Plans”) as to future issuances.
The compensation committee acts as the administrator of the Plans 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 Plans. 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.
For grants under the 2006 Plan, the compensation committee, in its discretion, can provide that 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 involuntary termination of a grantee’s employment without good reason, the compensation committee, in its discretion, can provide that all outstanding equity based awards will vest effective upon the normal vesting date that coincides with, or immediately follows, the termination.
For grants under the 2016 Plan, the compensation committee, in its discretion, can provide that in the event of a termination of employment upon a change of control or the grantee’s death or disability, all outstanding equity based awards will immediately vest. In the event of involuntary termination of a grantee’s employment without good reason, the compensation committee, in its discretion, can provide that equity based awards scheduled to vest on the vesting date that coincides with, or immediately follows, the termination will vest effective upon the normal vesting date, and all other outstanding equity based awards will be forfeited as of the date of termination.
We have provided compensation committee discretion with respect to 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 Plans permit 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 Plans may be unit options, phantom units, performance units, restricted units and deferred equity rights, or DERs. There are 1.3 million common units awarded and outstanding under the 2006 Plan, and the aggregate amount of our common units that may be awarded under the 2016 Plan is 5.0 million units. As of December 31, 2016, there are 4.0 million units available for issuance. Unless earlier terminated by us or unless all units available under the 2016 Plan have been paid to participants, the 2016 Plan will terminate as of the close of business on August 30, 2026.
Although the 2016 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 - Messrs. Mercer and Bobrowski were granted 102,843 and 51,316 phantom units, respectively, in December 2016. These phantom units vest as described above over a four year period. These awards were 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 objectives described above. Our compensation committee reviewed these recommendations with our chief executive officer. In addition, our compensation committee compared the recommended award amounts with similar awards to our peer group. In determining final grant amounts, the committee also took into account the leadership roles of Messrs. Mercer and Bobrowski in causing us to achieve the objectives described above. The phantom units granted to Messrs. Mercer and Bobrowski were below the 25th percentile of the peer group.
Mr. Walker made a recommendation to the compensation committee for the appropriate level of awards to be made to Mr. Walker based on his subjective view as to the appropriate compensation given the performance objectives achieved as discussed above. The compensation committee reviewed this recommendation and made a subjective determination as to the appropriate award level given the achievement of such objectives. The committee also compared this award determination to similar awards by our peer group. In determining the final grant amount, the committee took into account Mr. Walker’s leadership role in causing us to achieve the objectives described above and considered the peer group review. Accordingly, Mr. Walker was granted 115,461 phantom units in December 2016. The 2016 award puts Mr. Walker below the 25th percentile, after taking into account the percentage of his time devoted to our business. The value of the phantom units granted to Mr. Walker is deducted in calculating the omnibus fee we pay to EnerVest.
Benefits
We believe in a simple, straight-forward compensation program and, as such, Messrs. Mercer and Bobrowski are 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 Messrs. Mercer and Bobrowski.
Through EnerVest, we provide company benefits that we believe are standard in the industry. These benefits consist of a group medical, dental and vision insurance program for employees and their qualified dependents, group life insurance for employees, accidental death and dismemberment coverage for employees, a 401(k) employee savings and investment plan, and a defined benefit plan.
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. 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.
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. In 2016 and 2015, the total bonus paid to both Messrs. Mercer and Bobrowski were inclusive of the amount delivered in cash and in company contributions under the Retirement Plan. In 2014, the total base salary for Mr. Mercer was inclusive of the amount delivered in cash and in company contributions under the Retirement Plan.
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.
Messrs. Mercer and Bobrowski participate 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.
We reimburse EnerVest for any amounts contributed to the Retirement Plan and the 401(k) plan attributable to Messrs. Mercer and Bobrowski. In the Summary Compensation Table, the present values 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.
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 15, 2017, our named executive officers beneficially owned in the aggregate approximately 6.2% 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
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 salaries and bonuses for Messrs. Mercer and Bobrowski. Our compensation committee approved, and we reimbursed EnerVest for, cash bonuses paid to Mr. Walker in 2016 and 2015 and Messrs. Walker and Mark A. Houser in 2014 as listed in the table below. Mr. Walker is, and Mr. Houser was, 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.
(1)Represents amounts paid in December 2016, 2015 and 2014 as bonuses for services in 2016, 2015 and 2014, 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 2016, 2015 and 2014.
(3)Amounts in this column reflect the aggregate change during 2016, 2015 and 2014 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 Messrs. Mercer and Bobrowski, the amounts contributed by us to their 401(k) plans. In 2016, we contributed $35,000 and $35,000 to the 401(k) plans of Messrs. Mercer and Bobrowski, respectively. In 2015, we contributed $35,245 and $32,648 to the 401(k) plans of Messrs. Mercer and Bobrowski, respectively. Any perquisites or other personal benefits received were less than $10,000.
(5)Mr. Houser’s employment with us terminated in February 2015 and so he did not receive a bonus or unit awards in 2015 or 2016. In addition, under the terms of the award agreements, all phantom unit awards granted to Mr. Houser prior to his separation automatically vested on March 2, 2015. The value realized on vesting, which is not included in the table above, was $924,760.
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 2016. There were no grants of non-equity incentives or option awards.
(1)These phantom units vest 25% each year beginning in January 2018.
(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 2016.
Outstanding Equity Awards at Fiscal Year End
The following table sets forth certain information with respect to outstanding equity awards at December 31, 2016. There were no option awards outstanding.
(1)Based on the closing price of our common units on December 31, 2016 of $2.09.
(2)These phantom units vested in January 2017.
(3)One-half of these phantom units vested in January 2017, with the remaining one-half vesting in January 2018.
(4)One-third of these phantom units vested in January 2017, with one-third each vesting in January 2018 and January 2019.
(5)These phantom units vested 25% in January 2017, with 25% each vesting in January 2018, January 2019 and January 2020.
(6)These phantom units vest 25% each year beginning in January 2018.
Option Exercises and Units Vested
The following table sets forth certain information with respect to phantom units and performance units vested during 2016. There were no option awards that vested.
(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, 2016.
Pension Benefits
The following table sets forth certain information with respect to the Retirement Plan:
(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.
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, 2016, 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, 2016. In presenting this disclosure, we describe amounts earned through December 31, 2016 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, 2016, this amount would have been $630,000. 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, 2016, this amount would have been $37,959.
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, 2016, this amount would have been $630,000, representing 104 weeks of base salary, $471,489, representing vesting of unvested units, and $37,959 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;
·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;
·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, 2016, the value of the awards would have been $471,489. 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 an effort to further reduce costs, our chief executive officer recommended, and the committee approved, reducing the annual retainers and fees for 2016 for directors by 10%. Thus, in 2016, directors who were not officers or employees of EV Management, EnCap or their respective affiliates received an annual retainer of $36,000, with the chairmen of the audit committee and conflicts committee receiving an additional annual fee of $9,000 and the chairman of the compensation committee receiving an additional annual fee of $4,500. In addition, each non-employee director receives $900 per committee meeting attended ($450 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.
In December 2016, our chief executive officer recommended, and the committee approved, reinstating 50% of the 10% reduction taken in March 2016. Thus, in 2017, directors who are not officers or employees of EV Management, EnCap or their respective affiliates will receive an annual retainer of $38,000 with the chairmen of the audit committee and conflicts committee receiving an additional annual fee of $9,500 and the chairman of the compensation committee receiving an additional annual fee of $4,750. In addition, each non-employee director will receive $950 per committee meeting attended ($475 if by phone) and will be reimbursed for his out of pocket expenses in connection with attending meetings.
Each of the independent directors and Mr. Petersen were awarded 13,250 phantom units in December 2016. These phantom units vest 25% each year beginning in January 2018.
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, 2016:
(1)Messrs. Walker and Mariani 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 2016 computed in accordance with ASC Topic 718.
(3)Reflects the dollar amount of compensation recognized for financial statement reporting purposes for 2016 for distributions paid on the unvested phantom units.
(4)As of December 31, 2016, Messrs. Burk, Larson and Lindahl each have 29,656 equity awards outstanding, Mr. Houser has 25,750 equity awards outstanding and Mr. Petersen has 29,140 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 15, 2017 other than as set forth below.
The following table sets forth the beneficial ownership of our units as of February 15, 2017 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;
·each named executive officer of EV Management; 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)Includes 2,008,098 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.
(3)Includes 20,000 common units owned by a trust for Mr. Lindahl’s daughters. Mr. Lindahl disclaims beneficial ownership of these common units.
(4)Includes 523,666 common units owned by EnCap Energy Capital Fund V, L.P. and 414,280 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.
(5)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.
(6)Includes 160,803 common units owned by KS Mariani, LP, a limited partnership of which Mr. Mariani and his spouse are the general partner and 30,000 common units owned equally 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 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 could have issued under the 2006 Plan prior to its expiration in September 2016 was 4.5 million. The number of common units we may issue under the 2016 Plan is 5.0 million. The following table summarizes information about our equity compensation plans as of December 31, 2016:
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. John B. Walker and Kenneth 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 2016, we paid EnerVest $15.9 million in 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 include a deduction for the value of the awards we issue to EnerVest employees (including Messrs. Walker and Mariani) 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. In February 2017, EV Management and EnerVest extended the term of the omnibus agreement through December 2017.
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 2016, we reimbursed EnerVest approximately $21.2 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.
Acquisitions from Institutional Partnerships Managed by EnerVest
EnerVest is the general partner of institutional partnerships formed to acquire, develop and produce oil and natural gas properties. EnerVest generally has a 1% to 1.5% interest in the institutional partnerships that they manage, which increases to 20% following return of invested capital and a stated rate of return.
In October 2015, we acquired oil and natural gas properties in the Appalachian Basin, the San Juan Basin, Michigan and the Austin Chalk from certain institutional partnerships managed by EverVest for a combined cash consideration of $259.0 million.
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 2016, we recognized $0.1 million of income from unconsolidated affiliates, and we received $0.1 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 our long-term incentive plans 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 2016, we awarded an aggregate of 1.0 million phantom units to such employees under the 2016 Plan. The market value of these units on the date of grant was approximately $1.8 million.
Director Independence
During 2016, all members of the board of directors of EV Management, other than Messrs. Walker, Mariani, Michael E. Mercer, Mark A. Houser, and Gary R. Petersen, are independent as defined under the independence standards established by the NASDAQ. 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, 2016. 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, 2016 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)For 2015, represents fees for potential transactions.
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:
3.1
First 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).
3.2
First 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).
3.3
Amended 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).
3.4
First 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).
4.1
Indenture, 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).
10.1
Omnibus 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).
10.2
Contract 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).
10.3
Contract 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).
*10.4
EV 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).
*10.5
Employment 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).
+10.6
Omnibus Agreement Extension, dated February 23, 2017, by and between EnerVest, Ltd. and EV Energy GP, L.P.
*10.7
Form 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).
10.8
Second 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).
10.9
First 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).
10.10
Second 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).
10.11
Third 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).
10.12
Amended 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).
10.13
Fourth 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).
10.14
Fifth 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).
10.16
Sixth 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).
10.17
Seventh Amendment dated as of February 26, 2015 to Second Amended and Restated Credit Agreement (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 2, 2015).
10.18
Guarantee, dated as of April 2, 2015, by and among Williams Partners L.P. and CGAS Properties, L.P. (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 10, 2015).
10.19
Guarantee, dated as of April 2, 2015, by and among CGAS Properties, L.P. and Utica Gas Services, L.L.C. (incorporated by reference from Exhibit 10.2 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on August 10, 2015).
10.20
Membership Interest Purchase Agreement, dated as of April 2, 2015, by and among CGAS Properties, L.P. and Utica Gas Services, L.L.C. (incorporated by reference from Exhibit 10.3 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on August 10, 2015).
10.21
Amendment No. 1 to Membership Interest Purchase Agreement, dated as of May 26, 2015, by and among CGAS Properties, L.P. and Utica Gas Services, L.L.C. (incorporated by reference from Exhibit 10.4 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on August 10, 2015).
10.22
Membership Interest Purchase Agreement, dated as of May 26, 2015, by and among CGAS Properties, L.P. and M3 Ohio Gathering L.L.C. (incorporated by reference from Exhibit 10.5 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on August 10, 2015).
10.23
Eighth Amendment dated October 8, 2015 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 15, 2015).
10.24
Stock Purchase Agreement, dated as of September 2, 2015, among Capital C Energy Operations, LP, CGAS Properties, L.P. and Belden & Blake Corporation (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 November 9, 2015).
10.25
Membership Interest Purchase Agreement, dated as of September 2, 2015, among EnerVest Energy Institutional Fund XI-A, L.P., Enervest Energy Institutional Fund XI-WI, L.P., EV Properties, L.P. and EnerVest Mesa, LLC (incorporated by reference from Exhibit 10.2 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on November 9, 2015).
10.26
Purchase and Sale Agreement, dated as of September 2, 2015, among EnerVest Energy Institutional Fund X-A, L.P., EnerVest Energy Institutional Fund X-WI, L.P. and EV Properties, L.P. (incorporated by reference from Exhibit 10.3 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on November 9, 2015).
10.27
Purchase and Sale Agreement, dated as of September 2, 2015, among EnerVest Energy Institutional Fund XI-A, L.P., EnerVest Energy Institutional Fund XI-WI, L.P. and CGAS Properties, L.P. (incorporated by reference from Exhibit 10.4 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on November 9, 2015).
10.28
Ninth Amendment dated April 1, 2016 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, 2016).
*10.29
2016 Long-Term Incentive Plan (incorporated by reference to Exhibit A of the Partnership’s Definitive Proxy Statement on Form DEF 14A filed with SEC on July 20, 2016).
*10.30
Form of Phantom Units Award Agreement (incorporated by reference to Exhibit 10.1 of the Partnership’s Registration Statement on Form S-8 filed with SEC on October 31, 2016).
+21.1
Subsidiaries of EV Energy Partners, L.P.
+23.1
Consent of Cawley, Gillespie & Associates, Inc.
+23.2
Consent of Wright & Company, Inc.
+23.3
Consent of Deloitte & Touche LLP.
+31.1
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
+31.2
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
+32 .1
Section 1350 Certification of Chief Executive Officer.
+32.2
Section 1350 Certification of Chief Financial Officer.
+99.1
Cawley, Gillespie and Associates, Inc. Reserve Report.
+ 99.2
Wright & Company, Inc. Reserve Report.
+101
Interactive 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 28, 2017 By: /s/ NICHOLAS BOBROWSKI
Nicholas Bobrowski
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 28, 2017
John B. Walker
(principal executive officer)
/s/MICHAEL E. MERCER
President, Chief Executive Officer and Director
February 28, 2017
Michael E. Mercer
/s/NICHOLAS BOBROWSKI
Vice President and Chief Financial Officer
February 28, 2017
Nicholas Bobrowski
(principal financial officer)
/s/RYAN J. FLORY
Controller
February 28, 2017
Ryan J. Flory
(principal accounting officer)
/s/VICTOR BURK
Director
February 28, 2017
Victor Burk
/s/JAMES R. LARSON
Director
February 28, 2017
James R. Larson
/s/GEORGE LINDAHL III
Director
February 28, 2017
George Lindahl, III
/s/GARY R. PETERSEN
Director
February 28, 2017
Gary R. Petersen
/s/MARK A. HOUSER
Director
February 28, 2017
Mark A. Houser
/s/KENNETH MARIANI
Director
February 28, 2017
Kenneth Mariani
EXHIBIT INDEX
3.1
First 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).
3.2
First 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).
3.3
Amended 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).
3.4
First 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).
4.1
Indenture, 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).
10.1
Omnibus 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).
10.2
Contract 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).
10.3
Contract 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).
*10.4
EV 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).
*10.5
Employment 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).
+10.6
Omnibus Agreement Extension, dated February 23, 2017, by and between EnerVest, Ltd. and EV Energy GP, L.P.
*10.7
Form 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).
10.8
Second 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).
10.9
First 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).
10.10
Second 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).
10.11
Third 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).
10.12
Amended 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).
10.13
Fourth 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).
10.14
Fifth 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).
10.16
Sixth 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).
10.17
Seventh Amendment dated as of February 26, 2015 to Second Amended and Restated Credit Agreement (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 2, 2015).
10.18
Guarantee, dated as of April 2, 2015, by and among Williams Partners L.P. and CGAS Properties, L.P. (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 10, 2015).
10.19
Guarantee, dated as of April 2, 2015, by and among CGAS Properties, L.P. and Utica Gas Services, L.L.C. (incorporated by reference from Exhibit 10.2 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on August 10, 2015).
10.20
Membership Interest Purchase Agreement, dated as of April 2, 2015, by and among CGAS Properties, L.P. and Utica Gas Services, L.L.C. (incorporated by reference from Exhibit 10.3 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on August 10, 2015).
10.21
Amendment No. 1 to Membership Interest Purchase Agreement, dated as of May 26, 2015, by and among CGAS Properties, L.P. and Utica Gas Services, L.L.C. (incorporated by reference from Exhibit 10.4 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on August 10, 2015).
10.22
Membership Interest Purchase Agreement, dated as of May 26, 2015, by and among CGAS Properties, L.P. and M3 Ohio Gathering L.L.C. (incorporated by reference from Exhibit 10.5 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on August 10, 2015).
10.23
Eighth Amendment dated October 8, 2015 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 15, 2015).
10.24
Stock Purchase Agreement, dated as of September 2, 2015, among Capital C Energy Operations, LP, CGAS Properties, L.P. and Belden & Blake Corporation (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 November 9, 2015).
10.25
Membership Interest Purchase Agreement, dated as of September 2, 2015, among EnerVest Energy Institutional Fund XI-A, L.P., Enervest Energy Institutional Fund XI-WI, L.P., EV Properties, L.P. and EnerVest Mesa, LLC (incorporated by reference from Exhibit 10.2 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on November 9, 2015).
10.26
Purchase and Sale Agreement, dated as of September 2, 2015, among EnerVest Energy Institutional Fund X-A, L.P., EnerVest Energy Institutional Fund X-WI, L.P. and EV Properties, L.P. (incorporated by reference from Exhibit 10.3 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on November 9, 2015).
10.27
Purchase and Sale Agreement, dated as of September 2, 2015, among EnerVest Energy Institutional Fund XI-A, L.P., EnerVest Energy Institutional Fund XI-WI, L.P. and CGAS Properties, L.P. (incorporated by reference from Exhibit 10.4 to EV Energy Partners, L.P.’s quarterly report on Form 10-Q filed with the SEC on November 9, 2015).
10.28
Ninth Amendment dated April 1, 2016 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, 2016).
*10.29
2016 Long-Term Incentive Plan (incorporated by reference to Exhibit A of the Partnership’s Definitive Proxy Statement on Form DEF 14A filed with SEC on July 20, 2016).
*10.30
Form of Phantom Units Award Agreement (incorporated by reference to Exhibit 10.1 of the Partnership’s Registration Statement on Form S-8 filed with SEC on October 31, 2016).
+21.1
Subsidiaries of EV Energy Partners, L.P.
+23.1
Consent of Cawley, Gillespie & Associates, Inc.
+23.2
Consent of Wright & Company, Inc.
+23.3
Consent of Deloitte & Touche LLP.
+31.1
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
+31.2
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
+32 .1
Section 1350 Certification of Chief Executive Officer.
+32.2
Section 1350 Certification of Chief Financial Officer.
+99.1
Cawley, Gillespie and Associates, Inc. Reserve Report.
+99.2
Wright & Company, Inc. Reserve Report.
+101
Interactive Data Files
*Management contract or compensatory plan or arrangement
+Filed herewith