ITEM 1A.
RISK FACTORS
You should carefully consider each of the following risks and all of the information provided elsewhere in this Report. If any of the risks described below or elsewhere in this Report were actually to occur, our business, financial condition, results of operations, or cash flows could be materially and adversely affected. In that case, we may not be able to pay distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.
Risks Related to Our Business
We may not have sufficient cash flow from operations to pay quarterly distributions on our common units following establishment of cash reserves and payment of fees and expenses, including reimbursement of expenses to our general partner and Encore Operating.
We may not have sufficient available cash each quarter to pay quarterly distributions. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution is reduced by our operating expenses and the amount of any cash reserves that our general partner establishes to provide for future operations, capital expenditures, acquisitions of oil and natural gas properties, debt service requirements, and cash distributions to our unitholders.
The amount of cash we actually generate depends upon numerous factors related to our business that may be beyond our control, including, among other things, the risks described in this section. In addition, the actual amount of cash that we have available for distribution depends on other factors, including:
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our capital expenditures;
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our ability to make borrowings under our revolving credit facility to pay distributions;
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sources of cash used to fund acquisitions;
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debt service requirements and restrictions on distributions contained in our revolving credit facility or future debt agreements;
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fluctuations in our working capital needs;
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general and administrative expenses;
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cash settlements of commodity derivative contracts;
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timing and collectibility of receivables; and
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the amount of cash reserves established by our general partner for the proper conduct of our business.
Our oil and natural gas reserves naturally decline, and we will be unable to sustain distributions at the current level without making accretive acquisitions or substantial capital expenditures that maintain or grow our asset base.
Because our oil and natural gas properties are a depleting asset, our future oil and natural gas reserves, production volumes, cash flow, and ability to make distributions depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. 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 and reduce cash available for distribution.
We need to make substantial capital expenditures to maintain and grow our asset base, which reduce our cash available for distribution. Because the timing and amount of these capital expenditures fluctuate each quarter, we expect to reserve substantial amounts of cash each quarter to finance these expenditures over time. We may use the reserved cash to reduce indebtedness until we make the capital expenditures. Over a longer
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period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions.
If our reserves decrease and we do not reduce our distribution, then a portion of the distribution may be considered a return of part of our unitholders’ investment in us as opposed to a return on investment. Also, if we do not make sufficient growth capital expenditures, we will be unable to expand our business operations and will therefore be unable to raise future distributions.
To fund our capital expenditures, we must use cash generated from our operations, additional borrowings, or the issuance of additional equity or debt securities, or some combination thereof, which would limit our ability to pay distributions at the then-current distribution rate.
The use of cash generated from operations to fund capital expenditures reduces cash available for distribution to our unitholders. Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions, and contingencies and uncertainties that are beyond our control. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, results of operations, financial condition, and ability to pay distributions. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution, thereby increasing the aggregate amount of cash required to maintain the then-current distribution rate, which could limit our ability to pay distributions at the then-current distribution rate.
We may not make cash distributions during periods when we record net income.
The amount of cash we have available for distribution depends primarily on our cash flow, including cash from financial reserves, working capital or other borrowings, and not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.
Oil and natural gas prices are very volatile. A decline in commodity prices could cause a decline in our liquidity and cash flows from operations, which may force us to reduce our distributions or cease paying distributions altogether.
The oil and natural gas markets are very volatile, and we cannot accurately predict future oil and natural gas prices. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of additional factors that are beyond our control, such as:
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overall domestic and global economic conditions;
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weather conditions;
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political and economic conditions in oil and natural gas producing countries, including those in the Middle East, Africa, and South America;
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actions of the Organization of Petroleum Exporting Countries and state-controlled oil companies relating to oil price and production controls;
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the impact of U.S. dollar exchange rates on oil and natural gas prices;
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technological advances affecting energy consumption and energy supply;
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domestic and foreign governmental regulations and taxation;
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the impact of energy conservation efforts;
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the proximity, capacity, cost, and availability of oil and natural gas pipelines and other transportation facilities;
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the availability of refining capacity; and
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the price and availability of alternative fuels.
The worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with substantial losses in worldwide equity markets could lead to an extended worldwide economic recession. A slowdown in economic activity caused by a recession has reduced worldwide demand for energy and resulted in lower oil and natural gas prices. Oil prices declined from record levels in early July 2008 of over $140 per Bbl to below $39 per Bbl in mid-February 2009 and natural gas prices have declined from over $13 per Mcf to below $4.25 per Mcf over the same period. In addition, the forecasted prices for 2009 have also declined. Notwithstanding significant declines in oil and natural gas prices since July 2008, there has not been a corresponding decrease in oilfield service costs as of February 2009. If oilfield service costs remain elevated in relation to prevailing oil and natural gas prices, our results of operations and cash flows could be adversely affected.
Our revenue, profitability, and cash flow depend upon the prices of and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:
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negatively impact the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically;
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reduce the amount of cash flow available for capital expenditures, repayment of indebtedness, and other corporate purposes;
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result in a decrease in the borrowing base under our revolving credit facility or otherwise limit our ability to borrow money or raise additional capital; and
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impair our ability to pay distributions.
If we raise our distribution levels in response to increased cash flow during periods of relatively high commodity prices, we may not be able to sustain those distribution levels during periods of low commodity prices.
An increase in the differential between benchmark prices of oil and natural gas and the wellhead price we receive could significantly reduce our cash available for distribution and adversely affect our financial condition and results of operations.
The prices that we receive for our oil and natural gas production sometimes trade at a discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials. For example, the oil production from our Elk Basin Assets has historically been sold at a higher discount to NYMEX as compared to our Permian Basin Assets due to competition from Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, and corresponding deep pricing discounts by regional refiners. Increases in differentials could significantly reduce our cash available for distribution and adversely affect our financial condition and results of operations.
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Price declines may result in a write-down of our asset carrying values, which could have a material adverse effect on our results of operations and limit our ability to borrow and make distributions.
Declines in oil and natural gas prices may result in our having to make substantial downward revisions to our estimated reserves. If this occurs, or if our estimates of development costs increase, production data factors change, or development 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 and goodwill. If we incur such impairment charges, it could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our revolving credit facility, which in turn may adversely affect our ability to make cash distributions to our unitholders. In addition, any write-downs that result in a reduction in our borrowing base could require prepayments of indebtedness under our revolving credit facility.
Our commodity derivative contract activities could result in financial losses or could reduce our income and cash flows, which may adversely affect our ability to pay distributions to our unitholders. Furthermore, in the future our commodity derivative contract positions may not adequately protect us from changes in commodity prices.
To achieve more predictable cash flow and to reduce our exposure to fluctuations in the price of oil and natural gas, we enter into derivative arrangements for a significant portion of our forecasted oil and natural gas production. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities, as well as to the ability of counterparties under our commodity derivative contracts to satisfy their obligations to us. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual prices we realize in our operations. Changes in oil and natural gas prices could result in losses under our commodity derivative contracts.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the notional amount of our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from the sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our derivative activities are subject to the following risks:
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a counterparty may not perform its obligation under the applicable derivative instrument, which risk may have been exacerbated by the worldwide financial and credit crisis; and
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there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, which may result in payments to our derivative counterparty that are not accompanied by our receipt of higher prices from our production in the field.
In addition, certain commodity derivative contracts that we may enter into may limit our ability to realize additional revenues from increases in the prices for oil and natural gas.
We have oil and natural gas commodity derivative contracts covering a significant portion of our forecasted production for 2009. These contracts are intended to reduce our exposure to fluctuations in the price of oil and natural gas. We have a much smaller commodity derivative contract portfolio covering our forecasted production for 2010, 2011, and 2012, and no commodity derivative contracts covering production beyond 2012. After 2009 and unless we enter into new commodity derivative contracts, our exposure to oil and natural gas price volatility will increase significantly each year as our commodity derivative contracts expire. We may not be able to obtain additional commodity derivative contracts on acceptable terms, if at all. Our failure to mitigate our exposure to commodity price volatility through commodity derivative contracts could have a negative effect on our financial condition and results of operation and significantly reduce our cash flows.
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The counterparties to our derivative contracts may not be able to perform their obligations to us, which could materially affect our cash flows and results of operations.
As of December 31, 2008, we were entitled to future payments of approximately $108.8 million from counterparties under our commodity derivative contracts. The worldwide financial and credit crisis may have adversely affected the ability of these counterparties to fulfill their obligations to us. If one or more of our counterparties is unable or unwilling to make required payments to us under our commodity derivative contracts, it could have a material adverse effect on our financial condition, results of operations, and ability to make distributions.
Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
It is not possible to measure underground accumulations of oil or natural gas in an exact way. In estimating our oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to oil and natural gas prices, production levels, capital expenditures, operating and development costs, the effects of regulation, and availability of funds. If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and our estimates of the future net cash flows from our reserves could change significantly.
Our Standardized Measure is calculated using prices and costs in effect as of the date of estimation, less future development, production, abandonment, and income tax expenses, and discounted at 10 percent per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. The Standardized Measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.
The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates, and the timing of development expenditures.
The timing of both our production and our incurrence of expenses in connection with the development, production, and abandonment of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10 percent 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.
Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.
The cost of developing, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. If commodity prices decline, the cost of developing, completing and operating a well may not decline in proportion to the prices that we receive for our production, resulting in higher operating and capital costs as a percentage of oil and natural gas revenues. For instance, oil and natural gas prices declined from record levels in early July 2008 of over $140 per Bbl and $13 per Mcf, respectively, to below $39 per Bbl and below $4.25 per Mcf, respectively, in mid-February 2009. Notwithstanding significant
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declines in oil and natural gas prices since July 2008, there has not been a corresponding decrease in oilfield service costs as of February 2009. If oilfield service costs remain elevated in relation to prevailing oil and natural gas prices, our results of operations and cash flows could be adversely affected. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce as much oil and natural gas as we had estimated. Furthermore, our development and production operations may be curtailed, delayed, or canceled as a result of other factors, including:
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higher costs, shortages of, or delivery delays of rigs, equipment, labor, or other services;
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unexpected operational events and/or conditions;
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reductions in oil and natural gas prices;
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increases in severance taxes;
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limitations in the market for oil and natural gas;
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adverse weather conditions and natural disasters;
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facility or equipment malfunctions, and equipment failures or accidents;
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title problems;
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pipe or cement failures and casing collapses;
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compliance with environmental and other governmental requirements;
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environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, and discharges of toxic gases;
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lost or damaged oilfield development and service tools;
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unusual or unexpected geological formations, and pressure or irregularities in formations;
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loss of drilling fluid circulation;
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fires, blowouts, surface craterings, and explosions;
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uncontrollable flows of oil, natural gas, or well fluids; and
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loss of leases due to incorrect payment of royalties.
If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.
Secondary and tertiary recovery techniques may not be successful, which could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.
A significant portion of our production and our reserves rely on secondary and tertiary recovery techniques. If production response is less than forecasted for a particular project, then the project may be uneconomic or generate less cash flow and reserves than we had estimated prior to investing capital. Risks associated with secondary and tertiary recovery techniques include, but are not limited to, the following:
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lower than expected production;
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longer response times;
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higher operating and capital costs;
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shortages of equipment; and
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lack of technical expertise.
If any of these risks occur, it could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.
Shortages of rigs, equipment, and crews could delay our operations and reduce our cash available for distribution.
Higher oil and natural gas prices generally increase the demand for rigs, equipment, and crews and can lead to shortages of, and increasing costs for, development equipment, services, and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations that we have planned. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues.
If we do not make acquisitions, our future growth, and ability to pay or increase distributions could be limited.
Our ability to grow and to increase distributions to unitholders depends in part on our ability to make acquisitions that result in an increase in pro forma available cash per unit. We may be unable to make such acquisitions because we are:
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unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
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unable to obtain financing for these acquisitions on economically acceptable terms; or
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outbid by competitors.
Competition for acquisitions is intense and may increase the cost of, or cause us to refrain from, completing acquisitions. If we are unable to acquire properties containing proved reserves, our total proved reserves could decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions. Future acquisitions could result in our incurring additional debt, contingent liabilities, and expenses, all of which could have a material adverse effect on our financial condition and results of operations. Furthermore, our financial position and results of operations may fluctuate significantly from period to period based on whether significant acquisitions are completed in particular periods.
Any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to make distributions to unitholders.
Even if we complete acquisitions that we believe will increase pro forma available cash per unit, these acquisitions may nevertheless result in a decrease in pro forma available cash per unit. Any acquisition involves potential risks, including, among other things:
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the validity of our assumptions about reserves, future production, revenues, capital expenditures, and operating costs, including synergies;
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an inability to integrate the businesses we acquire successfully;
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a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
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a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
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the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which our indemnity is inadequate;
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the diversion of management’s attention from other business concerns;
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natural disasters;
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the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation, or restructuring charges;
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unforeseen difficulties encountered in operating in new geographic areas; and
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customer or key employee losses at the acquired businesses.
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses, and seismic and other information, the results of which are often inconclusive and subject to various interpretations.
Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition given time constraints imposed by sellers. 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 fully assess their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.
Due to our lack of asset and geographic diversification, adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.
We only own oil and natural gas properties and related assets. All of our assets are located in Wyoming, Montana, North Dakota, Arkansas, and Texas. Due to our lack of diversification in asset type and location, an adverse development in the oil and natural gas business in these geographic areas would have a significantly greater impact on our results of operations and cash available for distribution to our unitholders than if we maintained more diverse assets and locations.
We depend on certain customers for a substantial portion of our sales. If these customers reduce the volumes of oil and natural gas they purchase from us, our revenues and cash available for distribution will decline to the extent we are not able to find new customers for our production.
For 2008, our largest purchasers were Marathon Oil Corporation, ConocoPhillips, and Chevron Corporation, which accounted for 24 percent, 23 percent, and 10 percent, respectively, of our total sales of production. If any of these customers were to reduce the production purchased from us, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production.
Competition in the oil and natural gas industry is intense, and we may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.
The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas, and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major and large independent oil and natural gas companies, and possess financial and technical resources substantially greater than us. Those companies may be able to develop and acquire more prospects and productive properties than our resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Some of our competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national, or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for, and
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purchase a greater number of properties than our resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local, and other laws and regulations. Our inability to compete effectively could have a material adverse impact on our business activities, financial condition, and results of operations.
We may incur substantial additional debt to enable us to pay our quarterly distributions, which may negatively affect our ability to execute our business plan and pay future distributions.
We may be unable to pay a distribution at the current distribution rate or a future distribution rate without borrowing under our revolving credit facility. When we borrow to pay distributions, we are distributing more cash than we are generating from our operations. This means that we are using a portion of our borrowing capacity under our revolving credit facility to pay distributions rather than to maintain or expand our operations. If we use borrowings under our revolving credit facility to pay distributions for an extended period of time rather than toward funding capital expenditures and other matters relating to our operations, we may be unable to support or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on our business, financial condition, and results of operations. If we borrow to pay distributions during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution in order to avoid excessive leverage.
Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.
As of February 18, 2009, we had $201 million of outstanding borrowings and $39 million of borrowing capacity under our revolving credit facility. We have the ability to incur additional debt under our revolving credit facility, subject to borrowing base limitations. Our future indebtedness could have important consequences to us, including:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions, or other purposes may not be available on favorable terms, if at all;
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covenants contained in future debt arrangements may require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
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we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities, and distributions to unitholders; and
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our debt level will make us more vulnerable to competitive pressures, or a downturn in our business or the economy in general, than our competitors with less debt.
Our ability to service our indebtedness depends upon, among other things, our future financial and operating performance, which is affected by prevailing economic conditions and financial, business, regulatory, and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.
In addition, we are not currently permitted to offset the value of our commodity derivative contracts with a counterparty against amounts that may be owing to such counterparty under our revolving credit facilities.
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We are unable to predict the impact of the recent downturn in the credit markets and the resulting costs or constraints in obtaining financing on our business and financial results.
U.S. and global credit and equity markets have recently undergone significant disruption, making it difficult for many businesses to obtain financing on acceptable terms. In addition, equity markets are continuing to experience wide fluctuations in value. If these conditions continue or worsen, our cost of borrowing may increase, and it may be more difficult to obtain financing in the future. In addition, an increasing number of financial institutions have reported significant deterioration in their financial condition. If any of the financial institutions are unable to perform their obligations under our revolving credit agreements and other contracts, and we are unable to find suitable replacements on acceptable terms, our results of operations, liquidity and cash flows could be adversely affected. We also face challenges relating to the impact of the disruption in the global financial markets on other parties with which we do business, such as customers and suppliers. The inability of these parties to obtain financing on acceptable terms could impair their ability to perform under their agreements with us and lead to various negative effects on us, including business disruption, decreased revenues, and increases in bad debt write-offs. A sustained decline in the financial stability of these parties could have an adverse impact on our business, results of operations, and liquidity.
Our revolving credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.
The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand, or pursue our business activities or to pay distributions.
Our ability to comply with the restrictions and covenants in our revolving credit facility in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, or financial ratios in our revolving credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets.
Our revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. Outstanding borrowings in excess of the borrowing base will be required to be repaid immediately, or we will be required to pledge other oil and natural gas properties as additional collateral.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
There are a variety of operating risks inherent in our wells, gathering systems, pipelines, and other facilities, such as leaks, explosions, mechanical problems, and natural disasters, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations, and substantial revenue losses. The location of our wells, gathering systems, pipelines, and other facilities near populated areas, including residential areas, commercial business centers, and industrial sites, could significantly increase the damages resulting from these risks.
We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not
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fully insurable. 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. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets due to weather and adverse economic conditions have made it more difficult for us to obtain certain types of coverage. We may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and our insurance may contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations, and ability to make distributions to our unitholders.
Our business depends in part on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production and could harm our business.
The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of pipelines, oil and natural gas gathering systems, and processing facilities. 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, or lack of available 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. Any significant curtailment in gathering system or pipeline capacity could reduce our ability to market our oil and natural gas production and harm our business.
We have limited control over the activities on properties we do not operate.
Other companies operated approximately 24 percent of our properties (measured by total reserves) and approximately 65 percent of our wells as of December 31, 2008. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in development or acquisition activities and lead to unexpected future costs.
We are subject to complex federal, state, local, and other laws and regulations that could adversely affect the cost, manner, or feasibility of conducting our operations.
Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate, and abandon oil and natural gas wells and related pipeline and processing facilities. 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. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.
Our business is subject to federal, state, and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition, results of operations, and ability to make distributions to unitholders. Please read “Items 1 and 2. Business and Properties - Environmental Matters and Regulation” and “Items 1 and 2. Business and Properties - Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.
ENCORE ENERGY PARTNERS LP
Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.
We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas production activities. In addition, we often indemnify sellers of oil and natural gas properties for environmental liabilities they or their predecessors may have created. These costs and liabilities could arise under a wide range of federal, state, and local environmental and safety laws and regulations, which have become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, imposition of cleanup and site restoration costs, liens and, to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.
Strict, joint, and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations, or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our profitability and our ability to make distributions to unitholders could be adversely affected.
Risks Inherent in an Investment in Us
Our general partner and its affiliates own a controlling interest in us and may have conflicts of interest with us and limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of unitholders.
As of February 18, 2009, EAC and its affiliates owned approximately 63 percent of our outstanding common units and controlled our general partner, which controls us. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to EAC. Furthermore, certain directors and officers of our general partner are directors and officers of affiliates of our general partner, including EAC. Conflicts of interest may arise between EAC and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These potential conflicts include, among others, the following situations:
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neither our partnership agreement nor any other agreement requires EAC or its affiliates (other than our general partner) to pursue a business strategy that favors us. EAC’s directors and officers have a fiduciary duty to make these decisions in the best interests of its shareholders, which may be contrary to our interests;
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our general partner is allowed to take into account the interests of parties other than us, such as EAC and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
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EAC is not limited in its ability to compete with us and is under no obligation to offer to sell assets to us;
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under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or its affiliates (including EAC) and no such person who acquires knowledge of a potential transaction, agreement, arrangement, or other matter that may be an opportunity for our partnership will have any duty to communicate or offer such opportunity to us;
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the officers of our general partner who provide services to us will devote time to affiliates of our general partner and may be compensated for services rendered to such affiliates;
ENCORE ENERGY PARTNERS LP
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our general partner has limited its liability, reduced its fiduciary duties, and restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;
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our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;
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Encore Operating performs administrative services for us pursuant to an administrative services agreement under which it receives an administrative fee of $1.88 per BOE of our production for such services and reimbursement of actual third-party expenses incurred on our behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on our behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator of a well;
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our general partner may cause us to borrow funds in order to permit the payment of cash distributions;
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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;
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our general partner has limited its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;
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our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80 percent of our common units;
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our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and
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our general partner decides whether to retain separate counsel, accountants, or others to perform services for us.
EAC is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses.
Our partnership agreement does not prohibit EAC from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, EAC may acquire, develop, or dispose of additional oil and natural gas properties or other assets, without any obligation to offer us the opportunity to purchase or develop any of those assets. EAC is an established participant in the oil and natural gas industry and has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with EAC with respect to commercial activities as well as for acquisition candidates. As a result, competition from EAC could adversely impact our results of operations and cash available for distribution.
EAC, as the owner of our general partner, has the power to appoint and remove our directors and management.
Since an affiliate of EAC owns our general partner, it has the ability to elect all the members of the board of directors of our general partner. Our general partner has control over all decisions related to our operations. Since EAC and its affiliates also owned approximately 63 percent of our outstanding common units as of February 18, 2009, the public unitholders do not have the ability to influence any operating decisions and are not able to prevent us from entering into most transactions. Furthermore, the goals and objectives of EAC and our general partner relating to us may not be consistent with those of a majority of the public unitholders.
ENCORE ENERGY PARTNERS LP
We do not have any employees and rely solely on officers of our general partner and employees of EAC. Failure of such officers and employees to devote sufficient attention to the management and operation of our business may adversely affect our financial results and our ability to make distributions to our unitholders.
None of the officers of our general partner are employees of our general partner, and we do not have any employees. Affiliates of our general partner and Encore Operating conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to EAC. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner, EAC, and their affiliates. If the officers of our general partner and the employees of EAC and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.
Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:
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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates, or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights, and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;
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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;
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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith 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. 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;
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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 nonappealable judgment entered by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner or its conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Our unitholders are bound by the provisions in our partnership agreement, including the provisions discussed above.
ENCORE ENERGY PARTNERS LP
Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.
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 do not elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by EAC. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they have little 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 unitholders are dissatisfied, they cannot remove our general partner without its consent.
The unitholders are unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least two-thirds of all outstanding units voting together as a single class is required to remove the general partner. As of February 18, 2009, EAC and its affiliates owned approximately 63 percent of our outstanding common units.
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 EAC, the owner of our general partner, from transferring all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions made by the board of directors and officers.
We may issue additional units, including units that are senior to the common units, without unitholder approval.
Our partnership agreement does not limit the number of additional partner interests that we may issue. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation, and voting. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
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our unitholders’ proportionate ownership interest in us will decrease;
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the amount of cash available for distribution on each unit may decrease;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit may be diminished; and
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the market price of our common units may decline.
Our partnership agreement restricts the voting rights of unitholders owning 20 percent or more of our common units, other than our general partner and its affiliates, which may limit the ability of significant unitholders to influence the manner or direction of management.
Our partnership agreement restricts unitholders’ voting rights by providing that any common units held by a person, entity, or group that owns 20 percent or more of any class of common units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such common 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 unitholders’ ability to influence the manner or direction of management.
ENCORE ENERGY PARTNERS LP
Affiliates of our general partner may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.
As of February 18, 2009, EAC and its affiliates held 20,924,055 of our common units. The sale of these units in the public markets could have an adverse impact on the price of the common units.
Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.
As of February 18, 2009, EAC and its affiliates owned approximately 63 percent of our outstanding common units. If at any time our general partner and its affiliates own more than 80 percent of the 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, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders also may incur a tax liability upon a sale of their common units.
Unitholder 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. A unitholder could be liable for our obligations as if it was a general partner if:
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a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
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a unitholder’s rights to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement, or to take other actions under our partnership agreement constitute “control” of our business.
Unitholders may have liability to repay distributions.
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, or Delaware Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an 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. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.
Unitholders who are not Eligible Holders will not be entitled to receive distributions on or allocations of income or loss on their common units and their common units will be subject to redemption.
In order to comply with U.S. laws with respect to the ownership of interests in oil and natural gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our common
ENCORE ENERGY PARTNERS LP
units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands. As of the date hereof, Eligible Holder means:
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a citizen of the United States;
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a corporation organized under the laws of the United States or of any state thereof;
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a public body, including a municipality; or
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an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof.
For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder will not receive distributions or allocations of income and loss on their common units and they run the risk of having their common units redeemed by us at the lower of their purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
An increase in interest rates may cause the market price of our common units to decline.
Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt or other securities may cause a corresponding decline in demand for riskier investments in general, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by individual states. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of additional entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is a maximum of 35 percent, and would likely pay state income tax at varying rates. Distributions to unitholders generally would be taxed again as corporate distributions, and no income, gains, losses, or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our 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 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, we are subject to an entity-
ENCORE ENERGY PARTNERS LP
level tax, the Texas margin tax, at an effective rate of up to 0.7 percent 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 unitholders.
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 administrative, legislative, or judicial interpretation at any time. For example, members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Although proposed legislation would not appear to affect our tax treatment as a partnership, 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.
We prorate our items of income, gain, loss, and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss, and deduction among our unitholders.
We prorate our items of income, gain, loss, and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
If the IRS contests any of the federal income tax positions we take, the market for our common units may be adversely affected, and the costs of any contest will reduce our cash available for distribution to 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. The IRS may adopt positions that differ from the conclusions of our counsel or from the positions we take. 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 some or all of our counsel’s conclusions or the 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, the costs of 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.
Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our unitholders are treated as partners to whom we allocate taxable income which could be different in amount than the cash we distribute, unitholders are required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.
ENCORE ENERGY PARTNERS LP
Tax gain or loss on the disposition of our common units could be more or less than expected.
If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to unitholders in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if unitholders sell their common units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning our 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) and other retirement plans, and foreign persons raises issues unique to them. For example, virtually all of our income allocated to organizations 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 foreign persons will be reduced by withholding taxes at the highest applicable effective tax rate, and foreign persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss, or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our tax counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We will treat each purchaser of common units as having the same tax benefits without regard to the 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, we will adopt depletion, depreciation, and amortization positions that may not conform with all aspects of existing Treasury regulations. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from unitholders’ sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to unitholder tax returns.
Unitholders likely will be subject to state and local taxes and return filing requirements as a result of investing in our common units.
In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes, and estate, inheritance, or intangible taxes that are imposed
ENCORE ENERGY PARTNERS LP
by the various jurisdictions in which we do business or own property. Unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We own property and conduct business in Montana, North Dakota, Texas, and Wyoming. Of those states, Texas and Wyoming do not impose a state income tax on individuals. We may own property or conduct business in other states or foreign countries in the future. It is the unitholders’ responsibility to file all federal, state, and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.
The sale or exchange of 50 percent or more of our capital and profits interests within a twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated for tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and unitholders receiving two schedule K-1s) for one fiscal year and require a unitholder who uses a different taxable year than us to include more than twelve moths of our taxable income or loss in his taxable income for the year of our termination.
We may adopt certain valuation methodologies that may result in a shift of income, gain, loss, and deduction between unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss, and deduction between unitholders, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss, and deduction between unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
There were no unresolved SEC staff comments as of December 31, 2008.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
From time to time, we are a party to ongoing legal proceedings in the ordinary course of business. We are not a party to any legal or governmental claims that management believes will have a material adverse effect on our results of operations or financial position.
ITEM 4.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF UNITHOLDERS
There were no matters submitted to a vote of unitholders during the fourth quarter of 2008.
ENCORE ENERGY PARTNERS LP
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF COMMON UNITS
Our common units are listed on the NYSE under the symbol “ENP.” The following table sets forth high and low sales prices of our common units and cash distributions to our common unitholders for the periods indicated:
(a)
Based on an initial quarterly distribution of $0.35 per unit, prorated for the period from and including September 17, 2007 (the closing date of our initial public offering) through September 30, 2007.
On February 18, 2009, the closing sales price of our common units as reported by the NYSE was $13.49 per unit, and we had approximately 12 unitholders of record. This number does not include owners for whom common units may be held in “street” name.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
We did not purchase any of our common units during the fourth quarter of 2008.
Cash Distributions to Unitholders
Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date. The term “available cash,” for any quarter, means all cash and cash equivalents on hand at the end of that quarter, less the amount of cash reserves established by our general partner to:
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provide for the proper conduct of our business;
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comply with applicable law, any of our debt instruments, or other agreements; or
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provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.
Our partnership agreement gives our general partner wide latitude to establish reserves for future capital expenditures and operational needs prior to determining the amount of cash available for distribution. We distribute available cash to our unitholders and our general partner in accordance with their ownership percentages.
In May 2008, the board of directors of our general partner approved a new distribution methodology, which returns additional cash flow to our unitholders during high commodity price environments. As a general guideline, we plan to distribute to unitholders 50 percent of the excess distributable cash flow above: (1) maintenance capital requirements; (2) an implied minimum quarterly distribution of $0.4325 per unit, or $1.73 per unit annually; and (3) a minimum coverage ratio of 1.10. We may decide to make a fixed quarterly distribution over a specified period pursuant to the preceding formula in order to reduce some of the variability in quarterly distributions over the specified period. Accordingly, we may make a distribution during a quarter
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even if we have not generated sufficient cash flow to cover such distribution by borrowing under our revolving credit facility, and we may reserve some of our cash during a quarter for distributions in future quarters even if the preceding formula would result in the distribution of a higher amount for such quarter. Our board of directors also may change our distribution philosophy based on prevailing business conditions. There can be no assurance that we will be able to distribute $0.4325 on a quarterly basis or achieve a minimum coverage ratio of 1.10.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
The following table shows selected historical financial data for the periods and as of the periods indicated. The selected historical financial data as of December 31, 2008, 2007, and 2006 and for the years ended December 31, 2008, 2007, 2006, and 2005 is derived from our audited financial statements. The selected historical financial data as of December 31, 2005 and 2004 and for the year ended December 31 2004 is derived from unaudited financial statements.
The following selected consolidated financial and operating data should be read in conjunction with “Item 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our consolidated financial position and results of operations should be read in conjunction with our consolidated financial statements and notes, and supplementary data thereto included in “Item 8. Financial Statements and Supplementary Data.” The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. Actual results could differ materially from those discussed in these forward-looking statements. We do not undertake to update, revise, or correct any of the forward-looking information unless required to do so under federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under the headings: “Information Concerning Forward-Looking Statements” and “Item 1A. Risk Factors.”
Introduction
In this management’s discussion and analysis of financial condition and results of operations, the following are discussed and analyzed:
•
Overview of Business
•
2008 Events
•
Recent Developments
•
2009 Outlook
•
Results of Operations
-
Comparison of 2008 to 2007
-
Comparison of 2007 to 2006
•
Capital Commitments, Capital Resources, and Liquidity
•
Changes in Prices
•
Critical Accounting Policies and Estimates
•
New Accounting Pronouncements
•
Information Concerning Forward-Looking Statements
Overview of Business
We are a Delaware limited partnership formed in February 2007 by EAC to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Our primary business objective is to make quarterly cash distributions to our unitholders at our current distribution rate and, over time, increase our quarterly cash distributions.
In September 2007, we completed our initial public offering (the “IPO”) of 9,000,000 common units at a price to the public of $21.00 per unit. In October 2007, the underwriters exercised their option to purchase an additional 1,148,400 common units. Net proceeds from the issuance of common units, including the underwriters’ over-allotment option, were approximately $193.5 million, after deducting the underwriters’ discount and a structuring fee of approximately $14.9 million, in the aggregate, and offering expenses of approximately $4.7 million. The net proceeds were used to repay in full $126.4 million of outstanding indebtedness under a subordinated credit agreement with EAP Operating, LLC, a wholly owned subsidiary of EAC, and reduce outstanding indebtedness under our revolving credit facility.
ENCORE ENERGY PARTNERS LP
Upon the closing of our IPO, Encore Operating contributed to us certain properties in the Permian Basin located in Crockett County, Texas (the “Permian Basin Assets”). The Permian Basin Assets are considered our predecessor, and therefore, our historical results of operations include the results of operations of the Permian Basin Assets for all periods presented. The results of operations of the Elk Basin Assets have been included since the acquisition date in March 2007. We acquired the Permian and Williston Basin Assets from Encore Operating in February 2008, and as a result of the transaction between entities under common control, our historical financial information was recast to include the acquired properties for all periods presented. Accordingly, our consolidated financial statements reflect our historical results combined with those of the Permian Basin Assets and the Permian and Williston Basin Assets throughout the periods presented.
At December 31, 2008, our oil and natural gas properties had estimated total proved reserves of 16.6 MMBbls of oil and 56.5 Bcf of natural gas, based on December 31, 2008 spot market prices of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas. On a BOE basis, our proved reserves were 26.1 MMBOE at December 31, 2008, of which approximately 64 percent was oil and approximately 89 percent was proved developed. Based on 2008 production, our ratio of reserves to production was approximately 11.3 years for total proved reserves and 10.0 years for proved developed reserves as of December 31, 2008.
Our financial results and ability to generate cash depend upon many factors, particularly the price of oil and natural gas. Average NYMEX oil prices strengthened in the first half of 2008 to record levels, but have since experienced a significant deterioration. In addition, our oil wellhead differentials to NYMEX improved in 2008 as we realized 89 percent of the average NYMEX oil price, as compared to 82 percent in 2007. Average NYMEX natural gas prices strengthened in the first half of 2008 to their highest levels since 2005, but have since experienced a significant deterioration. However, our natural gas wellhead differentials to NYMEX deteriorated slightly in 2008 as we realized 97 percent of the average NYMEX natural gas price in 2008, as compared to 101 percent in 2007. Commodity prices are influenced by many factors that are outside our control. We cannot accurately predict future commodity prices. For this reason, we attempt to mitigate the effect of commodity price risk by entering into commodity derivative contracts for a portion of our forecasted future production. For a discussion of factors that influence commodity prices and risks associated with our commodity derivative contracts, please read “Item 1A. Risk Factors.”
Events
In February 2008, we acquired certain oil and natural gas producing properties and related assets in the Permian and Williston Basins from Encore Operating in exchange for approximately $125.3 million in cash and 6,884,776 common units representing limited partner interests in us. In determining the total purchase price, the common units were valued at $125 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s historical carrying value of the properties. Because these assets were acquired from an affiliate, the acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities were recorded at Encore Operating’s historical cost and our historical financial information was recast to include the acquired properties for all periods presented.
In May 2008, we acquired an existing net profits interest in certain of our properties in the Permian Basin of West Texas in exchange for 283,700 common units representing limited partner interests in us, which were valued at approximately $5.8 million at the time of the acquisition.
Recent Developments
In January 2009, we acquired certain oil and natural gas producing properties and related assets in the Arkoma Basin and royalty interest properties in Oklahoma as well as 10,300 unleased mineral acres from EAC. The purchase price was $49 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3 million). Our
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historical results of operations, reserve data, and other operating and financial information do not include any information regarding these properties.
Outlook
For 2009, the board of directors of our general partner has approved a $7.4 million capital budget for oil and natural gas related activities, all of which is for development and exploitation. We expect to fund our 2009 capital expenditures with cash flow from operations.
The prices we receive for oil and natural gas production are largely based on current market prices, which are beyond our control. For comparability and accountability, we take a constant approach to budgeting commodity prices. We presently analyze our inventory of capital projects based on management’s outlook of future commodity prices. If NYMEX prices continue to trend downward, we may further reevaluate our capital projects. Since the end of 2008, oil NYMEX prices have declined from $44.60 per Bbl to below $39.00 per Bbl in mid-February 2009 and natural gas NYMEX prices have declined from $5.62 per Mcf to below $4.25 per Mcf over the same period. The price risk on a substantial portion of our forecasted oil and natural gas production for 2009 is mitigated using commodity derivative contracts. Please read “Item 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This information provides indicators of how we view and manage our ongoing market risk exposures. We do not enter into market risk sensitive instruments for speculative trading purposes.
Derivative policy. Due to the volatility of crude oil and natural gas prices, we enter into various derivative instruments to manage our exposure to changes in the market price of crude oil and natural gas. We use options (including floors and collars) and fixed price swaps to mitigate the impact of downward swings in prices on our cash available for distribution. All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement. While this strategy may result in us having lower net cash inflows in times of higher oil and natural gas prices than we would otherwise have, had we not utilized these instruments, management believes that the resulting reduced volatility of cash flow is beneficial.
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Counterparties. At December 31, 2008, we had committed greater than 10 percent of either our outstanding oil or natural gas commodity derivative contracts to the following counterparties:
In order to mitigate the credit risk of financial instruments, we enter into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating separately each derivative financial transaction between our counterparty and us, the master netting agreement enables our counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement benefits us in three ways: (1) the netting of the value of all trades reduces likelihood of our counterparties requiring daily collateral posting by us, (2) default by a counterparty under one financial trade can trigger rights for us to terminate all financial trades with such counterparty, and (3) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.
Commodity price sensitivity. We manage commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price. From time to time, we sell floors with a strike price below the strike price of the purchased floors in order to partially finance the premiums paid on the purchased floors. Together the two floors, known as a floor spread or put spread, have a lower premium cost than a traditional floor contract but provide price protection only down to the strike price of the short floor.
As of December 31, 2008, the fair market values of our oil and natural gas commodity derivative contracts were net assets of $100.6 million and $12.8 million, respectively. Based on our open commodity derivative positions at December 31, 2008, a 10 percent increase in the respective NYMEX prices for oil and natural gas would decrease our net derivative fair value asset by approximately $19.8 million, while a 10 percent decrease in the respective NYMEX prices for oil and natural gas would increase our net derivative fair value asset by approximately $25.6 million.
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The following tables summarize our open commodity derivative contracts as of December 31, 2008:
Oil Derivative Contracts
(a)
In addition, we have a floor contract for 1,000 Bbls/D at $63.00 per Bbl and a short floor contract for 1,000 Bbls/D at $65.00 per Bbl.
Natural Gas Derivative Contracts
Interest rate sensitivity. At December 31, 2008, we had total long-term debt of $150 million under our revolving credit facility, which is subject to floating market rates of interest that are linked to LIBOR. At this level of floating rate debt, if LIBOR increased 10 percent, we would incur an additional $0.4 million of interest expense per year, and if LIBOR decreased 10 percent, we would incur $0.4 million less.
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We manage interest rate risk with interest rate swaps whereby we swap floating rate debt under the OLLC Credit Agreement with a weighted average fixed rate. As of December 31, 2008, the fair market value of our interest rate swaps was a net liability of approximately $4.6 million. If LIBOR increased 10 percent, we estimate the liability would decrease to approximately $4.1 million, and if LIBOR decreased 10 percent, we estimate the liability would increase to approximately $5.0 million.
The following table summarizes our open interest rate swaps as of December 31, 2008:
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ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Encore Energy Partners GP LLC
and Unitholders of Encore Energy Partners LP:
We have audited the accompanying consolidated balance sheets of Encore Energy Partners LP (the “Partnership”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, partners’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Encore Energy Partners LP at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2007, the Partnership adopted Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109.”
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2009 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Fort Worth, Texas
February 24, 2009
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CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY AND COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1.
Formation of the Partnership and Description of Business
Encore Energy Partners LP (together with its subsidiaries, “ENP”), a Delaware limited partnership, was formed in February 2007 by Encore Acquisition Company (together with its subsidiaries, “EAC”), a publicly traded Delaware corporation, to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Also in February 2007, Encore Energy Partners GP LLC (the “General Partner”), a Delaware limited liability company and indirect wholly owned subsidiary of EAC, was formed to serve as the general partner of ENP, and Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and direct wholly owned subsidiary of ENP, was formed to own and operate ENP’s properties. ENP’s properties - and oil and natural gas reserves - are located in three core areas:
•
the Big Horn Basin in Wyoming and Montana, primarily in the Elk Basin field (the “Elk Basin Assets”);
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the Permian Basin in West Texas; and
•
the Williston Basin in North Dakota.
Initial Public Offering and Concurrent Transactions
In September 2007, ENP completed its initial public offering (“IPO”) of 9,000,000 common units at a price to the public of $21.00 per unit. In October 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units. The net proceeds of approximately $193.5 million, after deducting the underwriters’ discount and a structuring fee of approximately $14.9 million, in the aggregate, and offering expenses of approximately $4.7 million, were used to repay in full $126.4 million of outstanding indebtedness under a subordinated credit agreement with EAP Operating, LLC, and reduce outstanding borrowings under ENP’s revolving credit facility. Please read “Note 7. Long-Term Debt” for additional discussion of ENP’s long-term debt.
At the closing of the IPO, the following transactions were completed:
(a) ENP entered into a contribution, conveyance and assumption agreement (the “Contribution Agreement”) with the General Partner, OLLC, EAC, Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned subsidiary of EAC, and Encore Partners LP Holdings LLC, a Delaware limited liability company and direct wholly owned subsidiary of EAC. The following transactions, among others, occurred pursuant to the Contribution Agreement:
•
Encore Operating transferred certain oil and natural gas properties and related assets in the Permian Basin of West Texas (the “Permian Basin Assets”) to ENP in exchange for 4,043,478 common units; and
•
EAC agreed to indemnify ENP for certain environmental liabilities, tax liabilities, and title defects, as well as defects relating to retained assets and liabilities, occurring or existing before the closing.
These transfers and distributions were made in a series of steps outlined in the Contribution Agreement. In connection with the issuance of the common units by ENP in exchange for the Permian Basin Assets, the IPO, and the exercise of the underwriters’ option to purchase additional common units, the General Partner exchanged a certain number of common units for general partner units to enable it to maintain its then two percent general partner interest. The General Partner received the common units through capital contributions from EAC and its subsidiaries of common units they owned.
(b) ENP entered into an administrative services agreement (the “Administrative Services Agreement”) with the General Partner, OLLC, Encore Operating, and EAC pursuant to which Encore Operating
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
performs administrative services for ENP. Please read “Note 13. Related Party Transactions” for additional discussion regarding the Administrative Services Agreement.
(c) The Encore Energy Partners GP LLC Long-Term Incentive Plan (the “LTIP”) was approved. Please read “Note 9. Unit-Based Compensation Plans” for additional discussion regarding the LTIP.
Note 2.
Summary of Significant Accounting Policies
Principles of Consolidation
ENP’s consolidated financial statements include the accounts of its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.
As discussed in “Note 1. Formation of the Partnership and Description of Business,” upon completion of ENP’s IPO, EAC contributed the Permian Basin Assets to ENP. The Permian Basin Assets are considered the predecessor to ENP (the “Predecessor”), and therefore, the historical results of operations of ENP include the results of operations of the Permian Basin Assets for all periods presented. The results of operations of the Elk Basin Assets have been included with those of ENP from the date of acquisition in March 2007.
In February 2008, ENP completed the acquisition of certain oil and natural gas properties and related assets in the Permian Basin of West Texas and in the Williston Basin of North Dakota (the “Permian and Williston Basin Assets”) from Encore Operating. Please read “Note 3. Acquisitions” for additional discussion. Because the Permian and Williston Basin Assets were acquired from an affiliate, the acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities were recorded at Encore Operating’s historical cost and ENP’s historical financial information was recast to include the acquired properties for all periods presented. Accordingly, the consolidated financial statements and notes thereto reflect the combined historical results of ENP, the Permian Basin Assets, and the Permian and Williston Basin Assets throughout the periods presented. The results of operations of the Permian and Williston Basin Assets related to pre-partnership operations were allocated to the EAC affiliates based on their respective ownership percentages in ENP’s general and limited partner units. The effect of recasting ENP’s consolidated financial statements to account for this common control transaction reduced ENP’s net loss by approximately $18.3 million for 2007 and increased ENP’s net income by approximately $14.8 million in 2006.
ENP, the Permian Basin Assets, and the Permian and Williston Basin Assets were wholly owned by EAC prior to the closing of the IPO, with the exception of management incentive units owned by certain executive officers of the General Partner.
Use of Estimates
Preparing financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make certain estimations and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities in the consolidated financial statements and the reported amounts of revenues and expenses. Actual results could differ materially from those estimates.
Estimates made in preparing these consolidated financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating depletion, depreciation, and amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; operating costs accrued; volumes and prices for revenues accrued; estimates of the fair value of unit-based compensation awards; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Changes in the assumptions used could have a significant impact on reported results in future periods.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Cash and Cash Equivalents
Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less. On a bank-by-bank basis and considering legal right of offset, cash accounts that are overdrawn are reclassified to current liabilities and any change in cash overdrafts is shown as “Change in cash overdrafts” in the “Financing activities” section of ENP’s Consolidated Statements of Cash Flows.
Prior to the formation of ENP, EAC provided cash as needed to support the operations of the predecessor properties and collected cash from sales of production. Net cash received or paid during each year by EAC for periods prior to the properties’ ownership by ENP is reflected as net contributions from owner or net distributions to owner on the accompanying Consolidated Statements of Partners’ Equity and Comprehensive Income and Consolidated Statements of Cash Flows.
Supplemental Disclosures of Cash Flow Information
The following table sets forth supplemental disclosures of cash flow information for the periods indicated:
(a)
Please read “Note 3. Acquisitions” for additional discussion of these acquisitions.
Accounts Receivable
Trade accounts receivable, which are primarily from oil and natural gas sales, are recorded at the invoiced amount and do not bear interest. ENP routinely reviews outstanding accounts receivable balances and assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2008 and 2007, ENP had no allowance for doubtful accounts.
Properties and Equipment
Oil and Natural Gas Properties. ENP uses the successful efforts method of accounting for its oil and natural gas properties under Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (“SFAS 19”). Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in ENP’s Consolidated Statements of Operations and shown as a non-cash adjustment to net income in the “Operating activities” section of ENP’s Consolidated Statements of Cash Flows in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, ENP continues to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the reserves and the operating viability of the project. If subsequently it is determined that these conditions do not continue to exist, all previously capitalized costs associated with the exploratory well would be expensed and shown as a non-cash adjustment to net income in the “Operating activities” section of ENP’s Consolidated Statements of Cash Flows in the period in which the determination was made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Costs for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Costs to recomplete a well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the costs would be charged to expense. All capitalized costs associated with both development and exploratory wells are shown as “Development of oil and natural gas properties” in the “Investing activities” section of ENP’s Consolidated Statements of Cash Flows.
Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to barrels of oil equivalent (“BOE”) at the rate of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of oil.
The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to accumulated DD&A.
Miller and Lents, Ltd., ENP’s independent reserve engineer, estimates ENP’s reserves annually on December 31. This results in a new DD&A rate which ENP uses for the preceding fourth quarter after adjusting for fourth quarter production. ENP internally estimates reserve additions and reclassifications of reserves from proved undeveloped to proved developed at the end of the first, second, and third quarters for use in determining a DD&A rate for the respective quarter.
In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), ENP assesses the need for an impairment of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent that the carrying value exceeds fair value. Expected future net cash flows are based on existing proved reserves (and appropriately risk-adjusted probable reserves), forecasted production information, and management’s outlook of future commodity prices. Management aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. ENP uses prices consistent with the prices used in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment. Any impairment charge incurred is expensed and reduces the net basis in the asset. During 2008, events and circumstances indicated that a portion of ENP’s oil and natural gas properties might be impaired. However, ENP’s estimates of undiscounted cash flows based on management’s outlook of future commodity prices at the date of assessment indicated that the remaining carrying amounts of its oil and natural gas properties are expected to be recovered, although in some cases by only a marginal amount. If oil and natural gas prices continue to decline, it is reasonably possible that ENP’s estimates of undiscounted cash flows may
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
change in the near term resulting in the need to record a write down of ENP’s oil and natural gas properties to fair value.
Unproved properties, the majority of the costs of which relate to the acquisition of leasehold interests, are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss would be recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized would be determined by amortizing the portion of these properties’ costs which ENP believes will not be transferred to proved properties over the remaining life of the lease.
Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties, including wells and related equipment” consisted of the following as of the dates indicated:
Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is expensed on a straight-line basis over estimated useful lives, which range from three to seven years. Gains or losses from the disposal of other property and equipment are recognized in the period realized and included in “Other operating expense” of ENP’s Consolidated Statements of Operations.
Goodwill and Other Intangible Assets
ENP accounts for goodwill and other intangible assets under the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill and other intangible assets with indefinite useful lives are tested for impairment annually on December 31 or whenever indicators of impairment exist. If impairment is determined to exist, an impairment charge would be recognized for the amount by which the carrying value of the asset exceeds its implied fair value. The goodwill test is performed at the reporting unit level. ENP has determined that it has only one reporting unit, which is oil and natural gas production in the United States. ENP performed its annual impairment test at December 31, 2008 and determined that no impairment existed.
Intangible assets with definite useful lives are amortized over their estimated useful lives. In accordance with SFAS 144, ENP evaluates the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.
ENP is a party to a contract allowing it to purchase a certain amount of natural gas at a below market price for use as field fuel. The fair value of this contract, net of related amortization, is shown as “Other intangibles, net” on the accompanying Consolidated Balance Sheets. The gross carrying amount of this contract is $4.2 million and as of December 31, 2008 and 2007, accumulated amortization was $0.6 million and $0.3 million, respectively. During each of 2008 and 2007, ENP recorded $0.3 million of amortization
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
expense related to this contract. The net carrying amount is being amortized on a straight-line basis through July 2019. ENP expects to recognize $0.3 million of amortization expense during each of the next five years related to this contract.
Asset Retirement Obligations
In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” ENP recognizes the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which the property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of ENP’s oil and natural gas properties. The liability is recorded at its discounted fair value and then accreted each period until it is settled or the well is sold, at which time the liability is reversed. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining field life based on reserve estimates. ENP does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. Please read “Note 5. Asset Retirement Obligations” for additional information.
Unit-Based Compensation
ENP does not have any employees. However, the LTIP allows for the grant of unit awards and unit-based awards for employees, consultants, and directors of EAC, the General Partner, and any of their affiliates that perform services for ENP. In addition, in May 2007, the board of directors of the General Partner issued 550,000 management incentive units to certain executive officers of the General Partner.
For 2006, a portion of the general and administrative expenses and lease operating expenses allocated to ENP to reflect the carve out operations of the Predecessor was non-cash stock-based compensation recorded on the books of EAC.
ENP accounts for unit-based compensation according to the provisions of SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), which requires the recognition of compensation expense, over the requisite service period, in an amount equal to the fair value of the awards. ENP utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of employee stock options under SFAS 123R. Please read “Note 10. Unit-Based Compensation Plans” for additional discussion of ENP’s unit-based compensation plans.
Segment Reporting
ENP operates in only one industry: the oil and natural gas exploration and production industry in the United States. A single management team administers all properties as a whole rather than by discrete operating segments. ENP does not track all material costs to develop and operate its properties at a lower level, nor does its current internal reporting structure allow for accurate tracking at a lower level. Throughout the year, ENP allocates capital resources to projects on a project-by-project basis, across its entire asset base to maximize profitability without regard to individual areas.
Major Customers/Concentration of Credit Risk
In 2008, Marathon Oil Corporation, ConocoPhillips, and Chevron Corporation accounted for approximately 24 percent, 23 percent, and 10 percent of ENP’s sales of oil and natural gas products, respectively. In 2007, Marathon Oil Corporation and ConocoPhillips accounted for approximately 34 percent and 17 percent of ENP’s total sales of production, respectively. In 2006, Chevron Corporation accounted for approximately 31 percent of ENP’s sales of oil and natural gas production.
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Income Taxes
ENP is treated as a partnership for federal and state income tax purposes with each partner being separately taxed on his share of ENP’s taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying consolidated financial statements. However, ENP is subject to an entity-level tax, the Texas margin tax, at an effective rate of up to 0.7 percent on the portion of its income that is apportioned to Texas beginning with tax reports due on or after January 1, 2008. Deferred tax assets and liabilities are recognized for future Texas margin tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective Texas margin tax bases.
Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as ENP does not have access to information about each unitholder’s tax attributes in ENP.
On January 1, 2007, ENP adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation (“FIN”) No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The adoption of FIN 48 did not impact ENP’s financial condition, results of operations, or cash flows. ENP performs a periodic evaluation of tax positions to review the appropriate recognition threshold for each tax position recognized in its consolidated financial statements. On the date of adoption of FIN 48 and as of December 31, 2008 and 2007, all of ENP’s tax positions met the “more-likely-than-not” threshold prescribed by FIN 48. Any interest assessed by the taxing authorities would be included in “Interest expense” and penalties related to income taxes would be included in “Other expense” on the accompanying Consolidated Statements of Operations.
Oil and Natural Gas Revenue Recognition
Oil and natural gas revenues are recognized as oil and natural gas is produced and sold, net of royalties. Royalties and severance taxes are incurred based upon the actual price received from the sales. To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable - trade” in the accompanying Consolidated Balance Sheets. Natural gas revenues are reduced by any processing and other fees incurred except for transportation costs paid to third parties, which are recorded as “Other operating expense” in the accompanying Consolidated Statements of Operations. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on actual sales of natural gas rather than ENP’s proportionate share of natural gas production. If ENP’s overproduced imbalance position (i.e., ENP has cumulatively been over-allocated production) is greater than ENP’s share of remaining reserves, a liability is recorded for the excess at period-end prices unless a different price is specified in the contract in which case that price is used. Revenue is not recognized for the production in tanks, oil marketed on behalf of joint owners in ENP’s properties, or oil in pipelines that has not been delivered to the purchaser.
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ENP’s net oil inventories in pipelines were immaterial at December 31, 2008 and 2007. Natural gas imbalances at December 31, 2008 were 20,361 million British thermal units over-delivered to ENP. Natural gas imbalances at December 31, 2007 were immaterial.
Marketing Revenues and Expenses
In March 2007, ENP acquired a crude oil pipeline and a natural gas pipeline as part of the Elk Basin acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets. In addition, pipeline tariffs are collected for transportation through the crude oil pipeline.
Marketing revenues includes the sales of natural gas purchased from third parties as well as pipeline tariffs charged for transportation volumes through ENP’s pipelines. Marketing revenues derived from sales of natural gas purchased from third parties are recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, the sales price is fixed or determinable, and collectibility is reasonably assured. Marketing expenses include the cost of natural gas volumes purchased from third parties, pipeline tariffs, storage, truck facility fees, and tank bottom costs used to support the sale of oil production. As ENP takes title to the natural gas and has risks and rewards of ownership, these transactions are presented gross in the Consolidated Statements of Operations, unless they meet the criteria for netting as outlined in Emerging Issues Task Force (“EITF”) Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” ENP had no marketing activities prior to 2007.
Shipping Costs
Shipping costs in the form of pipeline fees and trucking costs paid to third parties are incurred to transport oil and natural gas production from certain properties to a different market location for ultimate sale. These costs are included in “Other operating expense” and “Marketing expense,” as applicable, in the accompanying Consolidated Statements of Operations.
Derivatives
ENP uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with its oil and natural gas production. These arrangements are structured to reduce ENP’s exposure to commodity price decreases, but they can also limit the benefit ENP might otherwise receive from commodity price increases. ENP’s risk management activity is generally accomplished through over-the-counter forward derivative or option contracts with large financial institutions. ENP also use derivative instruments in the form of interest rate swaps, which hedge its risk related to interest rate fluctuation.
ENP applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and its amendments, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative does not qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, changes in fair value can be recorded in accumulated other comprehensive income until such time as the hedged item is recognized in earnings.
To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically. Cash flow hedges are marked to market through accumulated other comprehensive income each period.
ENP has elected to designate our current interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in “Accumulated other comprehensive income” on the accompanying Consolidated Balance Sheets and reclassified into earnings in the same
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period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings immediately as “Derivative fair value loss (gain)” in the Consolidated Statements of Operations. While management does not anticipate changing the designation of ENP’s interest rate swaps as hedges, factors beyond ENP’s control can preclude the use of hedge accounting.
ENP has elected to not designate its portfolio of commodity derivative contracts as hedges and therefore, changes in fair value of these instruments are recognized in earnings as “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.
Allocation of Net Income (Loss)
ENP’s net income (loss) is allocated to partner equity accounts in accordance with the provisions of the partnership agreement. For purposes of calculating earnings per unit, ENP allocates net income (loss) to its limited partners and participating securities, including general partner units, each quarter under the provisions of EITF Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128.”
Earnings Per Unit
ENP calculates net income (loss) per common unit in accordance with SFAS No. 128, “Earnings per Share” (“SFAS 128”). Under the two-class method of calculating earnings per unit as prescribed by SFAS 128, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that may participate in undistributed earnings with common units. For purposes of calculating earnings per unit, the general partner units and management incentive units are participating securities. Net income (loss) per common unit is calculated by dividing the limited partners’ interest in net income (loss), after deducting the interests of the participating securities, by the weighted average number of common units outstanding. Please read “Note 9. Earnings Per Common Unit” for additional discussion.
For periods prior to the IPO, ENP was wholly owned by EAC, other than management incentive units owned by certain executive officers of the General Partner. Accordingly, earnings per unit is not presented for those periods.
Comprehensive Income
ENP has elected to show comprehensive income as part of its Consolidated Statements of Partners’ Equity and Comprehensive Income rather than in its Consolidated Statements of Operations.
New Accounting Pronouncements
SFAS No. 157, “Fair Value Measurements” (“SFAS 157”)
In September 2006, the FASB issued SFAS 157, which: (1) standardizes the definition of fair value; (2) establishes a framework for measuring fair value in GAAP; and (3) expands disclosures related to the use of fair value measures in financial statements. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value, but does not require any new fair value measurements. SFAS 157 was prospectively effective for financial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delayed the effective date of SFAS 157 for one year for nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). ENP elected a partial deferral of SFAS 157 for all instruments within the scope of FSP FAS 157-2, including, but not limited to, its asset retirement obligations and indefinite lived assets. The adoption of SFAS 157 on January 1, 2008, as it relates to financial assets and
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liabilities, did not have a material impact on ENP’s results of operations or financial condition. ENP does not expect the adoption of SFAS 157 on January 1, 2009, as it relates to all instruments within the scope of FSP FAS 157-2, to have a material impact on its results of operations or financial condition. Please read “Note 12. Fair Value Measurements” for additional discussion.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FASB Statement No. 115” (“SFAS 159”)
In February 2007, the FASB issued SFAS 159, which permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. SFAS 159 also allows entities an irrevocable option to measure eligible items at fair value at specified election dates, with resulting changes in fair value reported in earnings. SFAS 159 was effective for fiscal years beginning after November 15, 2007. ENP did not elect the fair value option for eligible instruments and therefore, the adoption of SFAS 159 on January 1, 2008 did not impact ENP’s results of operations or financial condition. ENP will assess the impact of electing the fair value option for eligible instruments acquired in the future. Electing the fair value option for such instruments could have a material impact on ENP’s future results of operations or financial condition.
FSP on FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”)
In April 2007, the FASB issued FSP FIN 39-1, which amends FIN No. 39, “Offsetting of Amounts Related to Certain Contracts” (“FIN 39”), to permit a reporting entity that is party to a master netting arrangement to offset the fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with FIN 39. FSP FIN 39-1 was effective for fiscal years beginning after November 15, 2007. The adoption of FSP FIN 39-1 on January 1, 2008 did not impact ENP’s results of operations or financial condition.
SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”)
In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS 141R establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. SFAS 141R is prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008, with early application prohibited. Subsequent to December 31, 2008, ENP completed an acquisition for certain oil and natural gas producing properties and related assets from Encore Operating. Please read “Note 14. Subsequent Events” for additional discussion of this acquisition. The accounting for transactions between entities under common control is unchanged under SFAS 141R. However, future acquisitions could have an impact on ENP’s results of operations and financial condition and the reporting in the consolidated financial statements.
SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (“SFAS 161”)
In March 2008, the FASB issued SFAS 161, which amends SFAS 133 to require enhanced disclosures about: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash
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flows. SFAS 161 is effective for fiscal years beginning on or after November 15, 2008, with early application encouraged. The adoption of SFAS 161 will require additional disclosures regarding ENP’s derivative instruments; however, it will not impact ENP’s results of operations or financial condition.
EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”)
In March 2008, the EITF ratified its consensus opinion on EITF 07-4, which addresses how master limited partnerships should calculate earnings per unit using the two-class method in SFAS 128 and how current period earnings of a master limited partnership should be allocated to the general partner, limited partners, and other participating securities. EITF 07-4 is retrospectively effective for fiscal years beginning after December 15, 2008, and interim periods within those years. ENP is evaluating the impact the adoption of EITF 07-4 will have on its earnings per unit calculations.
SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”)
In May 2008, the FASB issued SFAS 162, which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. SFAS 162 was effective November 15, 2008. The adoption of SFAS 162 did not impact ENP’s results of operations or financial condition.
FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”)
In June 2008, the FASB issued FSP EITF 03-6-1, which addresses whether instruments granted in unit-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per unit under the two-class method prescribed by SFAS 128. FSP EITF 03-6-1 is retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years, with early application prohibited. ENP is evaluating the impact the adoption of FSP EITF 03-6-1 will have on its earnings per unit calculations.
Note 3.
Acquisitions
Permian and Williston Basin Assets
In December 2007, OLLC entered into a purchase and investment agreement with Encore Operating pursuant to which OLLC agreed to acquire the Permian and Williston Basin Assets. The transaction closed in February 2008. The consideration for the acquisition consisted of approximately $125.3 million in cash, including post-closing adjustments, and 6,884,776 common units representing limited partner interests in ENP. In determining the total purchase price, the common units were valued at $125 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s historical carrying value of the properties. ENP funded the cash portion of the purchase price with borrowings under OLLC’s revolving credit facility.
As discussed in “Note 2. Summary of Significant Accounting Policies,” the transaction was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the acquired properties were recorded at Encore Operating’s historical cost of approximately $100 million, and the historical financial information of ENP was recast to include the Permian and Williston Basin Assets for all periods presented. As the historical basis in the Permian and Williston Basin Assets is included in the accompanying Consolidated Balance Sheets, the cash purchase price, as adjusted for post-closing adjustments, of the Permian and Williston Basin Assets was recorded as a deemed distribution to the EAC affiliates based on their respective ownership percentages in ENP’s general and limited partner units. No value was ascribed to
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the common units issued as consideration for the acquired properties as the cash consideration exceeded the historical carrying cost of the properties.
In May 2008, ENP acquired an existing net profits interest in certain of its properties in the Permian Basin of West Texas in exchange for 283,700 common units representing limited partner interests in ENP, which were valued at approximately $5.8 million at the time of the acquisition.
Elk Basin Assets
In January 2007, EAC entered into a purchase and sale agreement with a third party to acquire oil and natural gas properties and related assets in the Big Horn Basin of Wyoming and Montana, which included the Elk Basin Assets. Prior to closing, EAC assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin Assets to OLLC. The closing of the acquisition occurred in March 2007. The total purchase price for the Elk Basin Assets was approximately $330.7 million, including transaction costs of approximately $1.1 million.
ENP financed the acquisition of the Elk Basin assets through a $93.7 million contribution from EAC, $120 million of borrowings under a subordinated credit agreement with EAP Operating, LLC, a Delaware limited liability company and direct wholly owned subsidiary of EAC, and borrowings under OLLC’s revolving credit facility. Please read “Note 7. Long-Term Debt” for additional discussion of ENP’s long-term debt.
The following unaudited pro forma condensed financial data was derived from the historical financial statements of ENP and from the accounting records of the seller to give effect to the acquisition of the Elk Basin Assets as if it had occurred on January 1, 2006. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the acquisition of the Elk Basin Assets taken place on January 1, 2006 and is not intended to be a projection of future results.
For 2006, ENP was wholly owned by EAC. Accordingly, earnings per unit has not been calculated for that period.
Note 4.
Commitments and Contingencies
Litigation
ENP is a party to ongoing legal proceedings in the ordinary course of business. The General Partner’s management does not believe the result of these proceedings will have a material adverse effect on ENP’s business, financial position, results of operations, or liquidity.
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Leases
ENP leases equipment that has remaining non-cancelable lease terms in excess of one year. The following table summarizes by year the remaining non-cancelable future payments under these operating leases as of December 31, 2008 (in thousands):
ENP’s operating lease rental expense was approximately $0.8 million, $0.6 million, and $0.4 million in 2008, 2007, and 2006, respectively.
Note 5.
Asset Retirement Obligations
Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in ENP’s asset retirement obligations for the periods indicated:
As of December 31, 2008, approximately $9.0 million of ENP’s asset retirement obligations was long-term and recorded in “Future abandonment cost, net of current portion” and $0.4 million was current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets. Approximately $4.4 million of the future abandonment liability as of December 31, 2008 represents the estimated cost for decommissioning the Elk Basin natural gas processing plant. ENP expects to continue reserving additional amounts based on the estimated timing to cease operations of the natural gas processing plant.
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Note 6.
Other Current Liabilities
Other current liabilities consisted of the following as of the dates indicated:
Note 7.
Long-Term Debt
Revolving Credit Facility
OLLC is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The OLLC Credit Agreement matures on March 7, 2012. On August 22, 2007, OLLC amended its credit agreement to revise certain financial covenants. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.
The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. On December 5, 2008, the borrowing base under the OLLC Credit Agreement was redetermined with no change. At December 31, 2008, the borrowing base was $240 million.
OLLC’s obligations under the OLLC Credit Agreement are secured by a first-priority security interest in OLLC’s proved oil and natural gas reserves and in the equity interests in OLLC and its restricted subsidiaries. In addition, OLLC’s obligations under the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. Obligations under the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.
Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans bear interest at the base rate plus the applicable margin indicated in the following table:
The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate per year equal to the London Interbank Offered Rate (“LIBOR”), as published by Reuters or
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another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5 percent.
Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.
The OLLC Credit Agreement contains covenants that include, among others:
•
a prohibition against incurring debt, subject to permitted exceptions;
•
a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;
•
a restriction on creating liens on the assets of ENP, OLLC and its restricted subsidiaries, subject to permitted exceptions;
•
restrictions on merging and selling assets outside the ordinary course of business;
•
restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;
•
a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;
•
a requirement that ENP and OLLC maintain a ratio of consolidated current assets (as defined in the OLLC Credit Agreement) to consolidated current liabilities (as defined in the OLLC Credit Agreement) of not less than 1.0 to 1.0;
•
a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 1.5 to 1.0;
•
a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to consolidated senior interest expense of not less than 2.5 to 1.0; and
•
a requirement that ENP and OLLC maintain a ratio of consolidated funded debt (excluding certain related party debt) to consolidated adjusted EBITDA (as defined in the OLLC Credit Agreement) of not more than 3.5 to 1.0.
The OLLC Credit Agreement contains customary events of default. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.
OLLC incurs a commitment fee on the unused portion of the OLLC Credit Agreement determined based on the ratio of amounts outstanding under the OLLC Credit Agreement to the borrowing base in effect on such date. The following table summarizes the calculation of the commitment fee under the OLLC Credit Agreement:
On December 31, 2008, there were $150 million of outstanding borrowings and $90 million of borrowing capacity under the OLLC Credit Agreement. As of December 31, 2008, OLLC was in compliance with all covenants of the OLLC Credit Agreement.
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Subordinated Credit Agreement
In March 2007, OLLC entered into a six-year subordinated credit agreement with EAP Operating, LLC, a Delaware limited liability company and direct wholly owned subsidiary of EAC, pursuant to which a single subordinated term loan was made to ENP in the aggregate amount of $120 million. The total outstanding balance of $126.4 million, including accrued interest, was repaid in September 2007 using a portion of the net proceeds from the IPO.
Long-Term Debt Maturities
The following table illustrates ENP’s long-term debt maturities at December 31, 2008:
During 2008 and 2007, the weighted average interest rate for total indebtedness was 4.8 percent and 8.9 percent, respectively.
Note 8. Partners’ Equity and Distributions
ENP’s partnership agreement requires that, within 45 days after the end of each quarter, it distribute all of its available cash (as defined in the partnership agreement) to its unitholders. Distributions are not cumulative. ENP distributes available cash to its unitholders and the General Partner in accordance with their ownership percentages.
The following table illustrates information regarding ENP’s distributions of available cash for the periods indicated:
(a)
Based on an initial quarterly distribution of $0.35 per unit, prorated for the period from and including September 17, 2007 (the closing date of the IPO) through September 30, 2007.
Note 9.
Earnings Per Common Unit (“EPU”)
ENP calculates EPU in accordance with SFAS 128. Under the two-class method of calculating EPU as prescribed by SFAS 128, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that may participate in undistributed earnings with common units. For purposes of calculating EPU, the general partner units and vested management incentive units are participating securities.
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EPU is calculated by dividing the limited partners’ interest in net income or loss, after deducting the interests of participating securities by the weighted average number of common units outstanding. For 2007, EPU was calculated based on the net loss for the period from the closing of the IPO in September 2007 through December 31, 2007.
The following table presents the allocation of net income (loss) to the limited partners and reflects EPU computations for the periods indicated.
(a)
For 2007, 550,000 management incentive units were outstanding but were excluded from the diluted EPU calculations because their effect would have been antidilutive. Please read “Note 10. Unit-Based Compensation Plans” for additional discussion of the management incentive units.
Note 10.
Unit-Based Compensation Plans
Management Incentive Units
In May 2007, the board of directors of the General Partner issued 550,000 management incentive units to certain executive officers of the General Partner. A management incentive unit is a limited partner interest in ENP that entitles the holder to quarterly distributions to the extent paid to ENP’s common unitholders and to increasing distributions upon the achievement of 10 percent compounding increases in ENP’s distribution rate
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to common unitholders. On November 14, 2008 the management incentive units became convertible into ENP common units, at the option of the holder, at a ratio of one management incentive unit to approximately 3.1186 ENP common units. During the fourth quarter of 2008, all 550,000 management incentive units were converted into 1,715,205 ENP common units.
The fair value of the management incentive units granted in 2007 was estimated on the date of grant using a discounted dividend model. During 2008 and 2007, ENP recognized total compensation expense for the management incentive units of $4.8 million and $6.8 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of December 31, 2008, there have been no additional issuances of management incentive units.
Long-Term Incentive Plan
In September 2007, the board of directors of the General Partner approved the LTIP, which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. All employees, consultants, and directors of EAC, the General Partner, and any of their subsidiaries and affiliates who perform services for ENP and its subsidiaries and affiliates are eligible to be granted awards under the LTIP. The total number of common units reserved for issuance pursuant to the LTIP is 1,150,000. As of December 31, 2008, there were 1,100,000 common units available for issuance under the LTIP. The LTIP is administered by the board of directors of the General Partner or a committee thereof, referred to as the plan administrator. To satisfy common unit awards, ENP may issue new common units, acquire common units in the open market, or use common units already owned by EAC and its affiliates.
Phantom Units. From time to time, ENP issues phantom units to members of the General Partner’s board of directors pursuant to the LTIP. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. ENP intends to settle the phantom units at vesting by issuing common units; therefore, these phantom units are classified as equity instruments. Phantom units vest in four equal annual installments. The holders of phantom units are also entitled to receive distribution equivalent rights prior to vesting, which entitle them to receive cash equal to the amount of any cash distributions made by ENP with respect to a common unit during the period the right is outstanding. During 2008 and 2007, ENP recognized non-cash unit-based compensation expense for the phantom units of $0.3 million and $31,000, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations.
The following table summarizes the changes in the number of ENP’s unvested phantom units and their related weighted average grant date fair value for 2008:
ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
During 2008 and 2007, ENP issued 30,000 and 20,000, respectively, phantom units to members of the General Partner’s board of directors the vesting of which is dependent only on the passage of time and continuation as a board member. The following table illustrates outstanding phantom units at December 31, 2008:
As of December 31, 2008, ENP had $0.6 million of total unrecognized compensation cost related to unvested phantom units, which is expected to be recognized over a weighted average period of 1.5 years. During 2008, there were 6,250 phantom units that vested, the total fair value of which was $0.1 million.
Note 11. Financial Instruments
The book value of ENP’s cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments. The book value of long-term debt approximates fair value as the interest rate is variable. Commodity derivative contracts and interest rate swaps are marked-to-market each quarter.
Derivative Financial Instruments
Commodity Derivative Contracts. ENP manages commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price for a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price.
From time to time, ENP sells floors with a strike price below the strike price of the purchased floors in order to partially finance the premiums paid on the purchased floors. Together the two floors, known as a floor spread or put spread, have a lower premium cost than a traditional floor contract but provide price protection only down to the strike price of the short floor. As with ENP’s other commodity derivative contracts, these are marked-to-market each quarter through “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations. In the following tables, the purchased floor component of these floor spreads are shown net and included with ENP’s other floor contracts.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following tables summarize ENP’s open commodity derivative contracts as of December 31, 2008:
Oil Derivative Contracts
(a)
In addition, ENP has a floor contract for 1,000 Bbls/D at $63.00 per Bbl and a short floor contract for 1,000 Bbls/D at $65.00 per Bbl.
Natural Gas Derivative Contracts
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Interest Rate Swaps. ENP manages interest rate risk with interest rate swaps whereby it swaps floating rate debt under the OLLC Credit Agreement with a weighted average fixed rate. These interest rate swaps were designated as cash flow hedges. The following table summarizes ENP’s open interest rate swaps as of December 31, 2008:
As of December 31, 2008, the fair market value of ENP’s interest rate swaps was a net liability of $4.6 million of which, $1.3 million was current and included in the current liabilities line “Derivatives” and $3.3 million was long-term and included in the other liabilities line “Derivatives” in the accompanying Consolidated Balance Sheets. During 2008, settlements of interest rate swaps increased ENP’s interest expense by approximately $0.2 million.
Current Period Impact. ENP recognized derivative fair value gains and losses related to: (1) ineffectiveness on designated derivative contracts; (2) changes in the market value of derivative contracts; (3) settlements on commodity derivative contracts; and (4) premium amortization. The following table summarizes the components of derivative fair value loss (gain) for the periods indicated:
Counterparty Risk. At December 31, 2008, ENP had committed greater than 10 percent of either its oil or natural gas commodity derivative contracts to the following counterparties:
In order to mitigate the credit risk of financial instruments, ENP enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and ENP. Instead of treating separately each financial transaction between the counterparty and ENP, the master netting agreement enables the counterparty and ENP to aggregate all financial trades and treat them as a single agreement. This arrangement benefits ENP in three ways: (1) the netting of the value of
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
all trades reduces the likelihood of counterparties requiring daily collateral posting by ENP; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces ENP’s credit exposure to a given counterparty in the event of close-out.
Accumulated Other Comprehensive Loss. At December 31, 2008, accumulated other comprehensive loss consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps that are designated as hedges of $4.3 million. ENP expects to reclassify $1.3 million of deferred losses associated with its interest rate swaps from accumulated other comprehensive loss to interest expense during 2009.
Note 12.
Fair Value Measurements
As discussed in “Note 2. Summary of Significant Accounting Policies,” ENP adopted SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by SFAS 157 are as follows:
•
Level 1 - Unadjusted quoted prices are available in active markets for identical assets or liabilities.
•
Level 2 - Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.
•
Level 3 - Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.
ENP’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions are used to estimate the fair values of ENP’s financial assets and liabilities that are accounted for at fair value on a recurring basis:
•
Level 2 - Fair values of oil and natural gas swaps were estimated using a combined income and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services reflecting broker market quotes. Fair values of interest rate swaps were estimated using a combined income and market-based valuation methodology based upon credit ratings and forward interest rate yield curves obtained from independent pricing services reflecting broker market quotes.
•
Level 3 - Fair values of oil and natural gas floors and caps were estimated using pricing models and discounted cash flow methodologies based on inputs that are not readily available in public markets.
ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table sets forth ENP’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008.
The following table summarizes the changes in the fair value of ENP’s Level 3 financial assets and liabilities for 2008:
Since ENP does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 financial assets and liabilities are included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations. All fair values reflected in the tables above and in the accompanying Consolidated Balance Sheet as of December 31, 2008 have been adjusted for non-performance risk, resulting in a reduction of the net asset of approximately $1.4 million as of December 31, 2008.
Note 13.
Related Party Transactions
ENP does not have any employees. The employees supporting the operations of ENP are employees of EAC. As discussed in “Note 1. Formation of the Partnership and Description of Business,” ENP entered into the Administrative Services Agreement pursuant to which Encore Operating performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering. In addition, Encore Operating provides all personnel and any facilities, goods, and equipment necessary to perform these services and not otherwise provided by ENP. Encore Operating initially received an administrative fee of $1.75 per BOE of ENP’s production for such services. Effective April 1, 2008, the administrative fee increased to $1.88
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
per BOE of ENP’s production as a result of the COPAS Wage Index Adjustment. Encore Operating also charges ENP for reimbursement of actual third-party expenses incurred on ENP’s behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator of a well. Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the Administrative Services Agreement unless its acts or omissions constitute gross negligence or willful misconduct.
ENP also reimburses EAC for any additional state income, franchise, or similar tax incurred by EAC resulting from the inclusion of ENP and its subsidiaries in consolidated tax returns with EAC and its subsidiaries as required by applicable law. The amount of any such reimbursement is limited to the tax that ENP and its subsidiaries would have incurred had it not been included in a combined group with EAC.
In 2008 and 2007, ENP paid Encore Operating $6.6 million and $2.8 million, respectively, for administrative fees under the Administrative Services Agreement (including payment of any COPAS recovery) and $8.3 million and $3.5 million, respectively, for reimbursement of actual third-party expenses incurred on ENP’s behalf. Expenses incurred under the Administrative Services Agreement and third-party expenses billed by EAC to ENP are included in “General and administrative expenses” in the accompanying Consolidated Statements of Operations. As of December 31, 2008 and 2007, ENP had a payable to EAC of $1.6 million and $6.7 million, respectively, which is reflected in “Accounts payable - affiliate” in the accompanying Consolidated Balance Sheets. As of December 31, 2008 and 2007, ENP had a receivable from EAC of $0.7 million and $3.3 million, respectively, which is reflected in “Accounts receivable - affiliate” in the accompanying Consolidated Balance Sheets.
As discussed in “Note 3. Acquisitions,” ENP completed the acquisition of the Permian and Williston Basin Assets from Encore Operating in February 2008 for total consideration of approximately $125.3 million in cash, including certain post-closing adjustments, and 6,884,776 common units representing limited partner interests in ENP. In determining the total purchase price, the common units were valued at $125 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s historical carrying value of the properties.
During 2008 and 2007, ENP distributed approximately $49.3 million and $0.8 million, respectively, to EAC and certain executive officers of the General Partner related to quarterly distribution on common units and management incentive units. During 2008 and 2007, ENP distributed approximately $1.2 million and $27 thousand, respectively, to the General Partner as the holder of all 504,851 general partner units.
As discussed in “Note 7. Long-Term Debt,” during 2007, ENP had a subordinated credit agreement with a subsidiary of EAC, which was repaid in full from a portion of the net proceeds from the IPO.
Prior to the contribution of the Permian Basin Assets to ENP in September 2007 and the acquisition of the Permian and Williston Basin Assets in February 2008, these properties were wholly owned by EAC and were not separate legal entities. In addition to employee-related expenses, EAC incurred G&A expenses related to leasing office space and other corporate overhead expenses during the period these properties were wholly owned by EAC. A portion of the consolidated G&A expenses reported for EAC were allocated to ENP and included in the accompanying Consolidated Statements of Operations based on the respective percentage of BOE produced by the properties in relation to the total BOE produced by EAC on a consolidated basis.
EAC (through its subsidiaries) contributed $93.7 million to ENP in March 2007. These proceeds were used by ENP, along with proceeds from the borrowings under ENP’s long-term debt agreements, to purchase the Elk Basin Assets. Additionally, EAC (through its subsidiaries) made a non-cash contribution in March 2007 of derivative oil put contracts representing 2,500 Bbls/D of production at $65.00 per Bbl for the period of April 2007 through December 2008. At the date of transfer, the derivative contracts had a fair value of $9.4 million.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 14.
Subsequent Events - Unaudited
Purchase and Sale Agreement
On December 5, 2008, OLLC entered into a purchase and sale agreement, with Encore Operating, pursuant to which OLLC acquired certain oil and natural gas producing properties and related assets in the Arkoma Basin and royalty interest properties in Oklahoma as well as 10,300 unleased mineral acres. The transaction closed on January 2, 2009. The purchase price was $49 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3 million), which OLLC financed through borrowings under the OLLC Credit Agreement.
The acquisition will be accounted for as a transaction between entities under common control. Therefore, the assets will be recorded on ENP’s balance sheet at EAC’s historical basis, and the historical results of operations of ENP will be restated to reflect the historical operating results of the combined entities.
Distributions
On January 26, 2009, ENP announced a distribution for the fourth quarter of 2008 to unitholders of record as of the close of business on February 6, 2009. Approximately $16.8 million was paid on February 13, 2009 to unitholders at a rate of $0.50 per unit.
ENCORE ENERGY PARTNERS LP
SUPPLEMENTARY INFORMATION
Capitalized Costs and Costs Incurred Relating to Oil and Natural Gas Producing Activities
The capitalized cost of oil and natural gas properties was as follows as of the dates indicated:
The following table summarizes costs incurred related to oil and natural gas properties for the periods indicated:
Oil & Natural Gas Producing Activities - Unaudited
The estimates of ENP’s proved oil and natural gas reserves, which are located entirely within the United States, were prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the FASB. Proved oil and natural gas reserve quantities are derived from estimates prepared by Miller and Lents, Ltd., who are independent petroleum engineers.
Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods assumed or that prices and costs will remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. In accordance with SEC guidelines, estimates of future net cash flows from ENP’s properties and the representative value thereof are made using oil and natural gas prices in effect as of the dates of such estimates and are held
ENCORE ENERGY PARTNERS LP
SUPPLEMENTARY INFORMATION - (Continued)
constant throughout the life of the properties. Year-end prices used in estimating net cash flows were as follows as of the dates indicated:
Net future cash inflows have not been adjusted for commodity derivative contracts outstanding at the end of the year. The future cash flows are reduced by estimated production and development costs, which are based on year-end economic conditions and held constant throughout the life of the properties, and by the estimated effect of future income taxes due to the Texas margin tax. Future federal income taxes have not been deducted from future net revenues in the calculation of ENP’s Standardized Measure as each partner is separately taxed on his share of ENP’s taxable income.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. Oil and natural gas reserve engineering is and must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and estimates of other engineers might differ materially from those included herein. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions based on the results of drilling, testing, and production activities. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered. Reserve estimates are integral to management’s analysis of impairments of oil and natural gas properties and the calculation of DD&A on these properties.
ENP’s estimated net quantities of proved oil and natural gas reserves were as follows as of the dates indicated:
ENCORE ENERGY PARTNERS LP
SUPPLEMENTARY INFORMATION - (Continued)
The changes in ENP’s proved reserves were as follows for the periods indicated:
(a)
Includes 10,568 MBOE, 6,871 MBOE, and 7,115 MBOE of proved reserves as of December 31, 2007, 2006, and 2005, respectively, associated with the Permian and Williston Basin Assets ENP acquired from EAC in February 2008. The acquisition of these assets was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby ENP’s historical financial information and proved reserve volumes were recast to include the acquired properties for all periods presented.
ENP’s Standardized Measure of discounted estimated future net cash flows was as follows as of the dates indicated:
ENCORE ENERGY PARTNERS LP
SUPPLEMENTARY INFORMATION - (Continued)
The changes in ENP’s Standardized Measure of discounted estimated future net cash flows were as follows for the periods indicated:
Selected Quarterly Financial Data - Unaudited
The following table sets forth selected quarterly financial data for the periods indicated:
The table above presents the allocation of net loss to the limited partners for the period subsequent to the IPO and displays EPU for the applicable periods. For periods prior to the IPO, ENP was wholly owned by EAC, other than management incentive units owned by certain executive officers of the General Partner. Accordingly, EPU is not presented for those periods.
ENCORE ENERGY PARTNERS LP
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 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, of the effectiveness of our disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer of our general partner concluded that our disclosure controls and procedures were effective as of December 31, 2008 to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer of our general partner, to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control Over Financial Reporting
Our general partner’s management is responsible for establishing and maintaining adequate internal control over financial reporting. ENP’s internal control over financial reporting is a process designed under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of ENP’s financial statements for external purposes in accordance with GAAP.
As of December 31, 2008, management assessed the effectiveness of ENP’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control - Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, management determined that ENP maintained effective internal control over financial reporting as of December 31, 2008, based on those criteria.
Ernst & Young, LLP, the independent registered public accounting firm that audited the consolidated financial statements of ENP included in this annual report on Form 10-K, has issued an attestation report on the effectiveness of ENP’s internal control over financial reporting as of December 31, 2008. The report, which expresses an unqualified opinion on the effectiveness of ENP’s internal control over financial reporting as of December 31, 2008, is included below.
ENCORE ENERGY PARTNERS LP
Report of Independent Registered Public Accounting Firm
To the Board of Directors of Encore Energy Partners GP LLC
and Unitholders of Encore Energy Partners LP:
We have audited Encore Energy Partners LP’s (the “Partnership”) internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Encore Energy Partners LP’s management is responsible 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 the Partnership’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed 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 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.
In our opinion, Encore Energy Partners LP maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Encore Energy Partners LP as of December 31, 2008 and 2007, and the related consolidated statements of operations, partners’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008 and our report dated February 24, 2009 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Fort Worth, Texas
February 24, 2009
ENCORE ENERGY PARTNERS LP
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Encore Energy Partners GP LLC, our general partner and an indirect wholly owned subsidiary of EAC, manages our operations and activities. All executive officers of our general partner are employees of EAC and devote time as needed to conduct our business and affairs. Encore Energy Partners GP LLC has a board of directors that oversees its management, operations, and activities. We refer to the board of directors of Encore Energy Partners GP LLC as the “board of directors of our general partner.” The board of directors and executive officers of our general partner make all strategic decisions on our behalf.
At the closing of our initial public offering, we entered into an administrative services agreement with Encore Operating and EAC pursuant to which Encore Operating performs administrative services for us. For more information regarding the administrative services agreement, please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence - Administrative Services Agreement.”
Our general partner is not elected by our unitholders nor subject to re-election on a regular basis. Unitholders are also not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. As owner of our general partner, EAC has the ability to elect all the members of the board of directors of our general partner. Our general partner owes a fiduciary duty to our unitholders, although our partnership agreement limits such duties and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. 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 specifically nonrecourse to it.
ENCORE ENERGY PARTNERS LP
Directors and Executive Officers of Our General Partner
The following table sets forth certain information regarding the members of the board of directors and the executive officers of our general partner. Directors are elected for one-year terms by EAC. The directors of our general partner hold office until the earlier of their death, resignation, removal, or disqualification or until their successors have been elected and qualified. Officers of our general partner serve at the discretion of the board of directors of our general partner.
I. Jon Brumley has been Chairman of the Board of our general partner since February 2007. Mr. Brumley is Chairman of the Board of EAC, a position he has held since its inception in April 1998. He also served as Chief Executive Officer of EAC from its inception until December 2005 and President of EAC from its inception until August 2002. Beginning in August 1996, Mr. Brumley served as Chairman and Chief Executive Officer of MESA Petroleum (an independent oil and gas company) until MESA’s merger in August 1997 with Parker & Parsley to form Pioneer Natural Resources Company (an independent oil and gas company). He served as Chairman and Chief Executive Officer of Pioneer until joining EAC in 1998. Mr. Brumley received a Bachelor of Business Administration from the University of Texas and a Master of Business Administration from the University of Pennsylvania Wharton School of Business. He is the father of Jon S. Brumley.
Jon S. Brumley has been the Chief Executive Officer, President, and Director of our general partner since February 2007. Mr. Brumley has been Chief Executive Officer of EAC since January 2006, President of EAC since August 2002, and a director of EAC since November 2001. He also held the positions of Executive Vice President - Business Development and Corporate Secretary from EAC’s inception in April 1998 until August 2002 and was a director of EAC from April 1999 until May 2001. Prior to joining EAC, Mr. Brumley held the position of Manager of Commodity Risk and Commercial Projects for Pioneer Natural Resources Company. He was with Pioneer since its creation by the merger of MESA and Parker & Parsley in August 1997. Prior to August 1997, Mr. Brumley served as Director - Business Development for MESA. Mr. Brumley received a Bachelor of Business Administration in Marketing from the University of Texas. He is the son of I. Jon Brumley.
Robert C. Reeves has been the Senior Vice President, Chief Financial Officer, and Treasurer of our general partner since February 2007 and Corporate Secretary since May 2008. Mr. Reeves has been Senior Vice President, Chief Financial Officer, and Treasurer of EAC since November 2006 and has been Corporate Secretary of EAC since May 2008. From November 2006 until January 2007, Mr. Reeves also served as
ENCORE ENERGY PARTNERS LP
Corporate Secretary of EAC. Mr. Reeves served as Senior Vice President, Chief Accounting Officer, Controller, and Assistant Corporate Secretary of EAC from November 2005 until November 2006. He served as EAC’s Vice President, Controller, and Assistant Corporate Secretary from August 2000 until October 2005. He served as Assistant Controller of EAC from April 1999 until August 2000. Prior to joining EAC, Mr. Reeves served as Assistant Controller for Hugoton Energy Corporation. Mr. Reeves received his Bachelor of Science degree in Accounting from the University of Kansas. He is a Certified Public Accountant.
L. Ben Nivens has been the Senior Vice President and Chief Operating Officer of our general partner since February 2007. Mr. Nivens has been Senior Vice President and Chief Operating Officer of EAC since November 2006. From October 2005 until November 2006, Mr. Nivens served as Senior Vice President, Chief Financial Officer, Treasurer, and Corporate Secretary of EAC. Mr. Nivens served as EAC’s Vice President of Corporate Strategy and Treasurer from June 2005 until October 2005. From April 2002 to June 2005, Mr. Nivens served as engineering manager and in other engineering positions for EAC. Prior to joining EAC, he worked as a reservoir engineer for Prize Energy from 1999 to 2002. From 1990 to 1999, Mr. Nivens worked in the corporate planning group at Union Pacific Resources and also served as a reservoir engineer. In addition, he worked as a reservoir engineer for Compass Bank in 1999. Mr. Nivens received a Bachelor of Science in Petroleum Engineering from Texas Tech University and a Masters of Business Administration from Southern Methodist University.
John W. Arms has been the Senior Vice President - Acquisitions of our general partner since February 2007. Mr. Arms has served as Senior Vice President - Acquisitions of EAC since February 2007. Mr. Arms served as Vice President of Business Development of EAC from September 2001 until February 2007. From November 1998 until September 2001, Mr. Arms served as Manager of Acquisitions and in various other petroleum engineering positions for EAC. Prior to joining EAC in November 1998, Mr. Arms was a Senior Reservoir Engineer for Union Pacific Resources and an Engineer at XTO Energy, Inc. Mr. Arms received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines.
Kevin Treadway has been the Senior Vice President - Land of our general partner and EAC since February 2008 and served as our Vice President - Land from February 2007 to February 2008. From 2004 until February 2008, Mr. Treadway served as Vice President - Land of EAC. He joined EAC in 2000 as staff landman and in 2002 was promoted to Land Manager. Prior to joining EAC, Mr. Treadway served as a Landman at Coho Resources. Mr. Treadway received a Bachelor of Science degree in Petroleum Land Management from the University of Southwestern Louisiana
Andrea Hunter has been Vice President, Controller, and Principal Accounting Officer of our general partner and EAC since February 2008. Prior to her promotion, Ms. Hunter had served as Controller of our general partner and EAC since September 2007. From July 2003 to September 2007, Ms. Hunter held positions of increasing responsibility at EAC, including financial reporting senior manager. Prior to joining EAC in July 2003, Ms. Hunter worked in public accounting, first in the Assurance and Business Advisory Services of PricewaterhouseCoopers LLP and later as an editor at Thomson Publishing’s Practitioners Publishing Company. Ms. Hunter received a Master of Science and Bachelor of Business Administration, both in Accounting, from the University of Texas at Arlington. She is a Certified Public Accountant.
Thomas H. Olle has served as Vice President, Strategic Solutions of our general partner and EAC since February 2008. From February 2007 to February 2008, Mr. Olle served as Vice President, Mid-Continent Region of our general partner. From November 2006 to February 2008, Mr. Olle served as Vice President, Mid-Continent Region of EAC. From February 2005 until November 2006, Mr. Olle was EAC’s Senior Vice President, Asset Management. Mr. Olle served as EAC’s Senior Vice President, Asset Management of the Cedar Creek Anticline from April 2003 to February 2005. Mr. Olle joined EAC in March 2002 as Vice President of Engineering. Prior to joining EAC, Mr. Olle served as Senior Engineering Advisor of Burlington Resources, Inc. (an independent oil and gas company) from September 1999 to March 2002. From July 1986 to September 1999, he served as Regional Engineer of Burlington Resources. Mr. Olle received a Bachelor of Science degree with Highest Honors in Mechanical Engineering from the University of Texas at Austin.
ENCORE ENERGY PARTNERS LP
Andy R. Lowe has been Vice President, Marketing of our general partner since February 2008. Mr. Lowe has been Vice President, Marketing of EAC since February 2007. From May 2006 until February 2007, Mr. Lowe was EAC’s Director of Marketing. Prior to joining EAC, Mr. Lowe was Vice President - Marketing for Vintage Petroleum, Inc. from December 1997 until December 2005. Mr. Lowe served as General Manager - Marketing for Vintage Petroleum, Inc. from 1992 until December 1997. Mr. Lowe served as president of Quasar Energy, Inc. from 1990 until 1992, providing downstream natural gas marketing services. From September 1983 to November 1990, he was employed by Maxus Energy Corporation, formerly Diamond Shamrock Exploration Company, serving as Manager of Marketing and in various other management and supervisory capacities. From 1981 to September 1983, he was employed by American Quasar Exploration Company as Manager of Oil and Gas Marketing. From 1978 to 1981, Mr. Lowe was employed by Texas Pacific Oil Company serving in various positions in production and marketing. Mr. Lowe received a Bachelor of Science degree in Education from Texas Tech University.
Arnold L. Chavkin has been a director of our general partner since October 2007 and is the chairman of the audit committee of the Board of Directors. Mr. Chavkin is also a member of the conflicts committee of the Board of Directors. Mr. Chavkin is a managing director at Pinebrook Road Partners, a private equity fund. From 1991 until his retirement in 2006, he served in various capacities with JPMorgan Chase & Co, including as the Chief Investment Officer at J.P. Morgan Partners, LLC. Prior to that, Mr. Chavkin was a member of Chemical Bank’s merchant banking and corporate finance groups, specializing in mergers and acquisitions and private placements for the energy industry. Mr. Chavkin served as a director of Encore Acquisition Company from 1998 to 2004. Mr. Chavkin is a Certified Public Accountant. He received a Bachelor of Arts degree and a Masters of Business Administration from Columbia University.
John E. Jackson has been a director of our general partner since February 2008. Mr. Jackson has served as Chairman, Chief Executive Officer and President of Price Gregory Services, Inc. (a pipeline-related infrastructure service provider in North America) since February 2008. Mr. Jackson has served as a director of Hanover Compressor Company (now Exterran Holdings, Inc.) since July 2004 and served as Hanover’s President and Chief Executive Officer from October 2004 to August 2007. Mr. Jackson joined Hanover in January 2002 as Senior Vice President and Chief Financial Officer. Mr. Jackson also serves as a director of Seitel, Inc.
J. Luther King, Jr. has been a director of our general partner since August 2007. Mr. King is the President of Luther King Capital Management Corporation, a registered investment advisory firm that he founded in 1979, and has served as President and Trustee of LKCM Funds, a registered investment company, since 1994. Mr. King serves as a director of Tyler Technologies, Inc. and is a member of its Audit Committee. In addition, Mr. King serves as the chairman of the board of trustees of Texas Christian University. Mr. King has a Bachelor of Science degree and a Masters of Business Administration from Texas Christian University and is a Chartered Financial Analyst.
Clayton E. Melton has been a director of our general partner since August 2007. Mr. Melton has served as President of Atlantic Service & Supply LLC, a distributor of heating and air conditioning equipment located in Fort Worth, Texas, since January 2003. From May 1999 to December 2002, he served as President of Comfort Products L.L.C., an air conditioning and heating distribution company. Prior to May 1999, Mr. Melton held various leadership and management positions in his over 33 years of service in the U.S. Army obtaining the rank of Brigadier General. Mr. Melton received a Bachelor of Science in Business Administration from William Carey College and a Masters of Public Administration from the University of Missouri.
George W. Passela has been a director of our general partner since August 2007. Mr. Passela is the Chief Financial Officer of Momentum Energy Group LLC, a natural gas gathering, compression, treating, and processing company. Prior to joining Momentum Energy, Mr. Passela was Managing Director at Banc of America Securities LLC, with responsibility for capital raising and investments in the exploration and production and midstream sectors. From 1977 until 2005, Mr. Passela was employed by The First National Bank of Boston in its International Division, initially working with multinational corporations that provided
ENCORE ENERGY PARTNERS LP
export and commodity financing in South America. From 1982 until 1987, he served as Branch Manager in Frankfurt, Germany. Upon returning to Boston, Mr. Passela established The First National Bank of Boston’s exploration and production practice and held various management positions in its energy group through 2005. Mr. Passela holds a Bachelor of Arts degree from the University of Miami and a Masters of Business Administration from the University of Utah.
Director Independence
The board of directors of our general partner has seven members, none of whom are officers or employees of EAC and its affiliates, including our general partner, other than Mr. I. Jon Brumley and Mr. Jon S. Brumley. The board of directors of our general partner has determined that Messrs. Chavkin, King, Melton, and Passela are independent, as defined for purposes of the listing standards of the NYSE. In making this determination, the board of directors of our general partner affirmatively determined that each independent director had no material relationship with EAC and its affiliates, including our general partner (either directly or as a partner, shareholder, or officer of an organization that has a relationship with EAC and its affiliates, including our general partner), and that none of the express disqualifications contained in the NYSE rules applied to any of them.
As contemplated by NYSE rules, the board of directors of our general partner has adopted categorical standards to assist it in making independence determinations, under which relationships that fall within the categorical standards are not required to be disclosed in this Report and their impact on independence need not be separately discussed. The board of directors of our general partner, however, considers all material relationships with each director in making its independence determinations. A relationship falls within the categorical standards if it:
•
Is a type of relationship addressed in Item 404 of Regulation S-K under the Securities Exchange Act of 1934 or Section 303A.02(b) of the NYSE Listed Company Manual, but under those rules neither requires disclosure nor precludes a determination of independence; or
•
Consists of charitable contributions by EAC and its affiliates, including our general partner to an organization where a director is an executive officer and does not exceed the greater of $1 million or 2% of the organization’s gross revenue in any of the last three years.
None of the independent directors had relationships relevant to an independence determination that were outside the scope of the categorical standards.
The NYSE 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 or to establish a compensation committee or a nominating and corporate governance committee.
Board Committees
As of February 18, 2009, the board of directors of our general partner had an audit and conflicts committee. The following table sets forth the membership on each committee:
In 2008, the audit committee held 7 meetings, the conflicts committee held 2 meetings, and the board of directors of our general partner held 6 meetings. Each director attended at least 75 percent of all board and applicable committee meetings in 2008.
ENCORE ENERGY PARTNERS LP
Audit Committee. The audit committee’s purpose is, among other things, to assist the board of directors of our general partner in overseeing:
•
the integrity of our financial statements;
•
our compliance with legal and regulatory requirements;
•
the independence, qualifications, and performance of our independent registered public accounting firm; and
•
the performance of our internal audit function.
The board of directors of our general partner has determined that all members of the audit committee are independent under the listing standards of the NYSE and the rules of the SEC. In addition, the board of directors of our general partner has determined that Mr. Chavkin is an “audit committee financial expert” as such term is defined in Item 407(d)(5) of Regulation S-K.
The charter of the audit committee is available on the “Corporate Governance” section of our website at www.encoreenp.com. Unitholders may request free printed copies of the audit committee charter from the following address:
Encore Energy Partners GP LLC
Attention: Corporate Secretary
777 Main Street, Suite 1400
Fort Worth, Texas 76102
(817) 877-9955
Conflicts Committee. The conflicts committee reviews specific matters that the board of directors of our general partner believes may involve conflicts of interest. At the request of the board of directors of our general partner, the conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, including EAC, and must meet the independence and experience standards established by the NYSE Listed Company Manual and the Securities Exchange Act of 1934 to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach of our general partner of any duties it may owe us or our unitholders.
Code of Business Conduct and Ethics and Governance Guidelines
We have adopted a Code of Business Conduct and Ethics for our general partner’s directors, officers (including our general partner’s principal executive officer, principal financial officer, and principal accounting officer), and employees. We have also adopted Governance Guidelines, which address director qualification standards; director responsibilities; director access to management, and as necessary and appropriate, independent advisors; director compensation; director orientation and continuing education; and annual performance evaluation of the board of directors. We will post on our website any amendments to the Code of Business Conduct and Ethics or waivers of the Code of Business Conduct and Ethics for directors and executive officers.
Our Code of Business Conduct and Ethics and the Governance Guidelines are available free of charge on the “Corporate Governance” section of our website (www.encoreenp.com). Unitholders may request free
ENCORE ENERGY PARTNERS LP
printed copies of the Code of Business Conduct and Ethics and Governance Guidelines from the following address:
Encore Energy Partners GP LLC
Attention: Corporate Secretary
777 Main Street, Suite 1400
Fort Worth, Texas 76102
(817) 877-9955
NYSE Corporate Governance Listing Standards
We have filed the required certifications under Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2 to this Report. In 2008, we submitted to the NYSE the CEO certification required by Section 303A.12(a) of the NYSE’s Listed Company Manual. In 2009, we plan to submit this certification to the NYSE within thirty days after filing this Report.
Executive Sessions of Non-Management Directors
The board of directors holds regular executive sessions in which non-management directors meet without any members of management present. Messrs. Chavkin, Jackson, King, Melton, and Passela are non-management directors of our general partner and Messrs. Chavkin, King, Melton, and Passela are independent under the listing standards of the NYSE. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. The chairman of the audit committee acts as chair of such executive sessions.
In accordance with NYSE rules, we have established a toll-free, confidential telephone hotline (the “Hotline”) so that interested parties may communicate with the presiding director or with all the non-management directors as a group. All calls to this Hotline are reported to the chairman of the audit committee, who is responsible for communicating any necessary information to the other non-management directors. The number of our confidential Hotline is (866) 783-5389.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires directors and executive officers of our general partner and holders of more than 10 percent of our common units to file reports with the SEC regarding their ownership and changes in ownership of our securities. We believe that, during 2008, the directors and executive officers of our general partner and our 10 percent unitholders complied with all Section 16(a) filing requirements, except that a Form 4 for each of Messrs. I. Jon Brumley, Melton, Jackson, and Passela was filed late. In making these statements, we have relied upon examination of the copies of Forms 3, 4, and 5, and amendments thereto, provided to us and the written representations of the directors and executive officers of our general partner.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
General
We do not employ any of the persons responsible for managing our business, and we do not have a compensation committee. Our general partner manages our operations and activities and its board of directors and officers make decisions on our behalf. All of the executive officers of our general partner also serve as executive officers of EAC. The compensation of EAC’s employees that perform services on our behalf (other than the long-term incentive plan benefits described below) are set by the compensation committee of, and
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paid for, by EAC. We do not expect to pay any salaries or bonuses, or to make awards under our long-term incentive plan, to the named executive officers of our general partner.
Management Incentive Units
General
In May 2007, the board of directors of our general partner granted management incentive units to certain executive officers of our general partner. A management incentive unit is a limited partner interest in our partnership that entitles the holder to quarterly distributions to the extent paid to our common unitholders and to increasing distributions upon the achievement of 10 percent compounding increases in our distribution rate to common unitholders. On November 14, 2008 the management incentive units became convertible into our common units, at the option of the holder, at a ratio of one management incentive unit to approximately 3.1186 of our common units. During the fourth quarter of 2008, the holders of the management incentive units converted all 550,000 management incentive units into 1,715,205 of our common units.
In addition to approval by the board of directors of our general partner, the grants of management incentive units were approved by EAC’s Board of Directors based on the recommendation of its compensation committee, which consists of James A. Winne III, Martin C. Bowen, and Ted Collins, Jr. In making its decision to approve the grant of management incentive units by the board of directors of our general partner, EAC’s Board of Directors and its compensation committee relied on, among other things, the advice of an independent compensation consultant retained by the compensation committee, as well as analyses of equity compensation and ownership by other executives of master limited partnerships.
The management incentive units were issued based on the assumption that we would not pay the recipients any salaries or bonuses, or grant them any awards under our long-term incentive plan.
The following table sets forth the recipients of the management incentive units:
Compensation Committee Report
Neither we nor our general partner has a compensation committee. The board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above with management and based on this review and discussion has approved it for inclusion in this Form 10-K.
The board of directors of Encore Energy
Partners GP LLC:
I. Jon Brumley, Jon S. Brumley, Arnold L.
Chavkin, John E. Jackson, J. Luther King, Jr.,
Clayton E. Melton, and George W. Passela
ENCORE ENERGY PARTNERS LP
Summary Compensation Table
The following table summarizes the total compensation awarded to, earned by, or paid to our named executive officers for the periods indicated:
(a)
Reflects the compensation cost recognized by us for the grant of management incentive units in 2007. Pursuant to SEC rules, the amounts shown exclude the impact of estimated forfeitures related to service-based vesting conditions. These amounts reflect our recognized compensation expense for these awards and do not correspond to the actual value that may be realized by the named executive officers. For information on the assumptions in the valuation of the management incentive units, please read Note 10 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”
Grants of Plan-Based Awards for 2008
Our general partner’s named executive officers did not receive any grants of plan-based awards with respect to performance in 2008.
Outstanding Equity Awards at December 31, 2008
At December 31, 2008, none of the named executive officers of our general partner held any outstanding equity awards in us. All previously issued management incentive units were converted into our common units on November 21, 2008 and December 31, 2008.
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Units Vested
The following table summarizes the vesting of management incentive units during 2008 for each of the named executive officers of our general partner:
(a)
Represents the number of management incentive units held by the executive officers of our general partner that vested during 2008.
(b)
Represents the product of the closing price of a common unit of ENP on the vesting date of the management incentive units multiplied by the number of common unit equivalents that the management incentive units represented as of the vesting date.
Pension Benefits
We do not maintain any plans that provide for payments or other benefits at, following, or in connection with retirement.
Non-Qualified Deferred Compensation
We do not maintain any defined contribution or other plan that provides for the deferral of compensation on a basis that is not tax-qualified under the Code.
Potential Payments Upon Termination or Change-in-Control
None of our named executive officers were entitled to potential payments from us upon termination or a change-in-control as of December 31, 2008.
Compensation Committee Interlocks and Insider Participation
As previously discussed, our general partner’s board of directors is not required to maintain, and does not maintain, a compensation committee. I. Jon Brumley, our general partner’s chairman of the board of directors, serves as the chairman of the board of directors of EAC, and Jon S. Brumley, our general partner’s Chief Executive Officer and President and member of our general partner’s board of directors, serves as the Chief Executive Officer and President and member of the board of directors of EAC. However, all compensation decisions with respect to each of these persons are made by EAC and, other than with respect to the previously issued management incentive units, none of these individuals receive any compensation directly from us or our general partner. Please read “Certain Relationships and Related Transactions, and Director Independence” below for information about relationships among us, our general partner and EAC.
ENCORE ENERGY PARTNERS LP
Compensation of Directors
Officers or employees of our general partner or its affiliates who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director is fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.
The following table sets forth a summary of the compensation paid to or earned by non-employee directors of our general partner during 2008:
(a)
Directors receive an annual retainer of $50,000 plus additional fees of $2,000 for attendance at each board meeting and $1,000 for attendance at each committee meeting. The chair of each committee receives an additional annual fee of $10,000. Includes cash paid on distribution equivalent rights that accompany phantom units awarded to non-employee directors of our general partner. Each member of the conflicts committee receives a fee of $25,000 each time we seek special approval under our partnership agreement of a potential conflict of interest in connection with a drop-down transaction between us and EAC.
(b)
Directors receive an annual grant of 5,000 phantom units under the Encore Energy Partners GP LLC Long-Term Incentive Plan. The value of the phantom unit grant is based on the closing price of our common units on the date of grant. Phantom units vest in four equal annual installments, subject to earlier vesting in the event of a change in control, death, or disability and to such other terms as are set forth in the award agreement. Each phantom unit is accompanied by a distribution equivalent right, which entitles the holder to receive cash equal to the amount of any cash distributions made by us with respect to a common unit during the period the right is outstanding.
(c)
Represents quarterly cash distributions paid to directors as holders of phantom units.
(d)
We also reimburse directors for out-of-pocket expenses attendant to membership on the board of directors of our general partner. These amounts are excluded from the above table.
Long-Term Incentive Plan
In September 2007, the board of directors of our general partner approved the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “LTIP”), which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. All employees, consultants, and directors of EAC, our general partner, and any of their subsidiaries and affiliates who perform services for us and our subsidiaries and affiliates are eligible to be granted awards under the LTIP. The total number of common units reserved for issuance pursuant to the LTIP is 1,150,000. The LTIP is administered by the board of directors of our general partner or a committee thereof, referred to as the plan administrator.
The plan administrator may terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend the LTIP or any part of the LTIP from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The LTIP will expire on the earliest of (1) the date the units are no
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longer available under the LTIP for grants, (2) termination of the LTIP by the plan administrator, or (3) the date 10 years following the date of adoption.
Restricted Units. A restricted unit is a common unit that vests over a six-month period of time and during that time is subject to forfeiture. The plan administrator may make grants of restricted units containing such terms as it shall determine, including the period over which restricted units will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives. Restricted units will be entitled to receive quarterly distributions during the vesting period.
Phantom Units. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the plan administrator, cash equivalent to the value of a common unit. The plan administrator may make grants of phantom units under the plan containing such terms as the plan administrator shall determine, including the period over which phantom units granted will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial objectives.
Unit Options. The LTIP permits the grant of options covering common units. The plan administrator may make grants containing such terms as the plan administrator shall determine. Unit options must have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit options granted will become exercisable over a period determined by the plan administrator.
Unit Appreciation Rights. The LTIP permits the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a common unit on the exercise date over the exercise price established for the unit appreciation right. Such excess will be paid in cash or common units. The plan administrator may make grants of unit appreciation rights containing such terms as the plan administrator shall determine. Unit appreciation rights must have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit appreciation rights granted will become exercisable over a period determined by the plan administrator.
Distribution Equivalent Rights. The plan administrator may, in its discretion, grant distribution equivalent rights (“DERs”) as a stand-alone award or with respect to phantom unit awards or other awards under the LTIP. DERs entitle the participant to receive cash or additional awards equal to the amount of any cash distributions made by us with respect to a common unit during the period the right is outstanding. Payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the plan administrator.
Other Unit-Based Awards. The LTIP permits the grant of other unit-based awards, which are awards that are based, in whole or in part, on the value or performance of a common unit. Upon vesting, the award may be paid in common units, cash, or a combination thereof, as provided in the grant agreement.
Unit Awards. The LTIP permits the grant of common units that are not subject to vesting restrictions. Unit awards may be in lieu of or in addition to other compensation payable to the individual.
Change in Control; Termination of Service. Awards under the LTIP will vest and/or become exercisable, as applicable, upon a “change in control” of us or our general partner or upon a “Change of Control” as defined in EAC’s 2000 Incentive Stock Plan, unless provided otherwise by the plan administrator. The consequences of the termination of a grantee’s employment, consulting arrangement, or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement.
A “change in control” of us or our general partner under the LTIP includes the occurrence of one or more of the following events:
•
any person or group, other than EAC or its affiliates, becomes the beneficial owner of 50 percent or more of us or our general partner;
ENCORE ENERGY PARTNERS LP
•
approval by our limited partners of the complete liquidation of us;
•
the sale or other disposition of all or substantially all of our assets, other than to our general partner or its affiliates;
•
a transaction resulting in someone other than our general partner or one of its affiliates becoming our general partner; or
•
a transaction resulting in our general partner ceasing to be an affiliate of EAC.
A “Change in Control” is defined in EAC’s 2000 Incentive Stock Plan as the occurrence of one or more of the following events:
•
any person or group acquires beneficial ownership of 40 percent or more of EAC, other than through any acquisition (1) directly from EAC, (2) by EAC and its affiliates, (3) by any employee benefit plan sponsored or maintained by EAC or any corporation controlled by EAC, (4) by a corporation pursuant to a permitted transaction described in the third bullet below, or (5) by a person or group that owned on the adoption date of EAC’s 2000 Incentive Stock Plan more than 20 percent of EAC’s outstanding capital stock;
•
EAC’s incumbent board members, as of the effective date of EAC’s 2000 Incentive Stock Plan, cease to constitute at least a majority of EAC’s board of directors, provided that, any subsequent director whose election or nomination was approved by a majority vote of the directors then comprising EAC’s incumbent board members will generally be considered an EAC incumbent board member;
•
approval by EAC’s stockholders of a reorganization, merger, share exchange, or consolidation, unless, in each case following the transaction, (1) all or substantially all of EAC’s beneficial owners immediately prior to such transaction beneficially own more than 60 percent of the corporation resulting from such transaction in substantially the same proportions as their ownership immediately prior to such transaction, (2) no person or group beneficially owns 40 percent or more of the corporation resulting from such transaction except to the extent that such person or group beneficially owned 40 percent or more of EAC prior to the transaction, and (3) at least a majority of the board members of the corporation resulting from such transaction where EAC incumbent board members at the time of the execution of the initial agreement, or of the action of EAC’s board of directors, providing for such transaction; or
•
approval by EAC’s stockholders of a complete liquidation or dissolution of EAC or sale or other disposition of all or substantially all of EAC’s assets, other than to a corporation with respect to which, following such sale or other disposition, (1) more than 60 percent of such corporation is then beneficially owned by all or substantially all of the persons or groups who were the beneficial owners of EAC immediately prior to such sale or other disposition in substantially the same proportion as their ownership immediately prior to such sale or other disposition, (2) less than 40 percent of such corporation is then beneficially owned by any person or group, except to the extent that such person or group owned 40 percent or more of EAC prior to the sale or disposition, and (3) at least a majority of the board members of such corporation were EAC’s incumbent board members at the time of the execution of the initial agreement, or of the action of EAC’s board of directors, providing for such sale or other disposition or were elected, appointed, or nominated by EAC’s board of directors.
Source of Units. Common units to be delivered pursuant to awards under the LTIP may be common units acquired by our general partner in the open market, from any other person, directly from us, or any combination of the foregoing. If we issue new common units upon the grant, vesting or payment of awards under the long-term incentive plan, the total number of common units outstanding will increase.
ENCORE ENERGY PARTNERS LP
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
The following table sets forth the beneficial ownership of our units as of February 18, 2009 by:
•
each person known by us to beneficially own 5 percent or more of our outstanding units;
•
each member of the board of directors of our general partner;
•
each named executive officer of our general partner; and
•
all directors and executive officers of our general partner as a group.
Unless otherwise noted, the persons named below have sole voting power and investment power with respect to such units.
*
Less than 1%
(a)
EAC is the ultimate parent company of Encore Energy Partners LP Holdings LLC and Encore Operating, L.P. and therefore, may be deemed to beneficially own the units held by Encore Partners LP Holdings LLC and Encore Operating, L.P.
(b)
Mr. Brumley is the sole officer, director, and shareholder of a corporation that is the sole general partner of a limited partnership that owns the common units. Accordingly, Mr. Brumley has sole voting and dispositive power with respect to the common units owned by the partnership.
(c)
Includes 60,500 common units held by clients of Luther King Capital Management Corporation (“LKCM”), a registered investment advisory firm controlled by Mr. King. Pursuant to investment management agreements with such clients, LKCM generally has voting and investment power over such common units. Mr. King disclaims beneficial ownership of such common units, except to the extent of his pecuniary interest therein.
ENCORE ENERGY PARTNERS LP
The following table sets forth, as of February 18, 2009, the number of shares of common stock of EAC owned by each of the named executive officers and directors of our general partner and all executive officers and directors of our general partner as a group.
*
Less than 1%
(a)
Includes options that are or become exercisable within 60 days of February 18, 2009 as follows: Mr. I. Jon Brumley (328,362), Mr. Jon S. Brumley (343,623), Mr. Reeves (90,978), Mr. Nivens (16,412), and Mr. Arms (53,169), and all executive officers and directors as a group (994,102) upon the exercise of stock options granted pursuant to EAC’s incentive stock plans. Includes unvested restricted stock as of February 18, 2009 as follows: Mr. I. Jon Brumley (96,833), Mr. Jon S. Brumley (90,042), Mr. Reeves (35,986), Mr. Nivens (32,109), and Mr. Arms (28,903), and all directors and executive officers as a group (354,102).
(b)
Mr. Brumley is the sole officer, director, and shareholder of a corporation that is the sole general partner of two limited partnerships that own a total of 1,945,013 shares. Accordingly, Mr. Brumley has sole voting and dispositive power with respect to the shares owned by these partnerships.
(c)
Represents shares of EAC held by clients of LKCM. Pursuant to investment management agreements with such clients, LKCM generally has voting and investment power over such shares. Mr. King disclaims beneficial ownership of such shares, except to the extent of his pecuniary interest therein.
The following table sets forth information about our common units that may be issued under equity compensation plans as of December 31, 2008:
ENCORE ENERGY PARTNERS LP
(1)
There are no outstanding warrants or equity rights awarded under our equity compensation plan.
For discussion of our unit-based compensation plans, please read “Item 11. Executive Compensation.”
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
As of February 18, 2009, affiliates of our general partner, including directors and executive officers of our general partner, owned 22,997,156 common units representing approximately 70 percent of our outstanding common units. In addition, our general partner owned all 504,851 general partner units representing a 1.5 percent general partner interest in us.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the ongoing operation and upon liquidation of ENP. These distributions and payments were determined by and among affiliated entities.
Ongoing Operations of ENP
Distributions of available cash to our
general partner and its affiliates
We make cash distributions to our unitholders, including our general partner and its affiliates, as the holders of 20,924,055 common units and all 504,851 general partner units, in accordance with their ownership percentages.
Payments to our general partner and its affiliates
Our partnership agreement requires us to reimburse our general partner for all actual direct and indirect expenses it incurs or actual payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. We do not expect to incur any additional fees or to make other payments to our general partner in connection with operating our business. Our administrative services agreement requires us to pay Encore Operating an administrative fee of $1.88 per BOE of our production for administrative services performed by us and reimburse Encore Operating for actual third-party expenses incurred on our behalf. For further information regarding the administrative services agreement, please read “Administrative Services Agreement” below.
Withdrawal or removal of our general partner
If our general partner withdraws or is removed, its general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Upon Liquidation of ENP
Liquidation
Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.
Purchase and Investment Agreement
On December 27, 2007, we entered into a purchase and investment agreement with Encore Operating, pursuant to which we acquired certain oil and natural gas producing properties and related assets in the
ENCORE ENERGY PARTNERS LP
Permian and Williston Basins. The transaction closed on February 7, 2008 and was effective January 1, 2008. The consideration for the acquisition consisted of $125.3 million in cash and 6,884,776 common units representing limited partner interests in us. In determining the total purchase price, the common units were valued at $125 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s historical carrying value of the properties. We financed the cash portion of the purchase price through borrowings under our revolving credit facility.
Purchase and Sale Agreement
On December 5, 2008, we entered into a purchase and sale agreement, with Encore Operating, pursuant to which we acquired certain oil and natural gas producing properties and related assets in the Arkoma Basin and royalty interest properties in Oklahoma as well as 10,300 unleased mineral acres. The transaction closed on January 2, 2009. The purchase price was $49 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3 million), which we financed through borrowings under our revolving credit facility.
The acquisition will be accounted for as a transaction between entities under common control. Therefore, the assets will be recorded on our balance sheet at EAC’s historical basis, and our historical results of operations will be restated to reflect the historical operating results of the combined entities.
Administrative Services Agreement
We nor our general partner have any employees. The employees supporting our operations are employees of EAC. At the closing of our IPO, we entered into the administrative services agreement with our general partner, OLLC, Encore Operating, and EAC pursuant to which Encore Operating performs administrative services for us, such as accounting, corporate development, finance, land, legal, and engineering. In addition, Encore Operating provides all personnel and any facilities, goods, and equipment necessary to perform these services and not otherwise provided by us. Encore Operating initially received an administrative fee of $1.75 per BOE of our production for such services. Effective April 1, 2008, the administrative fee increased to $1.88 per BOE of our production as a result of the COPAS Wage Index Adjustment. Encore Operating also charges us for reimbursement of actual third-party expenses incurred on our behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on our behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator of a well. Encore Operating is not liable to us for its performance of, or failure to perform, services under the administrative services agreement unless its acts or omissions constitute gross negligence or willful misconduct.
We also reimburse EAC for any additional state income, franchise, or similar tax incurred by EAC resulting from the inclusion of us and our subsidiaries in consolidated tax returns with EAC and its subsidiaries as required by applicable law. The amount of any such reimbursement is limited to the tax that we and our subsidiaries would have incurred had we not been included in a combined group with EAC.
The administrative fee will increase in the following circumstances:
•
beginning on the first day of April in each year by an amount equal to the product of the then-current administrative fee multiplied by the COPAS Wage Index Adjustment for that year;
•
if we or one of our subsidiaries acquires any additional assets, Encore Operating may propose an increase in its administrative fee that covers the provision of services for such additional assets; however, such proposal must be approved by our general partner upon the recommendation of the conflicts committee of the general partner; or
•
otherwise as agreed upon by Encore Operating and our general partner, with the approval of the conflicts committee of our general partner.
ENCORE ENERGY PARTNERS LP
The administrative services agreement will terminate in the following circumstances:
•
at our discretion upon 90 days notice to Encore Operating;
•
at the discretion of Encore Operating upon 90 days notice to us;
•
upon a change in control of our general partner or Encore Operating by EAC or upon Encore Operating’s failure to pay an employee within 30 days of the date such employee’s payment is due, subject to certain limitations; or
•
upon the bankruptcy, dissolution, liquidation, or winding up of Encore Operating.
Policies and Procedures for Approval of Related Person Transactions
In February 2008, the board of directors of our general partner adopted a policy with respect to related person transactions to document procedures pursuant to which such transactions are reviewed, approved, or ratified. The policy applies to any transaction in which (1) we are a participant, (2) any related person has a direct or indirect material interest, and (3) the amount involved exceeds $120,000, but excludes any transaction that does not require disclosure under Item 404(a) of Regulation S-K.
Director Independence
All members of the board of directors of our general partner, other than Mr. I. Jon Brumley, Mr. Jon S. Brumley, and Mr. John E. Jackson, are independent as defined under the independence standards established by the NYSE. The NYSE 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 ACCOUNTANT FEES AND SERVICES
The audit committee of the board of directors of our general partner selected Ernst & Young LLP as our independent registered public accounting firm to audit our consolidated financial statements for 2009.
Fees Incurred by Us for Services Provided by Ernst & Young LLP
The following table shows the fees paid or accrued by us for the audit and other services provided by Ernst & Young LLP during the periods indicated:
(a)
Audit fees represent fees for professional services provided in connection with the annual audit of our consolidated financial statements, review of our quarterly consolidated financial statements, and audit services provided in connection with filings with the SEC, including comfort letters, consents, and comment letters.
Audit Committee’s Pre-Approval Policy and Procedures
The audit committee’s policy is to pre-approve all audit and permissible non-audit services provided by the independent registered public accounting firm. These services may include audit services, audit-related services, tax services, and other services. Pre-approval is detailed as to the specific service or category of service and is subject to a specific approval. The audit committee requires our independent registered public
ENCORE ENERGY PARTNERS LP
accounting firm and management to report on the actual fees charged for each category of service at audit committee meetings throughout the year.
During the year, circumstances may arise when it may become necessary to engage our independent registered public accounting firm for additional services not contemplated in the original pre-approval. In those circumstances, the audit committee of our general partner requires specific pre-approval before engaging our independent registered public accounting firm. The audit committee of our general partner has delegated pre-approval authority to its chairman for those instances when pre-approval is needed prior to a scheduled meeting. The chairman of the audit committee of our general partner must report on such approval at the next scheduled meeting.
All 2008 and 2007 services provided by our independent registered public accounting firm were pre-approved.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as a part of this Report:
1. Financial Statements:
2. Financial Statement Schedules:
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated financial statements and related notes.
(b) Exhibits
ENCORE ENERGY PARTNERS LP
*
Filed herewith
+
Management contract or compensatory plan, contract, or arrangement.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ENCORE ENERGY PARTNERS LP
By: Encore Energy Partners GP LLC, its General Partner
Date: February 24, 2009
By: /s/ Jon S. Brumley
Jon S. Brumley
Chief Executive Officer and President
KNOW ALL MEN BY THESE PRESENTS, that each individual whose signature appears below constitutes and appoints Jon S. Brumley and Robert C. Reeves, and each of them, his true and lawful attorneys-in-fact and agents with full power of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this report, and to file the same, with all exhibits thereto, and all documents in connection therewith, with the SEC, granting unto said attorneys-in-fact and agents, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or his or their substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.