UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2009
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or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission File Number: 001-33676
ENCORE ENERGY PARTNERS
LP
(Exact name of registrant as
specified in its charter)
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Delaware
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20-8456807
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(State or other jurisdiction
of incorporation or organization)
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(I.R.S. Employer
Identification No.)
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777 Main Street, Suite 1400, Fort Worth, Texas
(Address of principal
executive offices)
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76102
(Zip Code)
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Registrants telephone number, including area code:
(817)
877-9955
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Units Representing Limited Partner Interests
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act: None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such
files). Yes o No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act.
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Large accelerated
filer o
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Accelerated
filer þ
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Non-accelerated
filer o
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Smaller reporting
company o
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(Do not check if a smaller
reporting company)
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes o No þ
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Aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the price
at which the common equity of the registrant was last sold as of
June 30, 2009 (the last business day of the
registrants most
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recently completed second fiscal quarter)
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$
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317,874,042
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Number of Common Units outstanding as of February 17, 2010
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45,285,347
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DOCUMENTS INCORPORATED BY REFERENCE:
None
ENCORE
ENERGY PARTNERS LP
INDEX
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ENCORE
ENERGY PARTNERS LP
GLOSSARY
The following are abbreviations and definitions of certain terms
used in this annual report on
Form 10-K
(the Report). The definitions of proved developed
reserves, proved reserves, and proved undeveloped reserves have
been abbreviated from the applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
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ASC. FASB Accounting Standards Codification.
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Bbl. One stock tank barrel, or 42
U.S. gallons liquid volume, used in reference to oil or
other liquid hydrocarbons.
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Bbl/D. One Bbl per day.
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Bcf. One billion cubic feet, used in reference
to natural gas.
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Bcfe. One billion cubic feet of natural gas
equivalent, calculated by converting oil to natural gas at a
ratio of one Bbl of oil to six Mcf of natural gas.
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BOE. One barrel of oil equivalent, calculated
by converting natural gas to oil equivalent barrels at a ratio
of six Mcf of natural gas to one Bbl of oil.
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BOE/D. One BOE per day.
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Completion. The installation of permanent
equipment for the production of oil or natural gas.
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Council of Petroleum Accountants Societies
(COPAS). A professional organization
of oil and natural gas accountants that maintains consistency in
accounting procedures and interpretations, including the
procedures that are part of most joint operating agreements.
These procedures establish a drilling rate and an overhead rate
to reimburse the operator of a well for overhead costs, such as
accounting and engineering.
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Delay Rentals. Fees paid to the lessor of an
oil and natural gas lease during the primary term of the lease
prior to the commencement of production from a well.
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Developed Acreage. The number of acres
allocated or assignable to producing wells or wells capable of
production.
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Development Well. A well drilled within the
proved area of an oil or natural gas reservoir to the depth of a
stratigraphic horizon known to be productive.
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Dry Hole. An exploratory, development, or
extension well that proves to be incapable of producing either
oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.
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EAC. Encore Acquisition Company, a publicly
traded Delaware corporation, together with its subsidiaries.
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ENP. Encore Energy Partners LP, a publicly
traded Delaware limited partnership, together with its
subsidiaries.
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Exploratory Well. A well drilled to find a new
field or to find a new reservoir in a field previously producing
oil or natural gas in another reservoir.
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Farm-out. Transfer of all or part of the
operating rights from the working interest holder to an
assignee, who assumes all or some of the burden of development,
in return for an interest in the property. The assignor usually
retains an overriding royalty, but may retain any type of
interest.
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FASB. Financial Accounting Standards Board.
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Field. An area consisting of a single
reservoir or multiple reservoirs, all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition.
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ENCORE
ENERGY PARTNERS LP
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GAAP. Accounting principles generally accepted
in the United States.
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Gross Acres or Gross Wells. The total acres or
wells, as the case may be, in which an entity owns a working
interest.
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Lease Operating Expense (LOE). All
direct and allocated indirect costs of producing hydrocarbons
after completion of drilling and before commencement of
production. Such costs include labor, superintendence, supplies,
repairs, maintenance, and direct overhead charges.
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LIBOR. London Interbank Offered Rate.
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MBbl. One thousand Bbls.
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MBOE. One thousand BOE.
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Mcf. One thousand cubic feet, used in
reference to natural gas.
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Mcf/D. One Mcf per day.
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MMBbl. One million Bbls.
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MMBOE. One million BOE.
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MMcf. One million cubic feet, used in
reference to natural gas.
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MMcf/D. One MMcf per day.
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MMcfe. One MMcf equivalent, determined by
converting oil to natural gas equivalent at a ratio of one Bbl
of oil to six Mcf of natural gas.
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MMcfe/D. One MMcfe per day.
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Natural Gas Liquids (NGLs). The
combination of ethane, propane, butane, and natural gasolines
that when removed from natural gas become liquid under various
levels of higher pressure and lower temperature.
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Net Acres or Net Wells. Gross acres or wells,
as the case may be, multiplied by the working interest
percentage owned by an entity.
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Net Profits Interest. An interest that
entitles the owner to a specified share of net profits from the
production of hydrocarbons.
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NYMEX. New York Mercantile Exchange.
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NYSE. The New York Stock Exchange.
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Oil. Crude oil, condensate, and NGLs.
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Operator. The entity responsible for the
exploration, development, and production of a well or lease.
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Present Value of Future Net Revenues
(PV-10). The
present value of estimated future revenues to be generated from
the production of proved reserves, net of estimated future
production and development costs, using prices and costs as of
the date of estimation without future escalation, without giving
effect to commodity derivative activities, non-property related
expenses such as general and administrative expenses, debt
service, depletion, depreciation, and amortization, and income
taxes, discounted at an annual rate of 10 percent.
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Production Margin. Wellhead revenues less
production expenses.
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Production Taxes. Production expense
attributable to production, ad valorem, and severance taxes.
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ENCORE
ENERGY PARTNERS LP
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Productive Well. A well capable of producing
hydrocarbons in commercial quantities, including natural gas
wells awaiting pipeline connections to commence deliveries and
oil wells awaiting connection to production facilities.
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Proved Developed Reserves. Proved reserves
that can be expected to be recovered from existing wells with
existing equipment and operating methods or in which the cost of
the required equipment is relatively minor compared to the cost
of a new well.
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Proved Reserves. The estimated quantities of
hydrocarbons, which, by analysis of geoscience and engineering
data, can be estimated with reasonable certainty to be
economically producible from a given date forward from known
reservoirs under existing conditions and operating methods.
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Proved Undeveloped Reserves. Proved reserves
that are expected to be recovered from new wells on undrilled
acreage for which the existence and recoverability of such
reserves can be estimated with reasonable certainty, or from
existing wells where a relatively major expenditure is required
for recompletion. Includes unrealized production response from
enhanced recovery techniques that have been proved effective by
actual projects in the same reservoir or an analogous reservoir,
or by other evidence using reliable technology establishing
reasonable certainty.
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Recompletion. The completion for production of
an existing wellbore in another formation from that in which the
well has been previously completed.
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Reliable Technology. A grouping of one or more
technologies (including computational methods) that have been
field tested and have been demonstrated to provide reasonably
certain results with consistency and repeatability in the
formation being evaluated or in an analogous formation.
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Reserves. Reserves are estimated remaining
quantities of oil and natural gas and related substances
anticipated to the economically producible, as of a given date,
by application of development projects to known accumulations.
In addition, there must exist, or there must be a reasonable
expectation that there will exist, the legal right to produce or
a revenue interest in the production, installed means of
delivering oil and gas or related substances to market, and all
permits and financing required to implement the project.
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Reservoir. A porous and permeable underground
formation containing a natural accumulation of producible
hydrocarbons that is confined by impermeable rock or water
barriers and is individual and separate from other reservoirs.
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Royalty. An interest in an oil and natural gas
lease that gives the owner the right to receive a portion of the
production from the leased acreage (or of the proceeds from the
sale thereof), but does not require the owner to pay any portion
of the production or development costs on the leased acreage.
Royalties may be either landowners royalties, which are
reserved by the owner of the leased acreage at the time the
lease is granted, or overriding royalties, which are usually
reserved by an owner of the leasehold in connection with a
transfer to a subsequent owner.
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SEC. The United States Securities and Exchange
Commission.
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Secondary Recovery. Enhanced recovery of
hydrocarbons from a reservoir beyond the hydrocarbons that can
be recovered by normal flowing and pumping operations. Involves
maintaining or enhancing reservoir pressure by injecting water,
gas, or other substances into the formation in order to displace
hydrocarbons toward the wellbore. The most common secondary
recovery techniques are gas injection and waterflooding.
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SFAS. Statement of Financial Accounting
Standards.
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Standardized Measure. Future cash inflows from
proved reserves, less future production costs, development
costs, net abandonment costs, and income taxes, discounted at
10 percent per annum to
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ENCORE
ENERGY PARTNERS LP
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reflect the timing of future net cash flows. Standardized
Measure differs from
PV-10
because Standardized Measure includes the effect of estimated
future net abandonment costs and income taxes.
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Tertiary Recovery. An enhanced recovery
operation that normally occurs after waterflooding in which
chemicals or natural gases are used as the injectant.
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Undeveloped Acreage. Lease acreage on which
wells have not been drilled or completed to a point that would
permit the production of economic quantities of oil or natural
gas regardless of whether such acreage contains proved reserves.
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Unit. A specifically defined area within which
acreage is treated as a single consolidated lease for operations
and for allocations of costs and benefits without regard to
ownership of the acreage. Units are established for the purpose
of recovering hydrocarbons from specified zones or formations.
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Waterflood. A secondary recovery operation in
which water is injected into the producing formation in order to
maintain reservoir pressure and force oil toward and into the
producing wells.
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Working Interest. An interest in an oil or
natural gas lease that gives the owner the right to drill for
and produce hydrocarbons on the leased acreage and requires the
owner to pay a share of the production and development costs.
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Workover. Operations on a producing well to
restore or increase production.
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v
ENCORE
ENERGY PARTNERS LP
As used in this Report, references to ENP,
we, our, us, or similar
terms refer to Encore Energy Partners LP and its subsidiaries,
unless the context indicates otherwise. References to our
general partner refer to Encore Energy Partners GP LLC,
our general partner. References to our operating
company refer to Encore Energy Partners Operating LLC, our
operating company. References to EAC refer to Encore
Acquisition Company, the ultimate parent company of our general
partner, and its subsidiaries. References to Encore
Operating refer to Encore Operating, L.P., a wholly owned
subsidiary of EAC. This Report contains forward-looking
statements, which give our current expectations or forecasts of
future events. Please read Item 1A. Risk
Factors for a description of various factors that could
materially affect our ability to achieve the anticipated results
described in the forward-looking statements. Certain terms
commonly used in the oil and natural gas industry and in this
Report are defined under the caption Glossary. In
addition, all production and reserve volumes disclosed in this
Report represent amounts net to us, unless otherwise noted.
PART I
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ITEMS 1
and 2.
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BUSINESS
AND PROPERTIES
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General
Our Business. We are a Delaware limited
partnership formed 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. Our properties and oil and natural gas reserves
are located in four core areas:
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the Big Horn Basin in Wyoming and Montana;
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the Permian Basin in West Texas and New Mexico;
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the Williston Basin in North Dakota and Montana; and
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the Arkoma Basin in Arkansas and Oklahoma.
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EACs Merger with Denbury. On
October 31, 2009, EAC, the ultimate parent of our general
partner, entered into an Agreement and Plan of Merger (the
Merger Agreement) with Denbury Resources Inc.
(Denbury) pursuant to which EAC has agreed to merge
with and into Denbury, with Denbury as the surviving entity (the
Merger). The Merger Agreement, which was unanimously
approved by EACs Board of Directors and by Denburys
Board of Directors, provides for Denburys acquisition of
all of the issued and outstanding shares of EAC common stock.
EAC expects to complete the Merger during the first quarter of
2010, although completion by any particular date cannot be
assured.
Proved Reserves. Our estimated total proved
reserves at December 31, 2009 were 28.9 MMBbls of oil
and 84.7 Bcf of natural gas, based on 2009 average market
prices of $61.18 per Bbl of oil and $3.83 per Mcf of natural
gas. On a BOE basis, our proved reserves were 43.0 MMBOE at
December 31, 2009, of which 67 percent was oil,
92 percent was proved developed, and 8 percent was
proved undeveloped.
Drilling. In 2009, we participated in drilling
15 gross (1.8 net) non-operated productive wells. In 2009,
we drilled one gross (1.0 net) dry hole. We invested
$8.4 million in development, exploitation, and exploration
activities in 2009.
Financial Information About Operating
Segments. We have operations in only one industry
segment: the oil and natural gas exploration and production
industry in the United States.
Our
Relationship with Encore Acquisition Company
One of our principal attributes is our relationship with EAC.
EAC is engaged in the acquisition and development of oil and
natural gas reserves from onshore fields in the United States.
Since 1998, EAC has
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ENCORE
ENERGY PARTNERS LP
acquired producing properties with proven reserves and leasehold
acreage and grown the production and proven reserves by
drilling, exploring, reengineering or expanding existing
waterflood projects, and applying tertiary recovery techniques.
EACs fields are further characterized by large
accumulations of original oil in place. Original oil in place is
not an indication of how much oil is likely to be produced, but
it is an indication of the estimated size of a reservoir. We
believe that many of EACs oil and natural gas properties
are, or after additional capital is invested may become, well
suited for our partnership.
EAC constantly evaluates acquisitions and dispositions and may
elect to acquire or dispose of oil and natural gas properties in
the future without offering us the opportunity to purchase those
assets. EAC has retained such flexibility because it believes it
is in the best interests of its shareholders to do so. We cannot
say with any certainty which, if any, opportunities to acquire
assets from EAC may be made available to us or if we will choose
to pursue any such opportunity. Moreover, EAC is not prohibited
from competing with us and constantly evaluates acquisitions and
dispositions that do not involve us.
In February 2008, we acquired certain oil and natural gas
properties and related assets in the Permian Basin in West Texas
and in the Williston Basin in North Dakota (the Permian
and Williston Basin Assets) from Encore Operating for
approximately $125.0 million in cash and the issuance of
6,884,776 ENP common units to Encore Operating. In determining
the total purchase price, the common units were valued at
$125.0 million. However, no accounting value was ascribed
to the common units as the cash consideration exceeded Encore
Operatings carrying value of the properties. In January
2009, we acquired certain oil and natural gas properties and
related assets in the Arkoma Basin in Arkansas and royalty
interest properties primarily in Oklahoma, as well as 10,300
unleased mineral acres (the Arkoma Basin Assets),
from Encore Operating for approximately $46.4 million in
cash. In June 2009, we acquired certain oil and natural gas
properties and related assets in the Williston Basin in North
Dakota and Montana (the Williston Basin Assets) from
Encore Operating for approximately $25.2 million in cash.
In August 2009, we acquired certain oil and natural gas
properties and related assets in the Big Horn Basin in Wyoming,
the Permian Basin in West Texas and New Mexico, and the
Williston Basin in Montana and North Dakota (the Rockies
and Permian Basin Assets) from Encore Operating for
approximately $179.6 million in cash. Because these assets
were acquired from an affiliate, the acquisitions were accounted
for as transactions between entities under common control,
similar to a pooling of interests, whereby the assets and
liabilities of the acquired properties were recorded at Encore
Operatings carrying value and our historical financial
information was recast to include the acquired properties for
all periods in which the properties were owned by Encore
Operating. Accordingly, the information contained in this Report
reflects our historical results combined with those of the
Permian and Williston Basin Assets, the Arkoma Basin Assets, the
Williston Basin Assets, and the Rockies and Permian Basin Assets.
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ENCORE
ENERGY PARTNERS LP
Organizational
Structure
The following diagram depicts our organizational structure as of
February 17, 2010:
Operations
Well
Operations
In general, we seek to be the operator of wells in which we have
a working interest. As operator, we design and manage the
development of a well and supervise operation and maintenance
activities on a
day-to-day
basis. We do not own drilling rigs or other oilfield service
equipment used for drilling or maintaining wells on properties
we operate. Independent contractors engaged by us provide all
the equipment and personnel associated with these activities.
As of December 31, 2009, we operated properties
representing approximately 85 percent of our proved
reserves. As the operator, we are able to better control
expenses, capital allocation, and the timing of exploitation and
development activities on our properties. We also own working
interests in properties that are operated by third parties for
which we are required to pay our share of production,
exploitation, and development costs. Please read
Properties Nature of Our Ownership
Interests. During 2009, 2008, and 2007, our development
costs on non-operated properties were approximately
66 percent, 24 percent, and 28 percent,
respectively, of our total development costs. We also own
royalty interests in wells operated by third parties that are
not burdened by production or capital costs; however, we have
little or no control over the implementation of projects on
these properties.
We do not have any employees. Encore Operating provides
administrative services for us, such as accounting, corporate
development, finance, land, legal, and engineering pursuant to
an administrative services agreement. In addition, Encore
Operating provides all personnel, facilities, goods, and
equipment necessary to perform these services which are not
otherwise provided by us. Encore Operating is not liable to us
for its
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ENCORE
ENERGY PARTNERS LP
performance of, or failure to perform, services under the
administrative services agreement unless its acts or omissions
constitute gross negligence or willful misconduct.
Encore Operating initially received an administrative fee of
$1.75 per BOE of our production for such services. From
April 1, 2008 to March 31, 2009, the administrative
fee was $1.88 per BOE of our production. Effective April 1,
2009, the administrative fee increased to $2.02 per BOE of our
production. ENP also reimburses Encore Operating for 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.
The administrative fee will increase in the following
circumstances:
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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;
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if we acquire 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 the board of directors of our
general partner upon the recommendation of its conflicts
committee; and
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otherwise as agreed upon by Encore Operating and our general
partner, with the approval of the conflicts committee of the
board of directors of our general partner.
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Natural
Gas Gathering
We own and operate a network of natural gas gathering systems in
our Big Horn Basin area of operation. These systems gather and
transport our natural gas and a small amount of third-party
natural gas to larger gathering systems and intrastate,
interstate, and local distribution pipelines. Our network of
natural gas gathering systems permits us to transport production
from our wells with fewer interruptions and also minimizes any
delays associated with a gathering company extending its lines
to our wells. Our ownership and control of these lines enables
us to:
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realize faster connection of newly drilled wells to the existing
system;
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control pipeline operating pressures and capacity to maximize
our production;
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control compression costs and fuel use;
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maintain system integrity;
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control the monthly nominations on the receiving pipelines to
prevent imbalances and penalties; and
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track sales volumes and receipts closely to assure all
production values are realized.
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Our gas gathering systems are operated for us by Encore
Operating pursuant to the administrative services agreement.
Seasonal
Nature of Business
Oil and natural gas producing operations are generally not
seasonal. However, demand for some of our products can fluctuate
season to season, which impacts price. In particular, heavy oil
is typically in higher demand in the summer for its use in road
construction, and natural gas is generally in higher demand in
the winter for heating.
4
ENCORE
ENERGY PARTNERS LP
Production
and Price History
The following table sets forth information regarding our
production volumes, average realized prices, and average costs
per BOE for the periods indicated:
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Year Ended December 31,
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2009
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2008
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2007
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Total Production Volumes:
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Oil (MBbls)
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2,337
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2,533
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2,232
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Natural gas (MMcf)
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6,097
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6,219
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5,751
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Combined (MBOE)
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3,353
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3,570
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3,190
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Average Daily Production Volumes:
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|
|
Oil (Bbl/D)
|
|
|
6,402
|
|
|
|
6,922
|
|
|
|
6,114
|
|
Natural gas (Mcf/D)
|
|
|
16,703
|
|
|
|
16,991
|
|
|
|
15,756
|
|
Combined (BOE/D)
|
|
|
9,186
|
|
|
|
9,754
|
|
|
|
8,740
|
|
Average Realized Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
54.61
|
|
|
$
|
89.45
|
|
|
$
|
60.74
|
|
Natural gas (per Mcf)
|
|
|
3.68
|
|
|
|
8.67
|
|
|
|
6.80
|
|
Combined (per BOE)
|
|
|
44.75
|
|
|
|
78.59
|
|
|
|
54.75
|
|
Average Costs per BOE:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
12.43
|
|
|
$
|
12.54
|
|
|
$
|
10.65
|
|
Production, ad valorem, and severance taxes
|
|
|
4.80
|
|
|
|
7.88
|
|
|
|
5.55
|
|
Depletion, depreciation, and amortization
|
|
|
16.93
|
|
|
|
16.12
|
|
|
|
14.89
|
|
Exploration
|
|
|
0.93
|
|
|
|
0.05
|
|
|
|
0.04
|
|
Derivative fair value loss (gain)
|
|
|
14.16
|
|
|
|
(27.14
|
)
|
|
|
8.24
|
|
General and administrative
|
|
|
3.39
|
|
|
|
4.65
|
|
|
|
4.78
|
|
Other operating
|
|
|
0.92
|
|
|
|
0.47
|
|
|
|
0.45
|
|
Marketing, net of revenues
|
|
|
(0.05
|
)
|
|
|
0.04
|
|
|
|
(0.60
|
)
|
Productive
Wells
The following table sets forth information relating to the
productive wells in which we owned a working interest as of
December 31, 2009. Wells are classified as oil or natural
gas wells according to their predominant production stream. We
also hold royalty interests in units and acreage beyond the
wells in which we have a working interest.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Wells
|
|
|
Natural Gas Wells
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
Gross
|
|
|
Net
|
|
|
Working
|
|
|
Gross
|
|
|
Net
|
|
|
Working
|
|
|
|
Wells(a)
|
|
|
Wells
|
|
|
Interest
|
|
|
Wells(a)
|
|
|
Wells
|
|
|
Interest
|
|
|
Big Horn Basin
|
|
|
352
|
|
|
|
271.5
|
|
|
|
77
|
%
|
|
|
41
|
|
|
|
29.6
|
|
|
|
72
|
%
|
Williston Basin
|
|
|
100
|
|
|
|
63.9
|
|
|
|
64
|
%
|
|
|
23
|
|
|
|
6.3
|
|
|
|
27
|
%
|
Permian Basin
|
|
|
1,538
|
|
|
|
373.8
|
|
|
|
24
|
%
|
|
|
561
|
|
|
|
273.7
|
|
|
|
49
|
%
|
Arkoma Basin
|
|
|
5
|
|
|
|
0.3
|
|
|
|
6
|
%
|
|
|
123
|
|
|
|
9.1
|
|
|
|
7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,995
|
|
|
|
709.5
|
|
|
|
36
|
%
|
|
|
748
|
|
|
|
318.7
|
|
|
|
43
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Our total wells include 1,099 operated wells and 1,644
non-operated wells. At December 31, 2009, 35 of our wells
had multiple completions. |
5
ENCORE
ENERGY PARTNERS LP
Acreage
The following table sets forth information relating to our
leasehold acreage at December 31, 2009. Developed acreage
is assigned to productive wells. Undeveloped acreage is acreage
held under lease, permit, contract, or option that is not in a
spacing unit for a producing well, including leasehold interests
identified for exploitation or exploratory drilling. As of
December 31, 2009, our undeveloped acreage in the Permian
Bain represented approximately 58 percent of our total net
undeveloped acreage. All of our oil and natural gas leases are
held by production, which means that for as long as our wells
continue to produce oil or natural gas, we will continue to own
the lease.
|
|
|
|
|
|
|
|
|
|
|
Gross Acreage
|
|
|
Net Acreage
|
|
|
Big Horn Basin:
|
|
|
|
|
|
|
|
|
Developed
|
|
|
16,267
|
|
|
|
13,360
|
|
Undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,267
|
|
|
|
13,360
|
|
|
|
|
|
|
|
|
|
|
Williston Basin:
|
|
|
|
|
|
|
|
|
Developed
|
|
|
46,738
|
|
|
|
37,535
|
|
Undeveloped
|
|
|
10,546
|
|
|
|
7,361
|
|
|
|
|
|
|
|
|
|
|
|
|
|
57,284
|
|
|
|
44,896
|
|
|
|
|
|
|
|
|
|
|
Permian Basin:
|
|
|
|
|
|
|
|
|
Developed
|
|
|
59,826
|
|
|
|
34,559
|
|
Undeveloped
|
|
|
8,244
|
|
|
|
10,279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
68,070
|
|
|
|
44,838
|
|
|
|
|
|
|
|
|
|
|
Arkoma Basin:
|
|
|
|
|
|
|
|
|
Developed
|
|
|
3,192
|
|
|
|
357
|
|
Undeveloped
|
|
|
357
|
|
|
|
84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,549
|
|
|
|
441
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
|
|
|
|
|
|
|
Developed
|
|
|
126,023
|
|
|
|
85,811
|
|
Undeveloped
|
|
|
19,147
|
|
|
|
17,724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
145,170
|
|
|
|
103,535
|
|
|
|
|
|
|
|
|
|
|
Development
Results
We concentrate our development activity and production
optimization projects on lower risk, development projects. The
number and types of wells we drill or projects we undertake vary
depending on the amount of funds we have available, the cost of
those activities, the size of the fractional working interest we
acquire in each well, and the estimated recoverable reserves
attributable to each well.
6
ENCORE
ENERGY PARTNERS LP
The following table sets forth information with respect to wells
completed during the periods indicated, regardless of when
development was initiated. This information should not be
considered indicative of future performance, nor should a
correlation be assumed between productive wells drilled,
quantities of reserves discovered, or economic value.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
9
|
|
|
|
1.2
|
|
|
|
49
|
|
|
|
15.3
|
|
|
|
43
|
|
|
|
13.5
|
|
Dry holes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
|
|
1.2
|
|
|
|
49
|
|
|
|
15.3
|
|
|
|
43
|
|
|
|
13.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
6
|
|
|
|
0.6
|
|
|
|
10
|
|
|
|
1.3
|
|
|
|
7
|
|
|
|
3.7
|
|
Dry holes
|
|
|
1
|
|
|
|
1.0
|
|
|
|
1
|
|
|
|
0.0
|
|
|
|
2
|
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
1.6
|
|
|
|
11
|
|
|
|
1.3
|
|
|
|
9
|
|
|
|
4.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
15
|
|
|
|
1.8
|
|
|
|
59
|
|
|
|
16.6
|
|
|
|
50
|
|
|
|
17.2
|
|
Dry holes
|
|
|
1
|
|
|
|
1.0
|
|
|
|
1
|
|
|
|
0.0
|
|
|
|
2
|
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
|
|
|
|
2.8
|
|
|
|
60
|
|
|
|
16.6
|
|
|
|
52
|
|
|
|
18.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present
Activities
As of December 31, 2009, we had two gross (0.1 net)
development wells that had reached total depth and were in the
process of being completed pending first production.
Delivery
Commitments and Marketing Arrangements
Our oil and natural gas production is principally sold to
marketers, processors, refiners, and other purchasers that have
access to nearby pipeline, processing, and gathering facilities.
In areas where there is no practical access to pipelines, oil is
trucked to central storage facilities where it is aggregated and
sold to various markets and downstream purchasers. Our
production sales agreements generally contain customary terms
and conditions for the oil and natural gas industry, provide for
sales based on prevailing market prices in the area, and
generally have terms of one year or less.
Our natural gas production and gathered natural gas from
operated Permian Basin properties is generally sold on the spot
market or under market-sensitive, short-term agreements with
purchasers, including the marketing affiliates of intrastate and
interstate pipelines, independent marketing companies, gas
processing companies, and other purchasers who have the ability
to pay the highest price for the natural gas production and move
the natural gas under the most efficient and effective
transportation agreements. Because all of our natural gas from
operated Permian Basin properties is sold under market-priced
agreements, we are positioned to take advantage of future
increases in natural gas prices, but we are also subject to any
future price declines. We do not market our own natural gas on
our non-operated Permian Basin properties, but receive our share
of revenues from the operator.
The marketing of our Big Horn heavy sour crude oil production is
through our Clearfork pipeline, which transports the crude oil
to local and other refiners through connections to other
interstate pipelines. Our Big Horn sweet crude oil production is
transported from the field by a third party trucking company
that delivers the crude oil to a centralized facility connected
to a common carrier pipeline with delivery points accessible to
local refiners in the Salt Lake City, Utah and Guernsey, Wyoming
market centers. We sell oil production from
7
ENCORE
ENERGY PARTNERS LP
our operated Permian Basin at the wellhead to third party
gathering and marketing companies. Any restrictions on the
available capacity to transport oil through any of the above
mentioned pipelines, or any other pipelines, or any interruption
in refining throughput capacity could have a material adverse
effect on our production volumes and the prices we receive for
our production.
The difference between NYMEX market prices and the price
received at the wellhead for oil and natural gas production is
commonly referred to as a differential. In recent years,
production increases from competing Canadian and Rocky Mountain
producers, in conjunction with limited refining and pipeline
capacity from the Rocky Mountain area, have affected this
differential. We cannot accurately predict future crude oil and
natural gas differentials. Increases in the differential between
the NYMEX price for oil and natural gas and the wellhead price
we receive could have a material adverse effect on our results
of operations, financial position, cash flows, and ability to
make distributions. The following table shows the relationship
between oil and natural gas wellhead prices as a percentage of
average NYMEX prices by quarter for 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
Second Quarter
|
|
|
Third Quarter
|
|
|
Fourth Quarter
|
|
|
|
of 2009
|
|
|
of 2009
|
|
|
of 2009
|
|
|
of 2009
|
|
|
Average oil wellhead to NYMEX percentage
|
|
|
86
|
%
|
|
|
91
|
%
|
|
|
89
|
%
|
|
|
89
|
%
|
Average natural gas wellhead to NYMEX percentage
|
|
|
69
|
%
|
|
|
92
|
%
|
|
|
100
|
%
|
|
|
107
|
%
|
Certain of our natural gas marketing contracts determine the
price that we are paid based on the value of the dry gas sold
plus a portion of the value of liquids extracted. Since title of
the natural gas sold under these contracts passes at the inlet
of the processing plant, we report inlet volumes of natural gas
in Mcf as production resulting in a price we were paid per Mcf
under certain contracts to be higher than the average NYMEX
price.
Principal
Customers
For 2009, our largest purchaser was Marathon Oil Corporation,
which accounted for 43 percent of our total sales of
production. Our marketing of oil and natural gas can be affected
by factors beyond our control, the potential effects of which
cannot be accurately predicted. Management believes that the
loss of any one purchaser would not have a material adverse
effect on our ability to market our oil and natural gas
production.
Competition
The oil and natural gas industry is highly competitive. We
encounter strong competition from other oil companies in
acquiring properties. Many of these competitors have resources
substantially larger than ours. As a result, our competitors may
be able to pay more for desirable leases, or to evaluate, bid
for, and purchase a greater number of properties or prospects
than our resources will permit.
We are also affected by competition for rigs and the
availability of related equipment. The oil and natural gas
industry has experienced shortages of rigs, equipment, pipe, and
personnel, which has delayed development and exploitation
activities and has caused significant price increases. We are
unable to predict when, or if, such shortages may occur or how
they would affect our development and exploitation program.
Competition is also strong for attractive oil and natural gas
producing properties, undeveloped leases, and development
rights, and we may not be able to compete satisfactorily when
attempting to acquire additional properties.
8
ENCORE
ENERGY PARTNERS LP
Properties
Nature
of Our Ownership Interests
The following table sets forth the production, average wellhead
prices, and average LOE per BOE of our properties by principal
area of operation for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Percent
|
|
|
Average Oil
|
|
|
Natural Gas
|
|
|
Lease
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
of Total
|
|
|
Wellhead
|
|
|
Wellhead
|
|
|
Operating
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBOE)
|
|
|
|
|
|
(per Bbl)
|
|
|
(per Mcf)
|
|
|
(per BOE)
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Big Horn Basin
|
|
|
1,422
|
|
|
|
337
|
|
|
|
1,478
|
|
|
|
44
|
%
|
|
$
|
54.33
|
|
|
$
|
0.94
|
|
|
$
|
12.82
|
|
Williston Basin
|
|
|
412
|
|
|
|
291
|
|
|
|
461
|
|
|
|
14
|
%
|
|
|
53.35
|
|
|
|
3.87
|
|
|
|
17.40
|
|
Arkoma Basin
|
|
|
21
|
|
|
|
963
|
|
|
|
182
|
|
|
|
5
|
%
|
|
|
53.33
|
|
|
|
2.83
|
|
|
|
1.10
|
|
Permian Basin
|
|
|
482
|
|
|
|
4,506
|
|
|
|
1,232
|
|
|
|
37
|
%
|
|
|
56.57
|
|
|
|
4.05
|
|
|
|
11.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,337
|
|
|
|
6,097
|
|
|
|
3,353
|
|
|
|
100
|
%
|
|
|
54.61
|
|
|
|
3.68
|
|
|
|
12.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Big Horn Basin
|
|
|
1,517
|
|
|
|
365
|
|
|
|
1,578
|
|
|
|
44
|
%
|
|
|
86.22
|
|
|
|
3.70
|
|
|
|
13.54
|
|
Williston Basin
|
|
|
459
|
|
|
|
345
|
|
|
|
516
|
|
|
|
14
|
%
|
|
|
91.26
|
|
|
|
9.16
|
|
|
|
14.54
|
|
Arkoma Basin
|
|
|
16
|
|
|
|
986
|
|
|
|
181
|
|
|
|
5
|
%
|
|
|
97.65
|
|
|
|
7.53
|
|
|
|
1.15
|
|
Permian Basin
|
|
|
541
|
|
|
|
4,523
|
|
|
|
1,295
|
|
|
|
36
|
%
|
|
|
96.73
|
|
|
|
9.29
|
|
|
|
12.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,533
|
|
|
|
6,219
|
|
|
|
3,570
|
|
|
|
100
|
%
|
|
|
89.45
|
|
|
|
8.67
|
|
|
|
12.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Big Horn Basin
|
|
|
1,287
|
|
|
|
286
|
|
|
|
1,334
|
|
|
|
42
|
%
|
|
|
55.15
|
|
|
|
1.90
|
|
|
|
11.48
|
|
Williston Basin
|
|
|
380
|
|
|
|
305
|
|
|
|
431
|
|
|
|
14
|
%
|
|
|
68.37
|
|
|
|
6.19
|
|
|
|
11.18
|
|
Arkoma Basin
|
|
|
18
|
|
|
|
1,048
|
|
|
|
192
|
|
|
|
6
|
%
|
|
|
67.98
|
|
|
|
6.08
|
|
|
|
0.75
|
|
Permian Basin
|
|
|
547
|
|
|
|
4,112
|
|
|
|
1,233
|
|
|
|
39
|
%
|
|
|
68.29
|
|
|
|
7.37
|
|
|
|
11.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,232
|
|
|
|
5,751
|
|
|
|
3,190
|
|
|
|
100
|
%
|
|
|
60.74
|
|
|
|
6.80
|
|
|
|
10.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
ENCORE
ENERGY PARTNERS LP
The following table sets forth the proved reserves of our
properties by principal area of operation as of
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Percent
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
of Total
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBOE)
|
|
|
|
|
|
Proved Developed:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Big Horn Basin
|
|
|
15,638
|
|
|
|
1,374
|
|
|
|
15,867
|
|
|
|
40
|
%
|
Williston Basin
|
|
|
4,513
|
|
|
|
3,361
|
|
|
|
5,073
|
|
|
|
13
|
%
|
Arkoma Basin
|
|
|
204
|
|
|
|
7,813
|
|
|
|
1,506
|
|
|
|
4
|
%
|
Permian Basin
|
|
|
5,986
|
|
|
|
65,831
|
|
|
|
16,958
|
|
|
|
43
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved Developed
|
|
|
26,341
|
|
|
|
78,379
|
|
|
|
39,404
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Undeveloped:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Big Horn Basin
|
|
|
1,044
|
|
|
|
|
|
|
|
1,044
|
|
|
|
29
|
%
|
Williston Basin
|
|
|
522
|
|
|
|
243
|
|
|
|
563
|
|
|
|
15
|
%
|
Permian Basin
|
|
|
1,023
|
|
|
|
6,077
|
|
|
|
2,036
|
|
|
|
56
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved Undeveloped
|
|
|
2,589
|
|
|
|
6,320
|
|
|
|
3,643
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Big Horn Basin
|
|
|
16,682
|
|
|
|
1,374
|
|
|
|
16,911
|
|
|
|
39
|
%
|
Williston Basin
|
|
|
5,035
|
|
|
|
3,604
|
|
|
|
5,636
|
|
|
|
13
|
%
|
Arkoma Basin
|
|
|
204
|
|
|
|
7,813
|
|
|
|
1,506
|
|
|
|
4
|
%
|
Permian Basin
|
|
|
7,009
|
|
|
|
71,908
|
|
|
|
18,994
|
|
|
|
44
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
|
28,930
|
|
|
|
84,699
|
|
|
|
43,047
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2009, the total quantity of proved
undeveloped reserves was 3.6 MMBOE, which was
22 percent higher than the balance at December 31,
2008. This increase is primarily attributable to an increase in
the amount of reserves that are allowed to be classified as
proved undeveloped, in accordance with the SECs new rules
on oil and natural gas reserves, partially offset by a decrease
due to the conversion of properties from proved undeveloped to
proved developed reserves.
The following table sets forth the
PV-10 of our
properties by principal area of operation as of
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
Amount(a)
|
|
|
Percent of Total
|
|
|
|
(In thousands)
|
|
|
|
|
|
Big Horn Basin
|
|
$
|
263,965
|
|
|
|
53
|
%
|
Williston Basin
|
|
|
73,445
|
|
|
|
15
|
%
|
Arkoma Basin
|
|
|
15,765
|
|
|
|
3
|
%
|
Permian Basin
|
|
|
146,598
|
|
|
|
29
|
%
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
499,773
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Giving effect to commodity derivative contracts, our
PV-10 would
increase by $0.2 million at December 31, 2009.
Standardized Measure at December 31, 2009 was
$494.5 million. Standardized Measure differs from
PV-10 by
approximately $5.3 million because Standardized Measure
includes the effect of future net abandonment costs and future
income taxes. Since we are taxed as a partnership that is not
subject to federal income taxes, future income taxes reflect the
impact of estimated future Texas margin taxes in the Permian
Basin area. |
10
ENCORE
ENERGY PARTNERS LP
Proved
Reserves
Recent SEC Rule-Making Activity. In December
2008, the SEC announced that it had approved revisions designed
to modernize the oil and gas company reserves reporting
requirements. Application of the new reserve rules resulted in
the use of lower prices at December 31, 2009 for both oil
and natural gas than would have resulted under the previous
rules. Use of new
12-month
average pricing rules at December 31, 2009 resulted in a
decrease in proved reserves of approximately 2.2 MMBOE.
Pursuant to the SECs final rule, prior period reserves
were not restated.
The SECs new rules expanded the technologies that a
company can use to establish reserves. The SEC now allows use of
techniques that have been proved effective by actual production
from projects in the same reservoir or an analogous reservoir or
by other evidence using reliable technology that establishes
reasonable certainty.
We used a combination of drilling results production and
pressure performance, wireline wellbore measurements, simulation
studies, offset analogies, seismic data and interpretation,
wireline formation tests, geophysical logs, and core data to
calculate our reserves estimates, including the material
additions to the 2009 reserves estimates.
Proved Undeveloped Reserves
(PUDs). As of December 31, 2009,
our PUDs totaled 2.6 MMBbls of crude oil and 6.3 Bcf
of natural gas, for a total of 3.6 MMBOE or about
8.5 percent of our total proved reserves.
All of our PUDs as of December 31, 2009 are associated with
development projects that are scheduled to begin drilling within
the next 5 years. Our major development areas are located
in our West Texas and Big Horn fields. All of these projects
will convert to proved developed reserves as, and to the extent,
these projects achieve production response.
Internal Controls Over Reserves Estimates. Our
policies regarding internal controls over the recording of
reserves estimates requires reserves to be in compliance with
the SEC definitions and guidance and prepared in accordance with
generally accepted petroleum engineering principles. We engage a
third-party petroleum consulting firm, Miller and Lents, Ltd.
(Miller and Lents) to prepare our reserves.
Responsibility for compliance in reserves bookings is delegated
to the Reserves and Planning Engineering Manager and requires
that reserves estimates be made by the regional reservoir
engineering staff for our different geographical regions. These
reserves estimates are reviewed and approved by regional
management and senior engineering staff with final approval by
the Reserves and Planning Engineering Manager and the Senior
Vice President and Chief Operating Officer and certain members
of senior management.
Our Reserves and Planning Engineering Manager is the technical
person primarily responsible for overseeing the preparation of
our reserves estimates. She has a Bachelor of Science degree in
Petroleum Engineering, 15 years of industry experience, and
9 years experience managing our reserves with positions of
increasing responsibility in engineering and evaluations. The
Reserves and Planning Engineering Manager reports directly to
our Senior Vice President and Chief Operating Officer.
The engineers and geologists of Miller and Lents have an average
of 30 years of relevant industry experience in the
estimation, assessment, and evaluation of oil and natural gas
reserves. They have significant industry experience in virtually
all petroleum-producing basins in the world and meet the
requirements regarding qualifications, independence,
objectivity, and confidentiality set forth in the Standards
Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information promulgated by the Society of Petroleum
Engineers. Miller and Lents is an independent firm of petroleum
engineers, geologists, geophysicists, and petrophysicists; it
does not own an interest in our properties and is not employed
on a contingent fee basis. Miller and Lents report on our
reserves and future net revenues as of December 31, 2009,
which details specific information regarding the scope of work
undertaken and the results thereof, is filed as
Exhibit 99.1 to this Report and incorporated herein by
reference.
11
ENCORE
ENERGY PARTNERS LP
Guidelines established by the SEC were used to prepare these
reserve estimates. 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 and their
PV-10 are
inherently imprecise, subject to change, and should not be
construed as representing the actual quantities of future
production or cash flows to be realized from oil and natural gas
properties or the fair market value of such properties.
Other Reserve Information. During 2009, we
filed the estimates of our oil and natural gas reserves as of
December 31, 2008 with the U.S. Department of Energy
on
Form EIA-23.
As required by
Form EIA-23,
the filing reflected only gross production that comes from our
operated wells at year-end. Those estimates came directly from
our reserve report prepared by Miller and Lents.
Big Horn
Basin Properties
Our Big Horn Basin properties, which include our Elk Basin
Assets and the Gooseberry field, are located in northwestern
Wyoming and south central Montana. The Big Horn Basin is
characterized by oil and natural gas fields with long production
histories and multiple producing formations. The Big Horn Basin
is a prolific basin and has produced over 1.8 billion Bbls
of oil since its discovery in 1906.
During 2009, production from our Big Horn Basin properties
averaged approximately 4,049 BOE/D, of which approximately
96 percent was oil. Our Big Horn Basin properties had
estimated proved reserves at December 31, 2009 of
16.9 MMBOE, of which 15.9 MMBOE was proved developed
and 1.0 MMBOE was proved undeveloped.
12
ENCORE
ENERGY PARTNERS LP
Elk
Basin Properties
Our properties in the Elk Basin area are located in the Elk
Basin field, Northwest Elk Basin field, and the South Elk Basin
field. The major producing horizons in these fields are the
Embar-Tensleep, Madison, Frontier, and Big Horn formations. The
Elk Basin Assets had estimated proved reserves at
December 31, 2009 of 12.5 MMBOE, of which
11.5 MMBOE was proved developed and 1.0 MMBOE was
proved undeveloped.
Our properties in the Elk Basin area include 16,267 gross
acres (13,360 net) located in Park County, Wyoming and Carbon
County, Montana. All of our production in the Elk Basin area is
operated.
We also own and operate (1) the Elk Basin natural gas
processing plant near Powell, Wyoming, (2) the Clearfork
crude oil pipeline extending from the South Elk Basin field to
the Elk Basin field in Wyoming, (3) the Wildhorse natural
gas gathering system that transports low sulfur natural gas from
the Elk Basin and South Elk Basin fields to our Elk Basin
natural gas processing plant, and (4) a small natural gas
gathering system that transports high sulfur natural gas from
the Elk Basin field to our Elk Basin natural gas processing
facility.
Embar-Tensleep Formation. Production in the
Embar-Tensleep formation is being enhanced through a tertiary
recovery technique involving effluent gas, or flue gas, from a
natural gas processing facility located in the Elk Basin field.
From 1949 to 1974, flue gas was injected into the Embar-Tensleep
formation to increase pressure and improve production of
resident hydrocarbons. Flue gas injection was re-established in
1998, and pressure monitoring wells indicate that the reservoir
pressure continues to increase.
Our wells in the Embar-Tensleep formation of the Elk Basin field
are drilled to a depth of 4,200 to 5,400 feet. We hold an
average 62 percent working interest and an average
56 percent net revenue interest in these wells. At
December 31, 2009, the Embar-Tensleep formation had
estimated total proved reserves of 4.7 MMBOE, all of which
were oil and 95 percent of which were proved developed.
Madison Formation. Production in the Madison
formation is being enhanced through a waterflood. We believe
that we can enhance production in the Madison formation by,
among other things, reestablishing optimal injection and
producing well patterns.
Our wells in the Madison formation of the Elk Basin field are
drilled to a depth of 4,800 to 5,800 feet. We hold an
average 67 percent working interest and an average
61 percent net revenue interest in these wells. The Madison
formation had estimated total proved reserves at
December 31, 2009 of 6.3 MMBOE, all of which were oil
and 87 percent of which were proved developed.
Frontier Formation. The Frontier formation is
being produced through primary recovery techniques.
Our wells in the Frontier formation of the Elk Basin field are
typically drilled to a depth of 1,600 to 2,900 feet. We
hold an average 95 percent working interest and an average
81 percent net revenue interest in our wells in the
Frontier formation. The Frontier formation had estimated total
proved reserves at December 31, 2009 of 543 MBOE,
67 percent of which were oil and all of which were proved
developed.
Other Oil and Natural Gas Properties. We also
operate wells in the Big Horn, Embar-Tensleep, and Madison
formations in the Northwest Elk Basin field and in the
Embar-Tensleep, Middle Frontier, Torchlight, and Peay Sand
formations in the South Elk Basin field. We hold an average
83 percent working interest and an average 71 percent
net revenue interest in our wells in these fields.
The Northwest Elk Basin field and South Elk Basin field had
estimated total proved reserves at December 31, 2009 of
725 MBOE, 93 percent of which were oil and all of
which were proved developed.
Natural Gas Processing Plant. We operate and
own a 62 percent interest in the Elk Basin natural gas
processing plant near Powell, Wyoming, which was first placed
into operation in the 1940s. ExxonMobil Corporation owns a
34 percent interest in the Elk Basin natural gas processing
plant, and other parties own the remaining 4 percent
interest.
13
ENCORE
ENERGY PARTNERS LP
The Elk Basin natural gas processing plant is a refrigeration
natural gas processing plant that receives natural gas supplies
through a natural gas gathering system from fields in the Elk
Basin and South Elk Basin fields. During 2009, the Elk Basin
natural gas processing plant produced approximately 421 net
Bbls of NGLs per day, primarily propane, normal butane, and
natural gasoline.
Pipelines. We own and operate one crude oil
pipeline system and two natural gas gathering pipeline systems.
The Clearfork pipeline is regulated by the FERC and transports
approximately 4,000 Bbls/D of crude oil from the Elk Basin
field to a pipeline operated by Marathon Oil Corporation for
further delivery to other markets. Most of the crude oil
transported by the Clearfork pipeline is eventually sold to
refineries in Billings, Montana. The Clearfork pipeline receives
crude oil from various interconnections with local gathering
systems.
The Wildhorse pipeline system is an approximately
12-mile
natural gas gathering system that transports approximately
1.0 MMcf/D of low-sulfur natural gas from the Elk Basin and
South Elk Basin fields to our Elk Basin natural gas
processing plant. The natural gas transported by the Wildhorse
gathering system is sold into the WBI Pipeline.
We also own a small natural gas gathering system that transports
approximately 13.5 MMcf/D of high sulfur natural gas from
the Elk Basin field to our Elk Basin natural gas processing
plant.
Gooseberry
Field
Gooseberry field is made up of two waterflood units in the Big
Horn Basin. The field is located 60 miles south of Elk
Basin in Wyoming and consists of 23 active producing wells.
Gooseberry is an active waterflood project.
The wells in the Gooseberry field are completed at
9,000 feet of depth from the Phosphoria and Tensleep
formations. We hold all working interest and an average
90 percent net revenue interest in our wells in the
Gooseberry field. The Gooseberry field had estimated proved
reserves at December 31, 2009 of 4.4 MMBOE, all of
which were oil and all of which were proved developed.
Williston
Basin Properties
Our Williston Basin properties include: Horse Creek, Charlson
Madison Unit, Elk, Cedar Creek MT, Lookout Butte East, Pine,
Beaver Creek, Buffalo Wallow, Buford, Crane, Charlie Creek,
Dickinson, Elm Coulee, Lone Butte, Lonetree Creek, Missouri
Ridge, Tracy Mountain, Tract Mountain Fryburg, Treetop, Trenton,
and Whiskey Joe. The Horse Creek field is located in Bowman
County, North Dakota and has producing oil wells from multiple
horizons in the Red River formation. The Charlson Madison Unit
produces from the unitized Madison formation. The Elk field is
operated and produces from wells in McKenzie County, North
Dakota.
During 2009, production from our Williston Basin properties
averaged approximately 1,262 BOE/D, of which approximately
89 percent was oil. Our Williston Basin properties had
estimated proved reserves at December 31, 2009 of
5.6 MMBOE, of which 5.1 MMBOE were proved developed.
During 2009, we drilled 1 gross (0.3 net) wells.
Permian
Basin Properties
The Permian Basin is one of the largest and most prolific oil
and natural gas producing basins in the United States. The
Permian Basin extends over 100,000 square miles in West
Texas and southeast New Mexico and has produced over
24 billion Bbls of oil since its discovery in 1921. The
Permian Basin is characterized by oil and natural gas fields
with long production histories and multiple producing formations.
For 2009, production from our Permian Basin properties was
approximately 20,262 MMcfe/D, 61 percent of which was
natural gas. Our Permian Basin properties had estimated proved
reserves at December 31, 2009
14
ENCORE
ENERGY PARTNERS LP
of 114.0 Bcfe, of which 101.8 Bcfe was proved
developed and 12.2 Bcfe was proved undeveloped. As of
December 31, 2009, our Permian Basin properties consisted
of 68,070 gross (44,838 net) acres.
Operated Properties. In West Texas, we operate
763 wells in eight areas: Crockett, Dune, Sand Hills,
Champmon, Nolley/McFarland, Hutex, Slaughter/Levelland, and
Vinegarone. We operate 5 wells in the Brunson area of New
Mexico.
The Crockett area is located in Crockett County, Texas.
Producing fields include Angus, Henderson, Hunt-Baggett, and
Ozona. These wells are primarily gas wells completed in the
Canyon Sand and Strawn formations. The productive intervals are
tight sand deposits at 6,500 to 8,500 feet of depth. The
Vinegarone field is located in ValVerde County, Texas. These gas
wells produce from the Strawn reservoir.
There are two fields located in Crane County, Texas. The Dune
field is a waterflood property producing from the
San Andres formation. The Sand Hills field has production
in the waterflooded Tubb formation as well as production from
the Wojcik-McElroy, McKnight, Judkins, Clearfork, and Penn
formations.
The Champmon field is located on a Strawn reef structure in
Gaines County, Texas. The field was discovered in 1996 and is
drilled on
40-acre
spacing. Three fields are located in Andrews County, Texas. The
Nolley-McFarland
area consists of two fields Nolley and Mcfarland.
Production is primarily oil from wells completed in the Queen,
Clearfork, Wolfcamp, and Penn formations. Depths range from
4,500 to 10,500 feet. The Hutex field produces
from the Strawn, Dean, and Devonian formations. The Slaughter
and Levelland fields are located in Cochran County, Texas.
Production is primarily oil from the San Andres. The
waterflood operations in these fields have been ongoing since
the 1970s.
The five wells in New Mexico Brunson area produce from multiple
formations which are downhole commingled. The formations include
Blinebry, Drinkard, Tubb, and Wantz.
Non-Operated Properties. We own non-operated
interests in several fields in the Permian Basin. The largest
are the North Cowden field and the Crockett area fields. We also
own interests in the Yates field in Pecos County as well as
interests in Loco Hills field in Eddy County, New Mexico.
The North Cowden field is a legacy West Texas field located in
Ector County, Texas. The North Cowden field has been undergoing
secondary waterflood operations since the 1970s. More recently,
the field has successfully piloted
CO2
injection as a tertiary method for recovering additional oil.
The Crockett area includes fields in the Davidson Ranch,
Hunt-Baggett, Live Oak Draw, and Ozona fields in Crockett
County, Texas. At December 31, 2009, we held an average
working interest of 21 percent and an average net revenue
interest of 15 percent in the producing wells developed in
this area. These wells produce from the Canyon Sand and Strawn
formations at depths of 8,000 to 9,000 feet. Many of the
wells were not completed in all of the known producing intervals.
The Canyon Sand formation in Crockett County is drilled to
40-acre
spacing, and many of our
non-operated
leases have quality drilling locations remaining to be
developed. We have identified 5.9 Bcfe of proved
undeveloped reserves on these properties.
Our properties in Crockett County are operated by several
companies, but a majority of the wells are operated by a private
oil and gas company that has drilled over 80 wells in
Crockett County, Texas since 2000. Historically, we have
participated with this company in drilling 2 to 4 wells per
year.
Arkoma
Properties
The royalty interest properties include interests in over
1,700 wells in Arkansas, Texas, and Oklahoma as well as
10,300 unleased mineral acres. The Arkoma Basin properties
consist of non-operated working interests in over 100 producing
wells in the Chismville field. At December 31, 2009, the
properties had total proved reserves of approximately
1.5 MMBOE, all of which is proved developed producing and
86 percent of which
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ENERGY PARTNERS LP
are natural gas. During 2009, the production from our Arkoma
properties averaged approximately 2,988 MMcfe/D, of which
88 percent is natural gas. During 2009, we drilled
14 gross (1.5 net) wells.
Title to
Properties
We believe that we have satisfactory title to our oil and
natural gas properties in accordance with standards generally
accepted in the oil and natural gas industry.
Our properties are subject, in one degree or another, to one or
more of the following:
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royalties, overriding royalties, and other burdens under oil and
natural gas leases;
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contractual obligations, including, in some cases, development
obligations arising under operating agreements, farm-out
agreements, production sales contracts, and other agreements
that may affect the properties or their titles;
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liens that arise in the normal course of operations, such as
those for unpaid taxes, statutory liens securing unpaid
suppliers and contractors, and contractual liens under operating
agreements;
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pooling, unitization, and communitization agreements,
declarations, and orders; and
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easements, restrictions,
rights-of-way,
and other matters that commonly affect property.
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We believe that the burdens and obligations affecting our
properties do not, in the aggregate, materially interfere with
the use of the properties.
We have granted mortgage liens on substantially all of our oil
and natural gas properties in favor of Bank of America, N.A., as
agent, to secure borrowings under our revolving credit facility.
These mortgages and the revolving credit facility contain
substantial restrictions and operating covenants that are
customarily found in loan agreements of this type.
Environmental
Matters and Regulation
General. Our operations are subject to
stringent and complex federal, state, and local laws and
regulations governing environmental protection, including air
emissions, water quality, wastewater discharges, and solid waste
management. These laws and regulations may, among other things:
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require the acquisition of various permits before development
commences;
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require the installation of pollution control equipment;
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enjoin some or all of the operations of facilities deemed in
non-compliance with permits;
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restrict the types, quantities, and concentration of various
substances that can be released into the environment in
connection with oil and natural gas development, production, and
transportation activities;
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restrict the way in which wastes are handled and disposed;
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limit or prohibit development activities on certain lands lying
within wilderness, wetlands, areas inhabited by threatened or
endangered species, and other protected areas;
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require remedial measures to mitigate pollution from former and
ongoing operations, such as requirements to close pits and plug
abandoned wells;
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impose substantial liabilities for pollution resulting from
operations; and
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require preparation of a Resource Management Plan, an
Environmental Assessment,
and/or an
Environmental Impact Statement for operations affecting federal
lands or leases.
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These laws, rules, and regulations may also restrict the rate of
oil and natural gas production below the rate that would
otherwise be possible. The regulatory burden on the oil and
natural gas industry increases the cost of doing business in the
industry and consequently affects profitability. Additionally,
Congress and federal and state agencies frequently revise
environmental laws and regulations, and the clear trend in
environmental regulation is to place more restrictions and
limitations on activities that may affect the environment. Any
changes that result in indirect compliance costs or additional
operating restrictions, including costly waste handling,
disposal, and cleanup requirements for the oil and natural gas
industry could have a significant impact on our operating costs.
The following is a discussion of relevant environmental and
safety laws and regulations that relate to our operations.
Waste Handling. The Resource Conservation and
Recovery Act (RCRA), and comparable state statutes,
regulate the generation, transportation, treatment, storage,
disposal, and cleanup of hazardous and non-hazardous solid
wastes. Under the auspices of the federal Environmental
Protection Agency (the EPA), the individual states
administer some or all of the provisions of RCRA, sometimes in
conjunction with their own, more stringent requirements.
Drilling fluids, produced waters, and most of the other wastes
associated with the exploration, development, and production of
crude oil or natural gas are regulated under RCRAs
non-hazardous
waste provisions. However, it is possible that certain oil and
natural gas exploration and production wastes now classified as
non-hazardous could be classified as hazardous wastes in the
future. Any such change could result in an increase in our costs
to manage and dispose of wastes, which could have a material
adverse effect on our results of operations and financial
position. Also, in the course of our operations, we generate
some amounts of ordinary industrial wastes, such as paint
wastes, waste solvents, and waste oils that may be regulated as
hazardous wastes.
Site Remediation. The Comprehensive
Environmental Response, Compensation and Liability Act
(CERCLA), also known as the Superfund law, imposes
joint and several liability, without regard to fault or legality
of conduct, on classes of persons who are considered to be
responsible for the release of a hazardous substance into the
environment. These persons include the current and past owner or
operator of the site where the release occurred, and anyone who
disposed of or arranged for the disposal of a hazardous
substance released at the site. Under CERCLA, such persons may
be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released
into the environment, for damages to natural resources, and for
the costs of certain health studies. CERCLA authorizes the EPA,
and in some cases third parties, to take actions in response to
threats to the public health or the environment and to seek to
recover from the responsible classes of persons the costs they
incur. In addition, it is not uncommon for neighboring
landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous
substances released into the environment.
We own, lease, or operate numerous properties that have been
used for oil and natural gas exploration and production for many
years. Although petroleum, including crude oil, and natural gas
are excluded from CERCLAs definition of hazardous
substance, in the course of our ordinary operations, we
generate wastes that may fall within the definition of a
hazardous substance. We believe that we have
utilized operating and waste disposal practices that were
standard in the industry at the time, yet hazardous substances,
wastes, or hydrocarbons may have been released on or under the
properties owned or leased by us, or on or under other
locations, including off-site locations, where such substances
have been taken for disposal. In addition, some of our
properties have been operated by third parties or by previous
owners or operators whose treatment and disposal of hazardous
substances, wastes, or hydrocarbons was not under our control.
In fact, there is evidence that petroleum spills or releases
have occurred in the past at some of the properties owned or
leased by us. These properties and the substances disposed or
released on them may be subject to CERCLA, RCRA, and analogous
state laws. Under such laws, we could be required to remove
previously disposed substances and wastes, remediate
contaminated property, or perform remedial plugging or pit
closure operations to prevent future contamination.
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The Elk Basin Assets have been used for oil and natural gas
exploration and production for many years. There have been known
releases of hazardous substances, wastes, or hydrocarbons at the
properties, and some of these sites are undergoing active
remediation. The risks associated with these environmental
conditions, and the cost of remediation, were assumed by us,
subject only to limited indemnity from the seller of the Elk
Basin Assets. Releases may also have occurred in the past that
have not yet been discovered, which could require costly future
remediation. In addition, we assumed the risk of various other
unknown or unasserted liabilities associated with the Elk Basin
Assets that relate to events that occurred prior to our
acquisition. If a significant release or event occurred in the
past, the liability for which was not retained by the seller or
for which indemnification from the seller is not available, it
could adversely affect our results of operations, financial
position, cash flows, and ability to make distributions.
Our Elk Basin Assets include a natural gas processing plant.
Previous environmental investigations of the Elk Basin natural
gas processing plant indicate historical soil and groundwater
contamination by hydrocarbons and the presence of
asbestos-containing material at the site. Although the
environmental investigations did not identify an immediate need
for remediation of the suspected historical contamination, the
extent of the contamination is not known and, therefore, the
potential liability for remediating this contamination may be
significant. In the event we ceased operating the gas plant, the
cost of decommissioning it and addressing the previously
identified environmental conditions and other conditions, such
as waste disposal, could be significant. We do not anticipate
ceasing operations at the Elk Basin natural gas processing plant
in the near future nor a need to commence remedial activities at
this time. However, a regulatory agency could require us to
investigate and remediate any contamination even while the gas
plant remains in operation. As of December 31, 2009, we
have recorded $4.7 million as future abandonment liability
for decommissioning the Elk Basin natural gas processing plant.
Due to the significant uncertainty associated with the known and
unknown environmental liabilities at the gas plant, our estimate
of the future abandonment liability includes a large
contingency. Our estimates of the future abandonment liability
and compliance costs are subject to change and the actual cost
of these items could vary significantly from those estimates.
Water Discharges. The Clean Water Act
(CWA), and analogous state laws, impose strict
controls on the discharge of pollutants, including spills and
leaks of oil and other substances, into waters of the United
States. The discharge of pollutants into regulated waters is
prohibited, except in accordance with the terms of a permit
issued by the EPA or an analogous state agency. CWA regulates
storm water run-off from oil and natural gas facilities and
requires a storm water discharge permit for certain activities.
Such a permit requires the regulated facility to monitor and
sample storm water run-off from its operations. CWA and
regulations implemented thereunder also prohibit discharges of
dredged and fill material in wetlands and other waters of the
United States unless authorized by an appropriately issued
permit. Spill prevention, control, and countermeasure
requirements of CWA require appropriate containment berms and
similar structures to help prevent the contamination of
navigable waters in the event of a petroleum hydrocarbon tank
spill, rupture, or leak. Federal and state regulatory agencies
can impose administrative, civil, and criminal penalties for
non-compliance
with discharge permits or other requirements of CWA and
analogous state laws and regulations.
The primary federal law for oil spill liability is the Oil
Pollution Act (OPA), which addresses three principal
areas of oil pollution prevention, containment, and
cleanup. OPA applies to vessels, offshore facilities, and
onshore facilities, including exploration and production
facilities that may affect waters of the United States. Under
OPA, responsible parties, including owners and operators of
onshore facilities, may be subject to oil cleanup costs and
natural resource damages as well as a variety of public and
private damages that may result from oil spills.
Air Emissions. Oil and natural gas exploration
and production operations are subject to the federal Clean Air
Act (CAA), and comparable state laws and
regulations. These laws and regulations regulate emissions of
air pollutants from various industrial sources, including oil
and natural gas exploration and production facilities, and also
impose various monitoring and reporting requirements. Such laws
and regulations may require a facility to obtain pre-approval
for the construction or modification of certain projects or
facilities
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ENERGY PARTNERS LP
expected to produce air emissions or result in the increase of
existing air emissions, obtain and strictly comply with air
permits containing various emissions and operational
limitations, or utilize specific emission control technologies
to limit emissions.
Permits and related compliance obligations under CAA, as well as
changes to state implementation plans for controlling air
emissions in regional non-attainment areas, may require oil and
natural gas exploration and production operations to incur
future capital expenditures in connection with the addition or
modification of existing air emission control equipment and
strategies. In addition, some oil and natural gas facilities may
be included within the categories of hazardous air pollutant
sources, which are subject to increasing regulation under CAA.
Failure to comply with these requirements could subject a
regulated entity to monetary penalties, injunctions, conditions
or restrictions on operations, and enforcement actions. Oil and
natural gas exploration and production facilities may be
required to incur certain capital expenditures in the future for
air pollution control equipment in connection with obtaining and
maintaining operating permits and approvals for air emissions.
Scientific studies have suggested that emissions of certain
gases, commonly referred to as greenhouse gases and
including carbon dioxide and methane, may be contributing to
warming of the atmosphere. In response to such studies, Congress
is considering legislation to reduce emissions of greenhouse
gases. In addition, at least 17 states have declined to
wait on Congress to develop and implement climate control
legislation and have already taken legal measures to reduce
emissions of greenhouse gases. Also, as a result of the Supreme
Courts decision on April 2, 2007 in Massachusetts,
et al. v. EPA, the EPA must consider whether it is
required to regulate greenhouse gas emissions from mobile
sources (e.g., cars and trucks) even if Congress does not adopt
new legislation specifically addressing emissions of greenhouse
gases. The Supreme Courts holding in Massachusetts
that greenhouse gases fall under CAAs definition of
air pollutant may also result in future regulation
of greenhouse gas emissions from stationary sources under
various CAA programs, including those used in oil and natural
gas exploration and production operations. It is not possible to
predict how legislation that may be enacted to address
greenhouse gas emissions would impact the oil and natural gas
exploration and production business. However, future laws and
regulations could result in increased compliance costs or
additional operating restrictions and could have a material
adverse effect on our business, financial condition, demand for
our operations, results of operations, cash flows, and ability
to make distributions.
Activities on Federal Lands. Oil and natural
gas exploration and production activities on federal lands are
subject to the National Environmental Policy Act
(NEPA). NEPA requires federal agencies, including
the Department of the Interior, to evaluate major agency actions
having the potential to significantly impact the environment. In
the course of such evaluations, an agency will prepare an
Environmental Assessment that assesses the potential direct,
indirect, and cumulative impacts of a proposed project and, if
necessary, will prepare a more detailed Environmental Impact
Statement that may be made available for public review and
comment. Our current exploration and production activities and
planned exploration and development activities on federal lands
require governmental permits that are subject to the
requirements of NEPA. This process has the potential to delay
the development of our oil and natural gas projects.
Occupational Safety and Health Act (OSH Act)
and Other Laws and Regulation. We are subject
to the requirements of OSH Act and comparable state statutes.
These laws and the implementing regulations strictly govern the
protection of the health and safety of employees. The
Occupational Safety and Health Administrations hazard
communication standard, EPA community
right-to-know
regulations under Title III of CERCLA, and similar state
statutes require that we organize
and/or
disclose information about hazardous materials used or produced
in our operations. We believe that we are in substantial
compliance with these applicable requirements and with other OSH
Act and comparable requirements.
We believe that we are in substantial compliance with all
existing environmental laws and regulations applicable to our
operations and that our continued compliance with existing
requirements will not have a material adverse impact on our
financial condition and results of operations. We did not incur
any material
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ENERGY PARTNERS LP
capital expenditures for remediation or pollution control
activities during 2009, and, as of the date of this Report, we
are not aware of any environmental issues or claims that will
require material capital expenditures in the future. However,
accidental spills or releases may occur in the course of our
operations, and we may incur substantial costs and liabilities
as a result of such spills or releases, including those relating
to claims for damage to property and persons. Moreover, the
passage of more stringent laws or regulations in the future may
have a negative impact on our business, financial condition,
results of operations, or ability to make distributions.
Other
Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by
numerous federal, state, and local authorities. Legislation
affecting the oil and natural gas industry is under constant
review for amendment or expansion, frequently increasing the
regulatory burden. Also, numerous departments and agencies, both
federal and state, are authorized by statute to issue rules and
regulations binding on the oil and natural gas industry and its
individual members, some of which carry substantial penalties
for failure to comply. Although the regulatory burden on the oil
and natural gas industry increases our cost of doing business
and, consequently, affects our profitability, these burdens
generally do not affect us any differently or to any greater or
lesser extent than they affect other companies in the industry
with similar types, quantities, and locations of production.
Legislation continues to be introduced in Congress and
development of regulations continues in the Department of
Homeland Security and other agencies concerning the security of
industrial facilities, including oil and natural gas facilities.
Our operations may be subject to such laws and regulations.
Presently, it is not possible to accurately estimate the costs
we could incur to comply with any such facility security laws or
regulations, but such expenditures could be substantial.
Development and Production. Our operations are
subject to various types of regulation at the federal, state,
and local levels. These types of regulation include requiring
permits for the development of wells, development bonds, and
reports concerning operations. Most states, and some counties
and municipalities, in which we operate also regulate one or
more of the following:
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location of wells;
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methods of developing and casing wells;
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surface use and restoration of properties upon which wells are
drilled;
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plugging and abandoning of wells; and
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notification of surface owners and other third parties.
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State laws regulate the size and shape of development and
spacing units or proration units governing the pooling of oil
and natural gas properties. Some states allow forced pooling or
integration of tracts in order to facilitate exploitation while
other states rely on voluntary pooling of lands and leases. In
some instances, forced pooling or unitization may be implemented
by third parties and may reduce our interest in the unitized
properties. In addition, state conservation laws establish
maximum rates of production from oil and natural gas wells,
generally prohibit the venting or flaring of natural gas, and
impose requirements regarding the ratability of production.
These laws and regulations may limit the amount of oil and
natural gas we can produce from our wells or limit the number of
wells or the locations at which we can drill. Moreover, each
state generally imposes a production or severance tax with
respect to the production and sale of oil, natural gas, and NGLs
within its jurisdiction.
Natural Gas Gathering. Section 1(b) of
the Natural Gas Act (NGA) exempts natural gas
gathering facilities from the jurisdiction of the Federal Energy
Regulatory Commission (the FERC). We own a number of
facilities that we believe would meet the traditional tests the
FERC has used to establish a pipelines status as a
gatherer not subject to the FERCs jurisdiction. In the
states in which we operate, regulation of gathering
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facilities and intrastate pipeline facilities generally includes
various safety, environmental, and in some circumstances,
nondiscriminatory take requirement and complaint-based rate
regulation.
Natural gas gathering may receive greater regulatory scrutiny at
both the state and federal levels since the FERC has taken a
less stringent approach to regulation of the offshore gathering
activities of interstate pipeline transmission companies and a
number of such companies have transferred gathering facilities
to unregulated affiliates. Our gathering operations could be
adversely affected should they become subject to the application
of state or federal regulation of rates and services. Our
gathering operations also may be or become subject to safety and
operational regulations relating to the design, installation,
testing, construction, operation, replacement, and management of
gathering facilities. Additional rules and legislation
pertaining to these matters are considered or adopted from time
to time. We cannot predict what effect, if any, such changes
might have on our operations, but the industry could be required
to incur additional capital expenditures and increased costs
depending on future legislative and regulatory changes.
Sales of Natural Gas. The price at which we
buy and sell natural gas is not subject to federal regulation
and, for the most part, is not subject to state regulation. Our
sales of natural gas are affected by the availability, terms,
and cost of pipeline transportation. The price and terms of
access to pipeline transportation are subject to extensive
federal and state regulation. The FERC is continually proposing
and implementing new rules and regulations affecting those
segments of the natural gas industry, most notably interstate
natural gas transmission companies that remain subject to the
FERCs jurisdiction. These initiatives also may affect the
intrastate transportation of natural gas under certain
circumstances. The stated purpose of many of these regulatory
changes is to promote competition among the various sectors of
the natural gas industry, and these initiatives generally
reflect more light-handed regulation. We cannot predict the
ultimate impact of these regulatory changes on our natural gas
marketing operations, and we note that some of the FERCs
more recent proposals may adversely affect the availability and
reliability of interruptible transportation service on
interstate pipelines. We do not believe that we will be affected
by any such FERC action materially differently than other
natural gas marketers with which we compete.
The Energy Policy Act of 2005 (EP Act 2005) gave the
FERC increased oversight and penalty authority regarding market
manipulation and enforcement. EP Act 2005 amended NGA to
prohibit market manipulation and also amended NGA and the
Natural Gas Policy Act of 1978 (NGPA) to increase
civil and criminal penalties for any violations of NGA, NGPA,
and any rules, regulations, or orders of the FERC to up to
$1,000,000 per day, per violation. In 2006, the FERC issued a
rule regarding market manipulation, which makes it unlawful for
any entity, in connection with the purchase or sale of natural
gas or transportation service subject to the FERCs
jurisdiction, to defraud, make an untrue statement, or omit a
material fact, or engage in any practice, act, or course of
business that operates or would operate as a fraud. This rule
works together with the FERCs enhanced penalty authority
to provide increased oversight of the natural gas marketplace.
State Regulation. The various states regulate
the development, production, gathering, and sale of oil and
natural gas, including imposing severance taxes and requirements
for obtaining drilling permits. Reduced rates or credits may
apply to certain types of wells and production methods.
In addition to production taxes, Texas and Montana each impose
ad valorem taxes on oil and natural gas properties and
production equipment. Wyoming and New Mexico impose an ad
valorem tax on the gross value of oil and natural gas production
in lieu of an ad valorem tax on the underlying oil and natural
gas properties. Wyoming also imposes an ad valorem tax on
production equipment. North Dakota imposes an ad valorem tax on
gross oil and natural gas production in lieu of an ad valorem
tax on the underlying oil and gas leases or on production
equipment used on oil and gas leases.
States also regulate the method of developing new fields, the
spacing and operation of wells, and the prevention of waste of
oil and natural gas resources. States may regulate rates of
production and establish maximum daily production allowables
from oil and natural gas wells based on market demand or
resource conservation, or both. States do not regulate wellhead
prices or engage in other similar direct economic
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regulation, but they may do so in the future. The effect of
these regulations may be to limit the amounts of oil and natural
gas that may be produced from our wells, and to limit the number
of wells or locations we can drill.
Federal, State, or Native American Leases. Our
operations on federal, state, or Native American oil and natural
gas leases are subject to numerous restrictions, including
nondiscrimination statutes. Such operations must be conducted
pursuant to certain
on-site
security regulations and other permits and authorizations issued
by the Federal Bureau of Land Management, Minerals Management
Service, and other agencies.
Operating
Hazards and Insurance
The oil and natural gas business involves a variety of operating
risks, including fires, explosions, blowouts, environmental
hazards, and other potential events that can adversely affect
our ability to conduct operations and cause us to incur
substantial losses. Such losses could reduce or eliminate the
funds available for exploration, exploitation, or leasehold
acquisitions or result in loss of properties.
In accordance with industry practice, we maintain insurance
against some, but not all, potential risks and losses. We do not
carry business interruption insurance. We may not obtain
insurance for certain risks if we believe the cost of available
insurance is excessive relative to the risks presented. In
addition, pollution and environmental risks generally are not
fully insurable at a reasonable cost. If a significant accident
or other event occurs that is not fully covered by insurance, it
could adversely affect us.
Employees
The officers of our general partner manage our operations and
activities. However, neither we nor our general partner have
employees. Encore Operating performs administrative services for
us pursuant to an administrative services agreement. For
additional information regarding the administrative services
agreement, please read Administrative Services
Agreement included in Item 13. Certain
Relationships and Related Transactions, and Director
Independence.
As of December 31, 2009, EAC had a staff of
421 persons, including 35 engineers, 18 geologists, and
13 landmen, none of which are represented by labor unions
or covered by any collective bargaining agreement. We believe
that EACs relations with its employees are satisfactory.
Principal
Executive Office
Our principal executive office is located at 777 Main Street,
Suite 1400, Fort Worth, Texas 76102. Our main
telephone number is
(817) 877-9955.
Available
Information
We make available electronically, free of charge through our
website (www.encoreenp.com), our annual reports on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K,
and other filings with the SEC pursuant to Section 13(a) of
the Securities Exchange Act of 1934 (the Exchange
Act) as soon as reasonably practicable after we
electronically file such material with, or furnish such material
to, the SEC. In addition, you may read and copy any materials
that we file with the SEC at its public reference room at
100 F Street, N.E., Room 1580,
Washington, D.C. 20549. Information concerning the
operation of the public reference room may be obtained by
calling the SEC at
1-800-SEC-0330.
The SEC also maintains a website (www.sec.gov) that
contains reports, proxy statements, and other information
regarding issuers, like us, that file electronically with the
SEC.
We have adopted a code of business conduct and ethics that
applies to all directors, officers, and employees of our general
partner, including the principal executive officer and principal
financial officer of our general partner. The code of business
conduct and ethics is available on our website. In the event
that we
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ENERGY PARTNERS LP
make changes in, or provide waivers from, the provisions of this
code of business conduct and ethics that the SEC or the NYSE
requires us to disclose, we intend to disclose these events on
our website.
The board of directors of our general partner has two standing
committees: (1) audit and (2) conflicts. 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. The audit
committee charter, our code of business conduct and ethics, and
our corporate governance guidelines are available on our website.
The information on our website or any other website is not
incorporated by reference into this Report.
23
ENCORE
ENERGY PARTNERS LP
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 be unable 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
If the
Merger between EAC and Denbury is not completed, it could
negatively affect the price of our common units and future
business and operations.
There is no assurance that the Merger between EAC and Denbury
will be completed. If the Merger is not completed for any
reason, we and EAC may be subject to a number of risks,
including the following:
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EAC may not realize the benefits expected from the Merger,
including a potentially enhanced financial and competitive
position, which in turn could negatively affect our financial
and competitive position; and
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the current market price of our common units may reflect a
market assumption that the Merger will occur and a failure to
complete the Merger could result in a decline in the market
price of our common units.
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Delays in competing the Merger could exacerbate uncertainties
concerning the effect of the Merger, which may have an adverse
effect on our business following the Merger and could defer or
detract from the realization of the benefits expected to result
from the Merger.
There
may be substantial disruption to our business and distraction of
our management and employees as a result of the
Merger.
All of the executive officers of our general partner are also
executive officers of EAC, and all of our employees are provided
by Encore Operating, a subsidiary of EAC. There may be
substantial disruption to our business and distraction of our
management and employees from day-to-day operations because
matters related to the Merger may require substantial
commitments of time and resources, which could otherwise have
been devoted to other opportunities that could have been
beneficial to us.
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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ENCORE
ENERGY PARTNERS LP
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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.
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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 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.
25
ENCORE
ENERGY PARTNERS LP
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 materially and adversely affect our financial
condition, results of operations, liquidity, and cash flows,
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.
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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 led to an extended worldwide
economic slowdown in 2008 and 2009, which is expected to
continue into 2010. The slowdown in economic activity has
reduced worldwide demand for energy and resulted in lower oil
and natural gas prices.
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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26
ENCORE
ENERGY PARTNERS LP
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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.
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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 adversely
affect our financial condition, results of operations, and cash
flows, which could significantly reduce our cash available for
distribution.
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 Big Horn
Basin assets has historically 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.
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 funds
under our revolving credit facility 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
27
ENCORE
ENERGY PARTNERS LP
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.
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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
through 2012. These contracts are intended to reduce our
exposure to fluctuations in the price of oil and natural gas.
After 2012, 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.
The
counterparties to our derivative contracts may not be able to
perform their obligations to us, which could materially affect
our cash flows, results of operations, and ability to make
distributions.
As of December 31, 2009, we were entitled to future
payments of approximately $26.3 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, net 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.
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ENCORE
ENERGY PARTNERS LP
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. 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.
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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
29
ENCORE
ENERGY PARTNERS LP
materially and adversely affect our revenue and profitability
and, as a result, our ability to pay distributions to our
unitholders.
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 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.
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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 and as a result, our cash available for
distribution.
If we
do not make acquisitions, our future growth, and ability to pay
or increase distributions could be limited.
Acquisitions are an essential part of our growth strategy, and
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.
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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 with 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.
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ENCORE
ENERGY PARTNERS LP
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 under our revolving
credit facility 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 managements 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 oil and natural gas properties, 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.
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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 negatively affect our
financial condition and results of operations and 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, Texas, Oklahoma, and New Mexico. 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.
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ENCORE
ENERGY PARTNERS LP
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 2009, our largest purchaser was Marathon Oil Corporation,
which accounted for 43 percent of our total sales of
production. If this customer, or any other significant customer,
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 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 17, 2010, we had $260 million of
outstanding borrowings and $115 million of borrowing
capacity under our revolving credit facility. We have the
ability to incur additional debt under our revolving
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ENERGY PARTNERS LP
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.
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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 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 owed to such counterparty under our
revolving credit facilities.
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, liquidity, and
ability to make distributions.
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
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ENERGY PARTNERS LP
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,
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.
Possible
regulations related to global warming and climate change could
have an adverse effect on our operations and the demand for oil
and natural gas.
Recent scientific studies have suggested that emissions of
certain gases, commonly referred to as greenhouse
gases, may be contributing to the warming of the
Earths atmosphere. Methane, a primary component of natural
gas, and carbon dioxide, a byproduct of the burning of refined
oil products and natural gas, are examples of greenhouse gases.
The U.S. Congress is considering climate-related
legislation to reduce emissions of greenhouse gases. In
addition, at least 20 states have developed measures to
regulate emissions of greenhouse gases, primarily through the
planned development of greenhouse gas emissions inventories
and/or
regional greenhouse gas cap and trade programs. The EPA has
adopted regulations requiring reporting of greenhouse gas
emissions from certain facilities and is considering additional
regulation of greenhouse gases as air pollutants
under the CAA. Passage of climate change legislation or other
regulatory initiatives by Congress or various states, or the
adoption of regulations by the EPA or analogous state agencies,
that regulate or restrict emissions of greenhouse gases
(including methane or carbon dioxide) in areas in which we
conduct business could have an adverse effect our operations and
the demand for oil and natural gas.
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 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
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ENERGY PARTNERS LP
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 15 percent of our
properties (measured by total reserves) and approximately
60 percent of our wells as of December 31, 2009. 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.
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
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ENERGY PARTNERS LP
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.
Our
development and exploratory drilling efforts may not be
profitable or achieve our targeted returns.
Development and exploratory drilling and production activities
are subject to many risks, including the risk that we will not
discover commercially productive oil or natural gas reserves. In
order to further our development efforts, we acquire both
producing and unproved properties as well as lease undeveloped
acreage that we believe will enhance our growth potential and
increase our earnings over time. However, we cannot assure you
that all prospects will be economically viable or that we will
not be required to impair our initial investments.
In addition, there can be no assurance that unproved property
acquired by us or undeveloped acreage leased by us will be
profitably developed, that new wells drilled by us will be
productive, or that we will recover all or any portion of our
investment in such unproved property or wells. The costs of
drilling and completing wells are often uncertain, and drilling
operations may be curtailed, delayed, or canceled as a result of
a variety of factors, including unexpected drilling conditions,
pressure or irregularities in formations, equipment failures or
accidents, weather conditions, and shortages or delays in the
delivery of equipment. Drilling for oil and natural gas may
involve unprofitable efforts, not only from dry holes, but also
from wells that are productive but do not produce sufficient
commercial quantities to cover the development, operating, and
other costs. In addition, wells that are profitable may not meet
our internal return targets, which are dependent upon the
current and future market prices for oil and natural gas, costs
associated with producing oil and natural gas, and our ability
to add reserves at an acceptable cost.
Seismic technology does not allow us to obtain conclusive
evidence that oil or natural gas reserves are present or
economically producible prior to spudding a well. We rely to a
significant extent on seismic data and other advanced
technologies in identifying unproved property prospects and in
conducting our exploration activities. The use of seismic data
and other technologies also requires greater up-front costs than
development on proved properties.
Our
development, exploitation, and exploration operations require
substantial capital, and we may be unable to obtain needed
financing on satisfactory terms.
We make and will continue to make substantial capital
expenditures in development, exploitation, and exploration
projects. We intend to finance these capital expenditures
through operating cash flows. However, additional financing
sources may be required in the future to fund our capital
expenditures. Financing may not continue to be available under
existing or new financing arrangements, or on acceptable terms,
if at all. If additional capital resources are not available, we
may be forced to curtail our development and other activities or
be forced to sell some of our assets on an untimely or
unfavorable basis.
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ENERGY PARTNERS LP
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 17, 2010, EAC owned approximately
45.7 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. EACs
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;
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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 $2.02 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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ENERGY PARTNERS LP
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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.
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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 also owned
approximately 45.7 percent of our outstanding common units
as of February 17, 2010, 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.
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.
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ENERGY PARTNERS LP
Our
partnership agreement limits our general partners
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.
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Our unitholders are bound by the provisions in our partnership
agreement, including the provisions discussed above.
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
managements 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
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ENERGY PARTNERS LP
two-thirds
of all outstanding units voting together as a single class is
required to remove the general partner. As of February 17,
2010, EAC owned approximately 45.7 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.
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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.
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 17, 2010, EAC 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 17, 2010, EAC owned approximately
45.7 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
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ENERGY PARTNERS LP
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
states partnership statute; or
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a unitholders 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.
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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 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
41
ENCORE
ENERGY PARTNERS LP
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-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
42
ENCORE
ENERGY PARTNERS LP
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. Our counsel is unable to opine as to the validity
of this method under applicable Treasury regulations. 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 counsels
conclusions or the positions we take. A court may not agree with
some or all of our counsels 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.
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
43
ENCORE
ENERGY PARTNERS LP
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 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, New
Mexico, Oklahoma, Arkansas, 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 for one fiscal year and
require a unitholder who uses a different taxable year than us
to include more than twelve months of our taxable income or loss
in his taxable income for the year of our termination.
44
ENCORE
ENERGY PARTNERS LP
The
amount of taxable income or loss allocable to each unitholder
depends in part upon values that we periodically determine for
our outstanding equity interests and our assets in order to
comply with federal income tax law. The IRS may challenge our
determinations of these values, which could adversely affect the
value of our units.
Federal income tax law requires us to periodically determine the
value of our assets and to calculate the amount of taxable
income or loss allocable to each partner based in part upon
these values. We determine these asset values and allocations in
part by reference to values that we determine for our
outstanding equity interests. The IRS may challenge our
valuations and related allocations. A successful IRS challenge
to these valuations 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 units and could have a negative impact
on the value of the units or result in audit adjustments to our
unitholders tax returns without the benefit of additional
deductions.
Changes
to current federal tax laws may affect unitholders ability
to take certain tax deductions.
Substantive changes to the existing federal income tax laws have
been proposed that, if adopted, would affect, among other
things, the ability to take certain operations-related
deductions, including deductions for intangible drilling and
percentage depletion, and deductions for United States
production activities. We are unable to predict whether any
changes, or other proposals to such laws, ultimately will be
enacted. Any such changes could negatively impact the value of
an investment in our units.
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ITEM 1B.
|
UNRESOLVED
STAFF COMMENTS
|
There were no unresolved SEC staff comments as of
December 31, 2009.
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ITEM 3.
|
LEGAL
PROCEEDINGS
|
We are a party to ongoing legal proceedings in the ordinary
course of business. Our general partners management does
not believe the result of these legal proceedings will have a
material adverse effect on our business, financial condition,
results of operations, liquidity, or ability to pay
distributions.
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ITEM 4.
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
|
There were no matters submitted to a vote of unitholders during
the fourth quarter of 2009.
45
ENCORE
ENERGY PARTNERS LP
PART II
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ITEM 5.
|
MARKET
FOR REGISTRANTS COMMON EQUITY, RELATED UNITHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
|
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:
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Cash Distribution
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Declared per
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2009
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High
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Low
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Common Unit
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Date Paid
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Quarter ended December 31
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$
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20.97
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$
|
15.66
|
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$
|
0.5375
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2/12/2010
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Quarter ended September 30
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$
|
17.27
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$
|
12.61
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$
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0.5375
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11/13/2009
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Quarter ended June 30
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$
|
18.62
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$
|
12.75
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$
|
0.5125
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8/14/2009
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Quarter ended March 31
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|
$
|
16.91
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|
|
$
|
11.06
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|
$
|
0.5000
|
|
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5/15/2009
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
2008
|
|
|
|
|
|
|
|
|
|
|
|
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|
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Quarter ended December 31
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|
$
|
22.10
|
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|
$
|
8.34
|
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|
$
|
0.5000
|
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2/13/2009
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Quarter ended September 30
|
|
$
|
28.73
|
|
|
$
|
18.08
|
|
|
$
|
0.6600
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11/14/2008
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Quarter ended June 30
|
|
$
|
28.50
|
|
|
$
|
18.80
|
|
|
$
|
0.6881
|
|
|
|
8/14/2008
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Quarter ended March 31
|
|
$
|
21.50
|
|
|
$
|
17.92
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|
|
$
|
0.5755
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5/15/2008
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On February 17, 2010, the closing sales price of our common
units as reported by the NYSE was $20.20 per unit and we had
approximately 11 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 2009.
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.
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.
The board of directors of our general partner 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
even if we have not generated sufficient
46
ENCORE
ENERGY PARTNERS LP
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. The board of directors of our
general partner also may change our distribution philosophy
based on prevailing business conditions. There can be no
assurance that we will be able to distribute $0.4325 on a
quarterly basis or achieve a minimum coverage ratio of 1.10.
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ITEM 6.
|
SELECTED
FINANCIAL DATA
|
The following table shows selected historical financial data for
the periods and as of the periods indicated. The selected
historical financial data as of December 31, 2009 and 2008
and for the years ended December 31, 2009, 2008, and 2007
is derived from our audited financial statements. The selected
historical financial data as of December 31, 2007, 2006,
and 2005 and for the years ended December 31, 2006 and 2005
is derived from unaudited financial statements.
The following selected consolidated financial and operating data
should be read in conjunction with Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations and Item 8. Financial
Statements and Supplementary Data:
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Year Ended December 31,(a)
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2009
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2008
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2007
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2006
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2005
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(In thousands, except per unit amounts)
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Consolidated Statements of Operations Data:
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Revenues:
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|
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Oil
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$
|
127,611
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$
|
226,613
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$
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135,546
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|
|
$
|
40,900
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|
|
$
|
22,832
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|
Natural gas
|
|
|
22,428
|
|
|
|
53,944
|
|
|
|
39,119
|
|
|
|
40,461
|
|
|
|
52,631
|
|
Marketing(b)
|
|
|
478
|
|
|
|
5,324
|
|
|
|
8,582
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
150,517
|
|
|
|
285,881
|
|
|
|
183,247
|
|
|
|
81,361
|
|
|
|
75,463
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Expenses:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
41,676
|
|
|
|
44,752
|
|
|
|
33,980
|
|
|
|
14,094
|
|
|
|
8,594
|
|
Production, ad valorem, and severance taxes
|
|
|
16,099
|
|
|
|
28,147
|
|
|
|
17,712
|
|
|
|
7,026
|
|
|
|
5,584
|
|
Depletion, depreciation, and amortization
|
|
|
56,757
|
|
|
|
57,537
|
|
|
|
47,494
|
|
|
|
14,697
|
|
|
|
11,880
|
|
Exploration
|
|
|
3,132
|
|
|
|
196
|
|
|
|
126
|
|
|
|
22
|
|
|
|
312
|
|
General and administrative(c)
|
|
|
11,375
|
|
|
|
16,605
|
|
|
|
15,245
|
|
|
|
3,471
|
|
|
|
2,567
|
|
Marketing(b)
|
|
|
302
|
|
|
|
5,466
|
|
|
|
6,673
|
|
|
|
|
|
|
|
|
|
Derivative fair value loss (gain)(d)
|
|
|
47,464
|
|
|
|
(96,880
|
)
|
|
|
26,301
|
|
|
|
|
|
|
|
|
|
Other operating
|
|
|
3,099
|
|
|
|
1,670
|
|
|
|
1,426
|
|
|
|
1,318
|
|
|
|
1,374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
179,904
|
|
|
|
57,493
|
|
|
|
148,957
|
|
|
|
40,628
|
|
|
|
30,311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(29,387
|
)
|
|
|
228,388
|
|
|
|
34,290
|
|
|
|
40,733
|
|
|
|
45,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest(e)
|
|
|
(10,974
|
)
|
|
|
(6,969
|
)
|
|
|
(12,702
|
)
|
|
|
|
|
|
|
|
|
Other
|
|
|
46
|
|
|
|
99
|
|
|
|
196
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expenses
|
|
|
(10,928
|
)
|
|
|
(6,870
|
)
|
|
|
(12,506
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(40,315
|
)
|
|
|
221,518
|
|
|
|
21,784
|
|
|
|
40,733
|
|
|
|
45,152
|
|
Income tax provision
|
|
|
(14
|
)
|
|
|
(762
|
)
|
|
|
(78
|
)
|
|
|
(260
|
)
|
|
|
(27
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(40,329
|
)
|
|
$
|
220,756
|
|
|
$
|
21,706
|
|
|
$
|
40,473
|
|
|
$
|
45,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocation(f):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income (loss)
|
|
$
|
(39,913
|
)
|
|
$
|
163,070
|
|
|
$
|
(18,877
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income (loss)
|
|
$
|
(592
|
)
|
|
$
|
2,648
|
|
|
$
|
(394
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common unit(f):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(1.01
|
)
|
|
$
|
5.33
|
|
|
$
|
(0.79
|
)
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
(1.01
|
)
|
|
$
|
5.21
|
|
|
$
|
(0.79
|
)
|
|
|
|
|
|
|
|
|
Weighted average common units outstanding(f):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
39,366
|
|
|
|
30,568
|
|
|
|
23,877
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
39,366
|
|
|
|
31,938
|
|
|
|
23,877
|
|
|
|
|
|
|
|
|
|
Cash distributions declared per common unit
|
|
$
|
2.0500
|
|
|
$
|
2.3111
|
|
|
$
|
0.0530
|
|
|
|
|
|
|
|
|
|
47
ENCORE
ENERGY PARTNERS LP
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,(a)
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
Total Production Volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls)
|
|
|
2,337
|
|
|
|
2,533
|
|
|
|
2,232
|
|
|
|
684
|
|
|
|
437
|
|
Natural gas (Mcf)
|
|
|
6,097
|
|
|
|
6,219
|
|
|
|
5,751
|
|
|
|
5,990
|
|
|
|
6,639
|
|
Combined (BOE)
|
|
|
3,353
|
|
|
|
3,570
|
|
|
|
3,190
|
|
|
|
1,683
|
|
|
|
1,544
|
|
Average Realized Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
54.61
|
|
|
$
|
89.45
|
|
|
$
|
60.74
|
|
|
$
|
59.78
|
|
|
$
|
52.20
|
|
Natural gas ($/Mcf)
|
|
|
3.68
|
|
|
|
8.67
|
|
|
|
6.80
|
|
|
|
6.76
|
|
|
|
7.93
|
|
Combined ($/BOE)
|
|
|
44.75
|
|
|
|
78.59
|
|
|
|
57.44
|
|
|
|
48.36
|
|
|
|
48.88
|
|
Average Expenses per BOE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
12.43
|
|
|
$
|
12.54
|
|
|
$
|
10.65
|
|
|
$
|
8.38
|
|
|
$
|
5.57
|
|
Production, ad valorem, and severance taxes
|
|
|
4.80
|
|
|
|
7.88
|
|
|
|
5.55
|
|
|
|
4.18
|
|
|
|
3.62
|
|
Depletion, depreciation, and amortization
|
|
|
16.93
|
|
|
|
16.12
|
|
|
|
14.89
|
|
|
|
8.74
|
|
|
|
7.70
|
|
Exploration
|
|
|
0.93
|
|
|
|
0.05
|
|
|
|
0.04
|
|
|
|
0.01
|
|
|
|
0.20
|
|
General and administrative(c)
|
|
|
3.39
|
|
|
|
4.65
|
|
|
|
4.78
|
|
|
|
2.06
|
|
|
|
1.66
|
|
Derivative fair value loss (gain)(d)
|
|
|
14.16
|
|
|
|
(27.14
|
)
|
|
|
8.24
|
|
|
|
|
|
|
|
|
|
Other operating
|
|
|
0.92
|
|
|
|
0.47
|
|
|
|
0.45
|
|
|
|
0.78
|
|
|
|
0.89
|
|
Marketing, net of revenues(b)
|
|
|
(0.05
|
)
|
|
|
0.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Statements of Cash Flows Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
114,970
|
|
|
$
|
189,235
|
|
|
$
|
73,369
|
|
|
$
|
62,031
|
|
|
$
|
50,530
|
|
Investing activities
|
|
|
(41,085
|
)
|
|
|
(42,333
|
)
|
|
|
(524,772
|
)
|
|
|
(8,836
|
)
|
|
|
(104,480
|
)
|
Financing activities
|
|
|
(72,750
|
)
|
|
|
(146,286
|
)
|
|
|
451,406
|
|
|
|
(53,195
|
)
|
|
|
53,950
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,(a)
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls)
|
|
|
28,930
|
|
|
|
27,278
|
|
|
|
35,228
|
|
|
|
9,073
|
|
|
|
8,992
|
|
Natural gas (Mcf)
|
|
|
84,699
|
|
|
|
78,011
|
|
|
|
83,238
|
|
|
|
76,824
|
|
|
|
85,712
|
|
Combined (BOE)
|
|
|
43,047
|
|
|
|
40,280
|
|
|
|
49,101
|
|
|
|
21,877
|
|
|
|
23,277
|
|
Consolidated Balance Sheets Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital
|
|
$
|
15,558
|
|
|
$
|
71,563
|
|
|
$
|
9,439
|
|
|
$
|
3,128
|
|
|
$
|
10,174
|
|
Total assets
|
|
|
719,651
|
|
|
|
813,313
|
|
|
|
749,144
|
|
|
|
211,287
|
|
|
|
222,432
|
|
Long-term debt
|
|
|
255,000
|
|
|
|
150,000
|
|
|
|
47,500
|
|
|
|
|
|
|
|
|
|
Partners/Owners equity
|
|
|
406,004
|
|
|
|
619,351
|
|
|
|
640,066
|
|
|
|
197,810
|
|
|
|
210,352
|
|
|
|
|
(a) |
|
In March 2007, we acquired certain oil and natural gas
properties and related assets in the Elk Basin of Wyoming and
Montana. The operating results of these properties are included
with ours from the date of acquisition forward. |
|
(b) |
|
In conjunction with our Elk Basin acquisition in March 2007, we
acquired a crude oil pipeline and a natural gas pipeline. Prior
to March 2007, we had no marketing activities and, therefore, no
marketing revenues and expenses. |
|
(c) |
|
As a result of becoming a publicly traded entity in September
2007, we incur additional expenses such as fees associated with
annual and quarterly reports to unitholders, tax returns,
Schedule K-1
preparation and distribution, investor relations, registrar and
transfer agent fees, incremental insurance costs, and accounting
and legal services. In addition, Encore Operating receives a fee
based on our production for performing our administrative
services, and receives reimbursement of actual third-party
expenses incurred on our behalf. |
|
(d) |
|
In conjunction with our Elk Basin acquisition in March 2007, EAC
contributed floor contracts to us and we have subsequently
purchased additional derivative contracts based on our risk
management strategy. |
48
ENCORE
ENERGY PARTNERS LP
|
|
|
|
|
Prior to March 2007, we had no derivative contracts and,
therefore, no derivative fair value gains or losses. |
|
(e) |
|
In conjunction with our Elk Basin acquisition in March 2007, we
entered into two credit agreements. Prior to March 2007, we had
no indebtedness and, therefore, no interest expense. |
|
(f) |
|
Prior to the closing of our initial public offering in September
2007, EAC owned all of our general and limited partner
interests, with the exception of management incentive units
owned by certain executive officers of our general partner.
Accordingly, earnings per unit is not presented for periods
prior to our initial public offering. |
49
ENCORE
ENERGY PARTNERS LP
|
|
ITEM 7.
|
MANAGEMENTS
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 managements discussion and analysis of financial
condition and results of operations, the following are discussed
and analyzed:
|
|
|
|
|
Overview of Business
|
|
|
|
2009 Highlights
|
|
|
|
Results of Operations
|
|
|
|
|
|
Comparison of 2009 to 2008
|
|
|
|
Comparison of 2008 to 2007
|
|
|
|
|
|
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 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.
As previously discussed, on October 31, 2009, EAC, the
ultimate parent of our general partner, entered into the Merger
Agreement with Denbury, pursuant to which EAC will merge with
and into Denbury, with Denbury as the surviving entity. The
Merger Agreement, which was unanimously approved by EACs
Board of Directors and by Denburys Board of Directors,
provides for Denburys acquisition of all of the issued and
outstanding shares of EAC common stock. EAC and Denbury expect
to complete the Merger during the first quarter of 2010,
although completion by any particular date cannot be assured.
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. 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
50
ENCORE
ENERGY PARTNERS LP
under a subordinated credit agreement with EAP Operating, LLC, a
wholly owned subsidiary of EAC, and reduce outstanding
indebtedness under our revolving credit facility.
Upon the closing of our IPO, Encore Operating contributed
certain oil and natural gas properties and related assets in the
Permian Basin in West Texas (the Permian Basin
Assets) to us. 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. In March 2007, we acquired certain
oil and natural gas properties and related assets in the Elk
Basin in Wyoming and Montana (the Elk Basin Assets)
from an independent energy company. The results of operations of
the Elk Basin Assets have been included with ours from the date
of acquisition forward.
In February 2008, we acquired the Permian and Williston Basin
Assets from Encore Operating. In January 2009, we acquired the
Arkoma Basin Assets from Encore Operating. In June 2009, we
acquired the Williston Basin Assets from Encore Operating. In
August 2009, we acquired the Rockies and Permian Basin Assets
from Encore Operating. Because these assets were acquired from
an affiliate, the acquisitions were accounted for as
transactions between entities under common control, similar to a
pooling of interests, whereby the assets and liabilities of the
acquired properties were recorded at Encore Operatings
carrying value and our historical financial information was
recast to include the acquired properties for all periods in
which the properties were owned by Encore Operating.
Accordingly, our consolidated financial statements reflect our
historical results combined with those of the Permian and
Williston Basin Assets, the Arkoma Basin Assets, the Williston
Basin Assets, and the Rockies and Permian Basin Assets.
At December 31, 2009, our oil and natural gas properties
had estimated total proved reserves of 28.9 MMBbls of oil
and 84.7 Bcf of natural gas, based on 2009
12-month
average market prices of $61.18 per Bbl of oil and $3.83 per Mcf
of natural gas. On a BOE basis, our proved reserves were
43.0 MMBOE at December 31, 2009, of which
approximately 67 percent was oil, approximately
92 percent was proved developed, and approximately eight
percent was proved undeveloped.
Our financial results and ability to generate cash depend upon
many factors, particularly the price of oil and natural gas.
Average NYMEX prices deteriorated significantly in 2009. Our oil
wellhead differentials to NYMEX deteriorated slightly in 2009 as
we realized 88 percent of the average NYMEX oil price, as
compared to 90 percent in 2008. Our natural gas wellhead
differentials to NYMEX deteriorated slightly in 2009 as we
realized 92 percent of the average NYMEX natural gas price
in 2009, as compared to 96 percent in 2008. 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 commodity price risk by
entering into commodity derivative contracts for a portion of
our forecasted production. For a discussion of factors that
influence commodity prices and risks associated with our
commodity derivative contracts, please read Item 1A.
Risk Factors.
2009
Highlights
Our financial and operating results for 2009 included the
following:
|
|
|
|
|
In August, we acquired the Rockies and Permian Basin Assets from
Encore Operating for approximately $179.6 million in cash.
|
|
|
|
In July, we issued 9,430,000 common units at a price to the
public of $14.30 per common unit. We used the net proceeds of
approximately $129.2 million to fund a portion of the
purchase price of the Rockies and Permian Basin Assets.
|
|
|
|
In June, we acquired the Williston Basin Assets from Encore
Operating for approximately $25.2 million in cash.
|
|
|
|
In May, we acquired certain natural gas properties in the
Vinegarone Field in Val Verde County, Texas (the
Vinegarone Assets) from an independent energy
company for approximately $27.5 million in
|
51
ENCORE
ENERGY PARTNERS LP
|
|
|
|
|
cash. Our historical results of operations, reserve data, and
other operating and financial information only include
information related to the Vinegarone Assets from the date of
acquisition forward.
|
|
|
|
|
|
In May, we issued 2,760,000 common units at a price to the
public of $15.60 per common unit. We used the net proceeds of
approximately $40.9 million to fund the purchase price of
the Vinegarone Assets and a portion of the purchase price of the
Williston Basin Assets.
|
|
|
|
In January, we acquired the Arkoma Basin Assets from Encore
Operating for approximately $46.4 million in cash.
|
|
|
|
We invested $40.7 million in oil and natural gas
activities, of which $8.4 million was invested in
development, exploitation, and exploration activities, yielding
15 gross (1.8 net) productive wells, and $32.3 million
was invested in acquisitions, primarily related to our
Vinegarone Assets.
|
Results
of Operations
Comparison
of 2009 to 2008
Revenues. The following table provides the
components of our revenues for the periods indicated, as well as
each periods respective production volumes and average
prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Decrease
|
|
|
|
2009
|
|
|
2008
|
|
|
$
|
|
|
%
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
127,611
|
|
|
$
|
226,613
|
|
|
$
|
(99,002
|
)
|
|
|
(44
|
)%
|
Natural gas
|
|
|
22,428
|
|
|
|
53,944
|
|
|
|
(31,516
|
)
|
|
|
(58
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas revenues
|
|
|
150,039
|
|
|
|
280,557
|
|
|
|
(130,518
|
)
|
|
|
(47
|
)%
|
Marketing
|
|
|
478
|
|
|
|
5,324
|
|
|
|
(4,846
|
)
|
|
|
(91
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
150,517
|
|
|
$
|
285,881
|
|
|
$
|
(135,364
|
)
|
|
|
(47
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Averaged realized prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
54.61
|
|
|
$
|
89.45
|
|
|
$
|
(34.84
|
)
|
|
|
(39
|
)%
|
Natural gas ($/Mcf)
|
|
$
|
3.68
|
|
|
$
|
8.67
|
|
|
$
|
(4.99
|
)
|
|
|
(58
|
)%
|
Combined ($/BOE)
|
|
$
|
44.75
|
|
|
$
|
78.59
|
|
|
$
|
(33.84
|
)
|
|
|
(43
|
)%
|
Total production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
2,337
|
|
|
|
2,533
|
|
|
|
(196
|
)
|
|
|
(8
|
)%
|
Natural gas (MMcf)
|
|
|
6,097
|
|
|
|
6,219
|
|
|
|
(122
|
)
|
|
|
(2
|
)%
|
Combined (MBOE)
|
|
|
3,353
|
|
|
|
3,570
|
|
|
|
(217
|
)
|
|
|
(6
|
)%
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls/D)
|
|
|
6,402
|
|
|
|
6,922
|
|
|
|
(520
|
)
|
|
|
(8
|
)%
|
Natural gas (Mcf/D)
|
|
|
16,703
|
|
|
|
16,991
|
|
|
|
(288
|
)
|
|
|
(2
|
)%
|
Combined (BOE/D)
|
|
|
9,186
|
|
|
|
9,754
|
|
|
|
(568
|
)
|
|
|
(6
|
)%
|
Average NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
61.95
|
|
|
$
|
99.75
|
|
|
$
|
(37.80
|
)
|
|
|
(38
|
)%
|
Natural gas (per Mcf)
|
|
$
|
3.99
|
|
|
$
|
9.04
|
|
|
$
|
(5.05
|
)
|
|
|
(56
|
)%
|
Oil revenues decreased 44 percent from $226.6 million
in 2008 to $127.6 million in 2009 as a result of a $34.84
per Bbl decrease in our average realized oil price and a
196 MBbls decrease in our oil production volumes. Our lower
average realized oil price decreased oil revenues by
approximately $81.4 million and was primarily due to a
lower average NYMEX price, which decreased from $99.75 per Bbl
in 2008 to $61.95 per
52
ENCORE
ENERGY PARTNERS LP
Bbl in 2009. Our lower oil production volumes decreased oil
revenues by approximately $17.6 million and was primarily
due to natural production declines in our Elk Basin field.
Natural gas revenues decreased 58 percent from
$53.9 million in 2008 to $22.4 million in 2009 as a
result of a $4.99 per Mcf decrease in our average realized
natural gas price and a 122 MMcf decrease in our natural
gas production volumes. Our lower average realized natural gas
price decreased natural gas revenues by approximately
$30.5 million and was primarily due to a lower average
NYMEX price, which decreased from $9.04 per Mcf in 2008 to $3.99
per Mcf in 2009. Our lower natural gas production volumes
decreased natural gas revenues by approximately
$1.1 million and was primarily due to natural production
declines in our Crockett County properties.
The following table shows the relationship between our average
oil and natural gas realized prices as a percentage of average
NYMEX prices for the periods indicated. Management uses the
realized price to NYMEX margin analysis to analyze trends in our
oil and natural gas revenues.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Average realized oil price ($/Bbl)
|
|
$
|
54.61
|
|
|
$
|
89.45
|
|
Average NYMEX ($/Bbl)
|
|
$
|
61.95
|
|
|
$
|
99.75
|
|
Differential to NYMEX
|
|
$
|
(7.34
|
)
|
|
$
|
(10.30
|
)
|
Average realized oil price to NYMEX percentage
|
|
|
88
|
%
|
|
|
90
|
%
|
Average realized natural gas price ($/Mcf)
|
|
$
|
3.68
|
|
|
$
|
8.67
|
|
Average NYMEX ($/Mcf)
|
|
$
|
3.99
|
|
|
$
|
9.04
|
|
Differential to NYMEX
|
|
$
|
(0.31
|
)
|
|
$
|
(0.37
|
)
|
Average realized natural gas price to NYMEX percentage
|
|
|
92
|
%
|
|
|
96
|
%
|
Our average realized oil price as a percentage of the average
NYMEX was 88 percent for 2009 as compared to
90 percent for 2008.
Our average realized natural gas price as a percentage of the
average NYMEX price was 92 percent for 2009 as compared to
96 percent for 2008. The natural gas index prices related
to our West Texas natural gas contracts widened in their
relationship to NYMEX causing a larger differential in 2009.
Marketing revenues decreased 91 percent from
$5.3 million in 2008 to $0.5 million in 2009 primarily
as a result of a reduction in natural gas throughput in our
Wildhorse pipeline. 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.
53
ENCORE
ENERGY PARTNERS LP
Expenses. The following table summarizes our
expenses for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase/ (Decrease)
|
|
|
|
2009
|
|
|
2008
|
|
|
$
|
|
|
%
|
|
|
Expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
41,676
|
|
|
$
|
44,752
|
|
|
$
|
(3,076
|
)
|
|
|
|
|
Production, ad valorem, and severance taxes
|
|
|
16,099
|
|
|
|
28,147
|
|
|
|
(12,048
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production expenses
|
|
|
57,775
|
|
|
|
72,899
|
|
|
|
(15,124
|
)
|
|
|
(21
|
)%
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization
|
|
|
56,757
|
|
|
|
57,537
|
|
|
|
(780
|
)
|
|
|
|
|
Exploration
|
|
|
3,132
|
|
|
|
196
|
|
|
|
2,936
|
|
|
|
|
|
General and administrative
|
|
|
11,375
|
|
|
|
16,605
|
|
|
|
(5,230
|
)
|
|
|
|
|
Marketing
|
|
|
302
|
|
|
|
5,466
|
|
|
|
(5,164
|
)
|
|
|
|
|
Derivative fair value loss (gain)
|
|
|
47,464
|
|
|
|
(96,880
|
)
|
|
|
144,344
|
|
|
|
|
|
Other operating
|
|
|
3,099
|
|
|
|
1,670
|
|
|
|
1,429
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating
|
|
|
179,904
|
|
|
|
57,493
|
|
|
|
122,411
|
|
|
|
213
|
%
|
Interest
|
|
|
10,974
|
|
|
|
6,969
|
|
|
|
4,005
|
|
|
|
|
|
Income tax provision
|
|
|
14
|
|
|
|
762
|
|
|
|
(748
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
$
|
190,892
|
|
|
$
|
65,224
|
|
|
$
|
125,668
|
|
|
|
193
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses (per BOE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
12.43
|
|
|
$
|
12.54
|
|
|
$
|
(0.11
|
)
|
|
|
|
|
Production, ad valorem, and severance taxes
|
|
|
4.80
|
|
|
|
7.88
|
|
|
|
(3.08
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production expenses
|
|
|
17.23
|
|
|
|
20.42
|
|
|
|
(3.19
|
)
|
|
|
(16
|
)%
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization
|
|
|
16.93
|
|
|
|
16.12
|
|
|
|
0.81
|
|
|
|
|
|
Exploration
|
|
|
0.93
|
|
|
|
0.05
|
|
|
|
0.88
|
|
|
|
|
|
General and administrative
|
|
|
3.39
|
|
|
|
4.65
|
|
|
|
(1.26
|
)
|
|
|
|
|
Marketing
|
|
|
0.09
|
|
|
|
1.53
|
|
|
|
(1.44
|
)
|
|
|
|
|
Derivative fair value loss (gain)
|
|
|
14.16
|
|
|
|
(27.14
|
)
|
|
|
41.30
|
|
|
|
|
|
Other operating
|
|
|
0.92
|
|
|
|
0.47
|
|
|
|
0.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating
|
|
|
53.65
|
|
|
|
16.10
|
|
|
|
37.55
|
|
|
|
233
|
%
|
Interest
|
|
|
3.27
|
|
|
|
1.95
|
|
|
|
1.32
|
|
|
|
|
|
Income tax provision
|
|
|
|
|
|
|
0.21
|
|
|
|
(0.21
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
$
|
56.92
|
|
|
$
|
18.26
|
|
|
$
|
38.66
|
|
|
|
212
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expenses. Total production expenses
decreased 21 percent from $72.9 million in 2008 to
$57.8 million in 2009. Our production margin decreased
125 percent from $207.7 million in 2008 to
$92.3 million in 2009. Total oil and natural gas wellhead
revenues per BOE decreased by 43 percent and total
production expenses per BOE decreased by 16 percent. On a
per BOE basis, our production margin decreased 108 percent
to $27.52 per BOE in 2009 as compared to $58.17 per BOE in 2008.
54
ENCORE
ENERGY PARTNERS LP
Production expense attributable to LOE decreased
$3.1 million from $44.8 million in 2008 to
$41.7 million in 2009 as a result of a lower production
volumes and a $0.11 decrease in the per BOE rate. Our lower
production volumes decreased LOE by approximately
$2.7 million. Our lower average LOE per BOE rate decreased
LOE by approximately $0.3 million and was primarily due to
lower prices paid to oilfield service companies and suppliers
and decreases in natural gas prices resulting in lower
electricity costs and gas plant fuel costs.
Production expense attributable to production taxes decreased
$12.0 million from $28.1 million in 2008 to
$16.1 million in 2009 primarily due to lower wellhead
revenues, which exclude the effects of commodity derivative
contracts. As a percentage of wellhead revenues, production
taxes increased to 10.7 percent in 2009 as compared to
10.0 percent in 2008 primarily due to higher ad valorem
taxes, which are based on production volumes as opposed to a
percentage of wellhead revenues.
Depletion, depreciation, and amortization
(DD&A) expense. DD&A
expense decreased $0.8 million from $57.5 million in
2008 to $56.8 million in 2009, as a result of a
217 MBOE decrease in production volumes, partially offset
by a $0.81 increase in the per BOE rate. Our lower production
volumes decreased DD&A expense by approximately
$3.5 million. Our higher average DD&A per BOE rate
increased DD&A expense by approximately $2.7 million
and was primarily due to the decrease in our proved reserves at
the beginning of 2009 as a result of lower average commodity
prices.
Exploration expense. Exploration expense
increased $2.9 million from $0.2 million in 2008 to
$3.1 million in 2009. During 2009, we expensed 1.0 net
exploratory dry hole totaling $3.0 million. No dry holes
were expensed in 2008.
General and administrative (G&A)
expense. G&A expense decreased
$5.2 million from $16.6 million in 2008 to
$11.4 million 2009 primarily due to a decrease in non-cash
equity-based compensation expense.
Marketing expense. Marketing expense decreased
$5.2 million from $5.5 million in 2008 to
$0.3 million in 2008 as a result of a reduction in natural
gas throughput in our Wildhorse pipeline. 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.
Derivative fair value loss (gain). During
2009, we recorded a $47.5 million derivative fair value
loss as compared to a $96.9 million derivative fair value
gain in 2008, the components of which were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase /
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
|
(In thousands)
|
|
|
Ineffectiveness
|
|
$
|
2
|
|
|
$
|
372
|
|
|
$
|
(370
|
)
|
Mark-to-market
loss (gain)
|
|
|
94,438
|
|
|
|
(101,595
|
)
|
|
|
196,033
|
|
Premium amortization
|
|
|
23,245
|
|
|
|
8,936
|
|
|
|
14,309
|
|
Settlements
|
|
|
(70,221
|
)
|
|
|
(4,593
|
)
|
|
|
(65,628
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative fair value loss (gain)
|
|
$
|
47,464
|
|
|
$
|
(96,880
|
)
|
|
$
|
144,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense. Interest expense increased
$4.0 million from $7.0 million in 2008 to
$11.0 million in 2009 primarily due to higher weighted
average outstanding borrowings under our revolving credit
facility and an increase in LIBOR. Our weighted average interest
rate for 2009 was 5.0 percent as compared to
4.8 percent for 2008.
55
ENCORE
ENERGY PARTNERS LP
Comparison
of 2008 to 2007
Revenues. The following table provides the
components of our revenues for the periods indicated, as well as
each periods respective production volumes and average
prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase/ (Decrease)
|
|
|
|
2008
|
|
|
2007
|
|
|
$
|
|
|
%
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
226,613
|
|
|
$
|
135,546
|
|
|
$
|
91,067
|
|
|
|
67
|
%
|
Natural gas
|
|
|
53,944
|
|
|
|
39,119
|
|
|
|
14,825
|
|
|
|
38
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas revenues
|
|
|
280,557
|
|
|
|
174,665
|
|
|
|
105,892
|
|
|
|
61
|
%
|
Marketing
|
|
|
5,324
|
|
|
|
8,582
|
|
|
|
(3,258
|
)
|
|
|
(38
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
285,881
|
|
|
$
|
183,247
|
|
|
$
|
102,634
|
|
|
|
56
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Averaged realized prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
89.45
|
|
|
$
|
60.74
|
|
|
$
|
28.71
|
|
|
|
47
|
%
|
Natural gas ($/Mcf)
|
|
$
|
8.67
|
|
|
$
|
6.80
|
|
|
$
|
1.87
|
|
|
|
28
|
%
|
Combined ($/BOE)
|
|
$
|
78.59
|
|
|
$
|
54.75
|
|
|
$
|
23.84
|
|
|
|
44
|
%
|
Total production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
2,533
|
|
|
|
2,232
|
|
|
|
301
|
|
|
|
13
|
%
|
Natural gas (MMcf)
|
|
|
6,219
|
|
|
|
5,751
|
|
|
|
468
|
|
|
|
8
|
%
|
Combined (MBOE)
|
|
|
3,570
|
|
|
|
3,190
|
|
|
|
380
|
|
|
|
12
|
%
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl/D)
|
|
|
6,922
|
|
|
|
6,114
|
|
|
|
808
|
|
|
|
13
|
%
|
Natural gas (Mcf/D)
|
|
|
16,991
|
|
|
|
15,756
|
|
|
|
1,235
|
|
|
|
8
|
%
|
Combined (BOE/D)
|
|
|
9,754
|
|
|
|
8,740
|
|
|
|
1,014
|
|
|
|
12
|
%
|
Average NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
99.75
|
|
|
$
|
72.45
|
|
|
$
|
27.30
|
|
|
|
38
|
%
|
Natural gas (per Mcf)
|
|
$
|
9.04
|
|
|
$
|
6.86
|
|
|
$
|
2.18
|
|
|
|
32
|
%
|
Oil revenues increased 67 percent from $135.5 million
in 2007 to $226.6 million in 2008 as a result of higher
average realized oil prices, which increased oil revenues by
approximately $72.7 million, and higher oil production
volumes of 301 MBbls, which increased oil revenues by
approximately $18.3 million. Our average realized oil price
increased $28.71 per Bbl from 2007 to 2008 primarily as a result
of the increase in the average NYMEX price from $72.45 per Bbl
for 2007 to $99.75 per Bbl for 2008. The increase in oil
production volumes was primarily due to a full year of
production from our Elk Basin Assets, which were acquired in
March 2007. For 2008, approximately 49 percent of our oil
production was from our Elk Basin Assets.
Natural gas revenues increased 38 percent from
$39.1 million in 2007 to $53.9 million in 2008 as a
result of higher average realized natural gas prices, which
increased natural gas revenues by approximately
$11.6 million, and higher natural gas production volumes of
468 MMcf, which increased natural gas revenues by
approximately $3.2 million. Our average realized natural
gas price increased $1.87 per Mcf from 2007 to 2008 primarily as
a result of the increase in the average NYMEX price from $6.86
per Mcf for 2007 to $9.04 per Mcf for 2008. The increase in
natural gas production volumes was primarily due to wells
drilled in the Permian Basin during the second half of 2007 and
the first half of 2008.
56
ENCORE
ENERGY PARTNERS LP
The following table shows the relationship between our average
oil and natural gas realized prices as a percentage of average
NYMEX prices for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Average realized oil price ($/Bbl)
|
|
$
|
89.45
|
|
|
$
|
60.74
|
|
Average NYMEX ($/Bbl)
|
|
$
|
99.75
|
|
|
$
|
72.45
|
|
Differential to NYMEX
|
|
$
|
(10.30
|
)
|
|
$
|
(11.71
|
)
|
Average realized oil price to NYMEX percentage
|
|
|
90
|
%
|
|
|
84
|
%
|
Average realized natural gas price ($/Mcf)
|
|
$
|
8.67
|
|
|
$
|
6.80
|
|
Average NYMEX ($/Mcf)
|
|
$
|
9.04
|
|
|
$
|
6.86
|
|
Differential to NYMEX
|
|
$
|
(0.37
|
)
|
|
$
|
(0.06
|
)
|
Average realized natural gas price to NYMEX percentage
|
|
|
96
|
%
|
|
|
99
|
%
|
Our average realized oil price as a percentage of the average
NYMEX price improved to 90 percent for 2008 from
84 percent for 2007 as a result of improved pricing in the
Rocky Mountain area. Our average realized natural gas price as a
percentage of the average NYMEX price deteriorated slightly to
96 percent for 2008 from 99 percent for 2007.
Marketing revenues decreased 38 percent from
$8.6 million in 2007 to $5.3 million in 2008 primarily
as a result of a reduction in natural gas throughput in our
Wildhorse pipeline. In March 2007, ENP acquired a natural gas
pipeline from Anadarko as part of the Big Horn Basin asset
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.
57
ENCORE
ENERGY PARTNERS LP
Expenses. The following table summarizes our
expenses for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
Year Ended December 31,
|
|
|
(Decrease)
|
|
|
|
2008
|
|
|
2007
|
|
|
$
|
|
|
%
|
|
|
Expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
44,752
|
|
|
$
|
33,980
|
|
|
$
|
10,772
|
|
|
|
|
|
Production, ad valorem, and severance taxes
|
|
|
28,147
|
|
|
|
17,712
|
|
|
|
10,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production expenses
|
|
|
72,899
|
|
|
|
51,692
|
|
|
|
21,207
|
|
|
|
41
|
%
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization
|
|
|
57,537
|
|
|
|
47,494
|
|
|
|
10,043
|
|
|
|
|
|
Exploration
|
|
|
196
|
|
|
|
126
|
|
|
|
70
|
|
|
|
|
|
General and administrative
|
|
|
16,605
|
|
|
|
15,245
|
|
|
|
1,360
|
|
|
|
|
|
Marketing
|
|
|
5,466
|
|
|
|
6,673
|
|
|
|
(1,207
|
)
|
|
|
|
|
Derivative fair value loss (gain)
|
|
|
(96,880
|
)
|
|
|
26,301
|
|
|
|
(123,181
|
)
|
|
|
|
|
Other operating
|
|
|
1,670
|
|
|
|
1,426
|
|
|
|
244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating
|
|
|
57,493
|
|
|
|
148,957
|
|
|
|
(91,464
|
)
|
|
|
(61
|
)%
|
Interest
|
|
|
6,969
|
|
|
|
12,702
|
|
|
|
(5,733
|
)
|
|
|
|
|
Income tax provision
|
|
|
762
|
|
|
|
78
|
|
|
|
684
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
$
|
65,224
|
|
|
$
|
161,737
|
|
|
$
|
(96,513
|
)
|
|
|
(60
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses (per BOE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
12.54
|
|
|
$
|
10.65
|
|
|
$
|
1.89
|
|
|
|
|
|
Production, ad valorem, and severance taxes
|
|
|
7.88
|
|
|
|
5.55
|
|
|
|
2.33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production expenses
|
|
|
20.42
|
|
|
|
16.20
|
|
|
|
4.22
|
|
|
|
26
|
%
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization
|
|
|
16.12
|
|
|
|
14.89
|
|
|
|
1.23
|
|
|
|
|
|
Exploration
|
|
|
0.05
|
|
|
|
0.04
|
|
|
|
0.01
|
|
|
|
|
|
General and administrative
|
|
|
4.65
|
|
|
|
4.78
|
|
|
|
(0.13
|
)
|
|
|
|
|
Marketing
|
|
|
1.53
|
|
|
|
2.09
|
|
|
|
(0.56
|
)
|
|
|
|
|
Derivative fair value loss
|
|
|
(27.14
|
)
|
|
|
8.24
|
|
|
|
(35.38
|
)
|
|
|
|
|
Other operating
|
|
|
0.47
|
|
|
|
0.45
|
|
|
|
0.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating
|
|
|
16.10
|
|
|
|
46.69
|
|
|
|
(30.59
|
)
|
|
|
(66
|
)%
|
Interest
|
|
|
1.95
|
|
|
|
3.98
|
|
|
|
(2.03
|
)
|
|
|
|
|
Income tax provision
|
|
|
0.21
|
|
|
|
0.02
|
|
|
|
0.19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
$
|
18.26
|
|
|
$
|
50.69
|
|
|
$
|
(32.43
|
)
|
|
|
(64
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expenses. Total production expenses
increased 41 percent from $51.7 million in 2007 to
$72.9 million in 2008 as a result of higher production
volumes and an increase in the per BOE rate. Our production
margin increased by $84.7 million (69 percent) to
$207.7 million for 2008 as compared to $123.0 million
for 2007. On a per BOE basis, our production margin increased
51 percent to $58.17 per BOE for 2008 as compared to $38.55
per BOE for 2007. Total oil and natural gas revenues per BOE
increased by 44 percent while total production expenses per
BOE increased by 26 percent.
58
ENCORE
ENERGY PARTNERS LP
Production expense attributable to LOE increased
$10.8 million from $34.0 million in 2007 to
$44.8 million in 2008 as a result of a $1.89 increase in
the average per BOE rate, which contributed approximately
$6.8 million of additional LOE, and an increase in
production volumes, which contributed approximately
$4.0 million of additional LOE. The increase in our average
LOE per BOE rate was primarily due to the increase in natural
gas prices and increases in prices paid to oilfield service
companies and suppliers. In West Texas, the higher gas prices
increased the electrical rates charged to our producing
properties, and at the Elk Basin gas plant, the charges
associated with the fuel gas were also higher.
Production taxes increased $10.4 million from
$17.7 million in 2007 to $28.1 million in 2008
primarily due to higher wellhead revenues. As a percentage of
wellhead revenues, production taxes remained approximately
constant at 10.0 percent for 2008 as compared to
10.1 percent in 2007.
DD&A expense. DD&A expense increased
$10.0 million from $47.5 million in 2007 to
$57.5 million in 2008 as a result of higher production
volumes, which contributed approximately $5.7 million of
additional DD&A expense, and an increase in the per BOE
rate of $1.23, which contributed approximately $4.4 million
of additional DD&A expense. The increase in our average
DD&A per BOE rate was primarily due to higher costs
incurred resulting from increases in rig rate, pipe costs, and
acquisition costs, and the decrease in our total proved reserves
to 40.3 MMBOE as of December 31, 2008 as compared to
49.1 MMBOE as of December 31, 2007.
G&A expense. G&A expense increased
$1.4 million from $15.2 million in 2007 to
$16.6 million primarily due to a higher per BOE rate
allocated by EAC to the Rockies and Permian Basin Operations
than our historical per BOE rate.
Marketing expense. Marketing expense decreased
$1.2 million from $6.7 million in 2007 to
$5.5 million in 2008 as a result of a reduction in natural
gas throughput in our Wildhorse pipeline. In March 2007, ENP
acquired a natural gas pipeline from Anadarko as part of the Big
Horn Basin asset 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.
Derivative fair value loss (gain). During
2008, we recorded a $96.9 million derivative fair value
gain as compared to a $26.3 million loss in 2007, the
components of which were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase /
|
|
|
|
2008
|
|
|
2007
|
|
|
(Decrease)
|
|
|
|
(In thousands)
|
|
|
Ineffectiveness
|
|
$
|
372
|
|
|
$
|
|
|
|
$
|
372
|
|
Mark-to-market
loss (gain)
|
|
|
(101,595
|
)
|
|
|
23,470
|
|
|
|
(125,065
|
)
|
Premium amortization
|
|
|
8,936
|
|
|
|
4,073
|
|
|
|
4,863
|
|
Settlements
|
|
|
(4,593
|
)
|
|
|
(1,242
|
)
|
|
|
(3,351
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative fair value loss (gain)
|
|
$
|
(96,880
|
)
|
|
$
|
26,301
|
|
|
$
|
(123,181
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense. Interest expense decreased
$5.7 million from $12.7 million in 2007 to
$7.0 million in 2009, primarily due to (1) the use of
net proceeds from our IPO to reduce weighted average outstanding
borrowings on our revolving credit facility and subordinated
credit agreement, (2) a reduction in LIBOR, and
(3) our use of interest rate swaps to fix the rate on a
portion of outstanding borrowings on our revolving credit
facility. Our weighted average interest rate for 2008 was
4.8 percent as compared to 8.9 percent for 2007.
Capital Commitments, Capital Resources, and
Liquidity
Capital commitments. Our primary uses of cash
are:
|
|
|
|
|
Distributions to unitholders;
|
|
|
|
Development, exploitation, and exploration of oil and natural
gas properties;
|
59
ENCORE
ENERGY PARTNERS LP
|
|
|
|
|
Acquisitions of oil and natural gas properties;
|
|
|
|
Funding of working capital; and
|
|
|
|
Contractual obligations.
|
Distributions to unitholders. Our partnership
agreement requires that, within 45 days after the end of
each quarter, we distribute all of our available cash (as
defined in the partnership agreement). Our available cash is our
cash on hand at the end of a quarter after the payment of our
expenses and the establishment of reserves for future capital
expenditures and operational needs. During 2009, 2008, and 2007,
we distributed $81.7 million, $74.4 million, and
$1.3 million, respectively, to our unitholders.
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.
The board of directors of our general partner 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
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. The board of directors of our general partner 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.
Development, exploitation, and exploration of oil and natural
gas properties. The following table summarizes
our costs incurred related to development, exploitation, and
exploration activities for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Development and exploitation
|
|
$
|
7,197
|
|
|
$
|
31,450
|
|
|
$
|
21,277
|
|
Exploration
|
|
|
1,223
|
|
|
|
8,223
|
|
|
|
10,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
8,420
|
|
|
$
|
39,673
|
|
|
$
|
31,277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our development and exploitation expenditures primarily relate
to drilling development and infill wells, workovers of existing
wells, and field related facilities. Our development and
exploitation capital for 2009 yielded 9 gross (1.2 net)
productive wells and no dry holes. Our exploration expenditures
primarily relate to drilling exploratory wells, seismic costs,
delay rentals, and geological and geophysical costs. Our
exploration capital for 2009 yielded 6 gross (0.6 net)
productive wells and 1 gross (1.0 net) dry hole. Please
read Items 1 and 2. Business and
Properties Development Results for a
description of the areas in which we drilled wells during 2009.
Acquisitions of oil and natural gas properties and leasehold
acreage. The following table summarizes our costs
incurred related to oil and natural gas property acquisitions
for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Acquisitions of proved property
|
|
$
|
32,265
|
|
|
$
|
5,940
|
|
|
$
|
498,057
|
|
Acquisitions of leasehold acreage
|
|
|
1
|
|
|
|
|
|
|
|
105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
32,266
|
|
|
$
|
5,940
|
|
|
$
|
498,162
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In August 2009, we acquired the Rockies and Permian Basin Assets
from Encore Operating for approximately $179.6 million in
cash. In June 2009, we acquired the Williston Basin Assets from
Encore
60
ENCORE
ENERGY PARTNERS LP
Operating for approximately $25.2 million in cash. In
January 2009, we acquired the Arkoma Basin Assets from Encore
Operating for approximately $46.4 million in cash. In
February 2008, we acquired the Permian and Williston Basin
Assets from Encore Operating for total consideration of
approximately $125.0 million in cash and the issuance of
6,884,776 ENP common units to Encore Operating. In determining
the total purchase price, the common units were valued at
$125.0 million. However, no accounting value was ascribed
to the common units as the cash consideration exceeded Encore
Operatings carrying value of the properties. Because these
assets were acquired from an affiliate, the acquisitions were
accounted for as transactions between entities under common
control, similar to a pooling of interests, whereby the assets
and liabilities of the acquired properties were recorded at
Encore Operating carrying value and our historical financial
information was recast to include the acquired properties for
all periods in which the properties were owned by Encore
Operating.
In May 2009, we acquired the Vinegarone Assets from an
independent energy company for approximately $27.5 million
in cash. In May 2008, we acquired an existing net profits
interest in certain of our proved properties in the Permian
Basin in West Texas from an independent energy company for
283,700 ENP common units, which were valued at approximately
$5.8 million at the time of the acquisition. In March 2007,
we acquired the Elk Basin Assets from an independent energy
company for approximately $330.7 million in cash. Also in
March 2007, we acquired certain properties in the Gooseberry
field for approximately $62.9 million. In April 2007, we
acquired certain properties in the Williston Basin for
approximately $102.0 million. The Gooseberry and Williston
Basin properties were acquired from EAC and, as the acquisition
was accounted for as a transaction between entities under common
control, the purchase price of the properties are shown in the
period the properties were originally purchased by EAC.
Funding of working capital. As of
December 31, 2009 and 2008, our working capital (defined as
total current assets less total current liabilities) was
$15.6 million and $71.6 million, respectively. The
decrease was primarily due to higher oil prices at
December 31, 2009 as compared to December 31, 2008,
which negatively impacted the fair value of our outstanding oil
derivative contracts.
For 2010, we expect working capital to remain positive primarily
due to the fair value of our outstanding commodity derivative
contracts. We anticipate cash reserves to be close to zero
because we intend to distribute available cash to unitholders
and reduce outstanding borrowings under our revolving credit
facility. However, we have availability under our revolving
credit facility to fund our obligations as they become due. Our
production volumes, commodity prices, and differentials for oil
and natural gas will be the largest variables affecting our
working capital. Our operating cash flow is determined in large
part by production volumes and commodity prices. Given our
current commodity derivative contracts, assuming relatively
stable commodity prices and constant production volumes, our
operating cash flow should remain positive for 2010.
Our capital expenditures are largely discretionary, and the
amount of funds devoted to any particular activity may increase
or decrease significantly, depending on available opportunities,
timing of projects, and market conditions. We plan to finance
our ongoing expenditures using internally generated cash flow
and availability under our revolving credit facility.
Off-balance sheet arrangements. We have no
investments in unconsolidated entities or persons that could
materially affect our liquidity or the availability of capital
resources. We have no off-balance sheet arrangements that are
material to our financial position or results of operations.
61
ENCORE
ENERGY PARTNERS LP
Contractual obligations. The following table
provides our contractual obligations and commitments at
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
Contractual Obligations and Commitments
|
|
Total
|
|
|
2010
|
|
|
2011 - 2012
|
|
|
2013 - 2014
|
|
|
Thereafter
|
|
|
|
(In thousands)
|
|
|
Revolving credit facility(a)
|
|
$
|
270,908
|
|
|
$
|
7,070
|
|
|
$
|
263,838
|
|
|
$
|
|
|
|
$
|
|
|
Commodity derivative contracts(b)
|
|
|
9,635
|
|
|
|
|
|
|
|
9,635
|
|
|
|
|
|
|
|
|
|
Interest rate swaps(c)
|
|
|
3,669
|
|
|
|
3,320
|
|
|
|
349
|
|
|
|
|
|
|
|
|
|
Development commitments(d)
|
|
|
1,536
|
|
|
|
1,536
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases and commitments(e)
|
|
|
1,888
|
|
|
|
687
|
|
|
|
1,201
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations(f)
|
|
|
43,475
|
|
|
|
573
|
|
|
|
1,147
|
|
|
|
1,160
|
|
|
|
40,595
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
331,111
|
|
|
$
|
13,186
|
|
|
$
|
276,170
|
|
|
$
|
1,160
|
|
|
$
|
40,595
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes principal and projected interest payments. Please read
Note 6 of Notes to Consolidated Financial Statements
included in Item 8. Financial Statements and
Supplementary Data for additional information regarding
our long-term debt. |
|
(b) |
|
At December 31, 2009, our commodity derivative contracts
were in a net asset position. Please read Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
and Note 10 of Notes to Consolidated Financial Statements
included in Item 8. Financial Statements and
Supplementary Data for additional information regarding
our commodity derivative contracts. |
|
(c) |
|
Represents net liabilities for interest rate swaps, the ultimate
settlement of which are unknown because they are subject to
continuing market risk. Please read Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
and Note 10 of Notes to Consolidated Financial Statements
included in Item 8. Financial Statements and
Supplementary Data for additional information regarding
our interest rate swaps. |
|
(d) |
|
Represents authorized purchases for work in process. Also at
December 31, 2009, we had $18.3 million of authorized
purchases not placed to vendors (authorized AFEs), which were
not accrued and are excluded from the above table, but are
budgeted for and expected to be made unless circumstances change. |
|
(e) |
|
Represents equipment obligations that have non-cancelable lease
terms in excess of one year. Please read Note 4 of Notes to
Consolidated Financial Statements included in Item 8.
Financial Statements and Supplementary Data for additional
information regarding our operating leases. |
|
(f) |
|
Represents the undiscounted future plugging and abandonment
expenses on oil and natural gas properties and related
facilities disposal at the end of field life. Please read Note 5
of Notes to Consolidated Financial Statements included in
Item 8. Financial Statements and Supplementary
Data for additional information regarding our asset
retirement obligations. |
Other contingencies and commitments. Encore
Operating provides administrative services for us, such as
accounting, corporate development, finance, land, legal, and
engineering, pursuant to an administrative services agreement.
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. From April 1, 2008 to
March 31, 2009, the administrative fee was $1.88 per BOE of
our production. Effective April 1, 2009, the administrative
fee increased to $2.02 per BOE of our production as a result of
the COPAS Wage Index Adjustment. We also reimburse Encore
Operating for 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.
62
ENCORE
ENERGY PARTNERS LP
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 acquire 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 the board of directors of our
general partner upon the recommendation of its conflicts
committee; and
|
|
|
|
otherwise as agreed upon by Encore Operating and our general
partner, with the approval of the conflicts committee of the
board of directors of our general partner.
|
Capital
resources
Cash flows from operating activities. Cash
provided by operating activities decreased $74.2 million
from $189.2 million in 2008 to $115.0 million in 2009,
primarily due to a decrease in our production margin, partially
offset by decreased settlements on our commodity derivative
contracts as a result of lower average oil prices in 2009 as
compared to 2008. Cash provided by operating activities
increased $115.8 million from $73.4 million in 2007 to
$189.2 million in 2007, primarily due to an increase in our
production margin, partially offset by increased settlements on
our commodity derivative contracts as a result of higher
commodity prices in the first half of 2008.
Cash flows from investing activities. Cash
used in investing activities decreased $1.2 million from
$42.3 million in 2008 to $41.1 million in 2009,
primarily due to a $32.8 million decrease in amounts paid
to develop oil and natural gas properties, partially offset by a
$31.7 million increase in amounts paid to acquire oil and
natural gas properties, namely the Vinegarone Assets.
Cash used in investing activities decreased $482.5 million
from $524.8 million in 2007 to $42.3 million in 2008,
primarily due to a $495.0 million decrease in amounts paid
for the acquisition of oil and natural gas properties, partially
offset by a $12.8 million increase in amounts paid to
develop oil and natural gas properties. In March 2007, we
acquired the Elk Basin Assets for approximately
$330.7 million. Also in March 2007, we acquired certain
properties in the Gooseberry field for approximately
$62.9 million. In April 2007, we acquired certain
properties in the Williston Basin for approximately
$102.0 million. The Gooseberry and Williston Basin
properties were acquired from EAC and, as the acquisition was
accounted for as a transaction between entities under common
control, the purchase price of the properties are shown in the
period the properties were originally purchased by EAC.
Cash flows from financing activities. Our cash
flows from financing activities consist primarily of proceeds
from and payments on long-term debt, distributions to
unitholders, and issuances of our common units. We periodically
draw on our revolving credit facility to fund acquisitions and
other capital commitments.
During 2009, we used net cash of $72.8 million in financing
activities, including $251.2 million in deemed
distributions to affiliates in connection with acquisitions and
$81.7 million in distributions to unitholders, partially
offset by $170.1 million net proceeds from the issuance of
our common units and net borrowings of $105 million under
our revolving credit facility. Net borrowings on our revolving
credit facility resulted in an increase in outstanding
borrowings under our revolving credit facility from
$150 million at December 31, 2008 to $255 million
at December 31, 2009.
During 2008, we used net cash of $146.3 million in
financing activities, including $125.0 million in deemed
distributions to affiliates in connection with our acquisition
of the Permian and Williston Basin Assets, $74.4 million in
distributions to unitholders, and $48.8 million in net
distributions to EAC related to pre-partnership operations,
partially offset by net borrowings of $102.5 million under
our revolving credit facility. Net borrowings on our revolving
credit facility resulted in an increase in outstanding
borrowings under our revolving credit facility from
$47.5 million at December 31, 2007 to
$150 million at December 31, 2008.
63
ENCORE
ENERGY PARTNERS LP
During 2007, we received net cash of $451.4 million from
financing activities, including net borrowings on our long-term
debt of $47.5 million, net proceeds received from the sale
of our common units of $193.5 million, $93.7 million
contribution from EAC used to partially finance our acquisition
of the Big Horn Basin Assets, and $119.9 million of net
contributions from EAC related to pre-partnership or pre-IPO
operations.
Liquidity
Our primary sources of liquidity are internally generated cash
flows and the borrowing capacity under our revolving credit
facility. We also have the ability to adjust our capital
expenditures. We may use other sources of capital, including the
issuance of debt or common units, to fund acquisitions or
maintain our financial flexibility. We believe that our
internally generated cash flows and availability under our
revolving credit facility will be sufficient to fund our planned
capital expenditures for the foreseeable future. However, should
commodity prices decline or the capital markets remain tight,
the borrowing capacity under our revolving credit facility could
be adversely affected. In the event of a reduction in the
borrowing base under our revolving credit facility, we currently
do not believe it will result in any required prepayments of
indebtedness.
Our partnership agreement requires that we distribute all of our
available cash quarterly. 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. The board of directors of our
general partner 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 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. The board
of directors of our general partner 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. Our partnership agreement permits our general partner
to establish cash reserves to be used to pay distributions for
any one or more of the next four quarters. In addition, our
partnership agreement allows our general partner to borrow funds
to make distributions.
Internally generated cash flows. Our
internally generated cash flows, results of operations, and
financing for our operations are largely dependent on oil and
natural gas prices. During 2009, our average realized oil and
natural gas prices decreased by 39 percent and
58 percent, respectively, as compared to 2008. Realized oil
and natural gas prices fluctuate widely in response to changing
market forces. If oil and natural gas prices decline, or we
experience a significant widening of our differentials, then our
earnings, cash flows from operations, borrowing base under our
revolving credit facility, and ability to pay distributions may
be adversely impacted. Prolonged periods of lower oil and
natural gas prices, or sustained wider differentials, could
cause us to not be in compliance with financial covenants under
our revolving credit facility and thereby affect our liquidity.
However, we have protected approximately two-thirds of our
forecasted production through 2012 against declining commodity
prices.
Revolving credit facility. The syndicate of
lenders underwriting our revolving credit facility includes
15 banking and other financial institutions. None of the
lenders are underwriting more than eight percent of the total
commitments. We believe the number of lenders and the small
percentage participation of each, provides adequate diversity
and flexibility should further consolidation occur within the
financial services industry.
Certain of the lenders underwriting our facility are also
counterparties to our commodity derivative contracts. Please
read Item 7A. Quantitative and Qualitative
Disclosures About Market Risk for additional discussion.
64
ENCORE
ENERGY PARTNERS LP
In March 2007, OLLC entered into a five-year credit agreement
(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. In March
2009, OLLC amended the OLLC Credit Agreement to, among other
things, increase the interest rate margins and commitment fees
applicable to loans made under the OLLC Credit Agreement. In
August 2009, OLLC amended the OLLC Credit Agreement to, among
other things, (1) increase the borrowing base from
$240 million to $375 million, (2) increase the
aggregate commitments of the lenders from $300 million to
$475 million, and (3) increase the interest rate
margins and commitment fees applicable to loans made under the
OLLC Credit Agreement. In November 2009, OLLC amended the OLLC
Credit Agreement, which will be effective upon the closing of
the Merger, to, among other things, permit the consummation of
the Merger from being a Change of Control under the
OLLC Credit Agreement.
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
$475 million. Availability under the OLLC Credit Agreement
is subject to a borrowing base, which is redetermined
semi-annually and upon requested special redeterminations. As of
December 31, 2009, the borrowing base was $375 million.
OLLC incurs a commitment fee of 0.5 percent on the unused
portion of the OLLC Credit Agreement.
Obligations under the OLLC Credit Agreement are secured by a
first-priority security interest in substantially all of
OLLCs proved oil and natural gas reserves and in the
equity interests of OLLC and its restricted subsidiaries. In
addition, obligations under the OLLC Credit Agreement are
guaranteed by us and OLLCs 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) 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:
|
|
|
|
|
|
|
|
|
|
|
Applicable Margin for
|
|
Applicable Margin for
|
Ratio of Outstanding Borrowings to Borrowing Base
|
|
Eurodollar Loans
|
|
Base Rate Loans
|
|
Less than .50 to 1
|
|
|
2.250
|
%
|
|
|
1.250
|
%
|
Greater than or equal to .50 to 1 but less than .75 to 1
|
|
|
2.500
|
%
|
|
|
1.500
|
%
|
Greater than or equal to .75 to 1 but less than .90 to 1
|
|
|
2.750
|
%
|
|
|
1.750
|
%
|
Greater than or equal to .90 to 1
|
|
|
3.000
|
%
|
|
|
2.000
|
%
|
The Eurodollar rate for any interest period (either
one, two, three, or six months, as selected by us) is the rate
equal to the British Bankers Association LIBOR for deposits in
dollars for a similar interest period. The Base Rate
is calculated as the highest of: (1) the annual rate of
interest announced by Bank of America, N.A. as its prime
rate; (2) the federal funds effective rate plus
0.5 percent; or (3) except during a LIBOR
Unavailability Period, the Eurodollar rate (for dollar
deposits for a one-month term) for such day plus
1.0 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 including, among
others, the following:
|
|
|
|
|
a prohibition against incurring debt, subject to permitted
exceptions;
|
|
|
|
a prohibition against purchasing or redeeming capital stock, or
prepaying indebtedness, subject to permitted exceptions;
|
65
ENCORE
ENERGY PARTNERS LP
|
|
|
|
|
a restriction on creating liens on our assets and the assets of
our 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 we and OLLC maintain a ratio of consolidated
current assets to consolidated current liabilities of not less
than 1.0 to 1.0 (the Current Ratio);
|
|
|
|
a requirement that we and OLLC maintain a ratio of consolidated
EBITDA to the sum of consolidated net interest expense plus
letter of credit fees of not less than 2.5 to 1.0 (the
Interest Coverage Ratio); and
|
|
|
|
a requirement that we and OLLC maintain a ratio of consolidated
funded debt to consolidated adjusted EBITDA of not more than 3.5
to 1.0 (the Leverage Ratio).
|
In order to show our and OLLCs compliance with the
covenants of the OLLC Credit Agreement, the use of non-GAAP
financial measures is required. The presentation of these
non-GAAP financial measures provides useful information to
investors as they allow readers to understand how much cushion
there is between the required ratios and the actual ratios.
These non-GAAP financial measures should not be considered an
alternative to any measure of financial performance presented in
accordance with GAAP.
As of December 31, 2009, we and OLLC were in compliance
with all covenants in the OLLC Credit Agreement, including the
following financial covenants:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual Ratio as of
|
|
|
|
|
|
|
December 31,
|
|
Financial Covenant
|
|
Required Ratio
|
|
|
2009
|
|
|
Current Ratio
|
|
|
Minimum 1.0 to 1.0
|
|
|
|
5.1 to 1.0
|
|
Interest Coverage Ratio
|
|
|
Minimum 2.5 to 1.0
|
|
|
|
10.7 to 1.0
|
|
Leverage Ratio
|
|
|
Maximum 3.5 to 1.0
|
|
|
|
2.0 to 1.0
|
|
The following table shows the calculation of the Current Ratio
as of December 31, 2009 ($ in thousands):
|
|
|
|
|
Current assets
|
|
$
|
48,248
|
|
Availability under the OLLC Credit Agreement
|
|
|
120,000
|
|
|
|
|
|
|
Consolidated current assets
|
|
$
|
168,248
|
|
|
|
|
|
|
Divided by: consolidated current liabilities
|
|
$
|
32,690
|
|
Current Ratio
|
|
|
5.1
|
|
The following table shows the calculation of the Interest
Coverage Ratio for the twelve months ended December 31,
2009 ($ in thousands):
|
|
|
|
|
Consolidated EBITDA(a)
|
|
$
|
116,732
|
|
Divided by: Consolidated net interest expense and letter of
credit fees
|
|
$
|
10,928
|
|
Interest Coverage Ratio
|
|
|
10.7
|
|
|
|
|
(a) |
|
Consolidated EBITDA is defined in the OLLC Credit Agreement and
generally means earnings before interest, income taxes,
depletion, depreciation, and amortization, and exploration
expense. Consolidated EBITDA is a non-GAAP financial measure,
which is reconciled to its most directly comparable GAAP measure
below. |
66
ENCORE
ENERGY PARTNERS LP
The following table shows the calculation of the Leverage Ratio
for the twelve months ended December 31, 2009 ($ in
thousands):
|
|
|
|
|
Consolidated funded debt
|
|
$
|
255,000
|
|
Divided by: Consolidated Adjusted EBITDA(a)
|
|
$
|
127,719
|
|
Leverage Ratio
|
|
|
2.0
|
|
|
|
|
(a) |
|
Consolidated Adjusted EBITDA is defined in the OLLC Credit
Agreement and generally means earnings before interest, income
taxes, depletion, depreciation, and amortization, and
exploration expense, after giving pro forma effect to one or
more acquisitions or dispositions in excess of $20 million
in the aggregate. Consolidated Adjusted EBITDA is a non-GAAP
financial measure, which is reconciled to its most directly
comparable GAAP measure below. |
The following table presents a calculation of Consolidated
EBITDA and Consolidated Adjusted EBITDA for the twelve months
ended December 31, 2009 (in thousands) as required under
the OLLC Credit Agreement, together with a reconciliation of
such amounts to their most directly comparable financial
measures calculated and presented in accordance with GAAP. These
EBITDA measures should not be considered an alternative to net
income (loss), operating income (loss), cash flow from operating
activities, or any other measure of financial performance or
liquidity presented in accordance with GAAP. These EBITDA
measures may not be comparable to similarly titled measures of
another company because all companies may not calculate these
measures in the same manner.
|
|
|
|
|
Consolidated net income
|
|
$
|
(40,507
|
)
|
Unrealized non-cash hedge gain
|
|
|
94,441
|
|
Consolidated net interest expense
|
|
|
10,928
|
|
Income and franchise taxes
|
|
|
14
|
|
Depletion, depreciation, amortization, and exploration expense
|
|
|
50,040
|
|
Non-cash unit-based compensation
|
|
|
565
|
|
Other non-cash
|
|
|
1,251
|
|
|
|
|
|
|
Consolidated EBITDA
|
|
|
116,732
|
|
Pro forma effect of acquisitions
|
|
|
10,987
|
|
|
|
|
|
|
Consolidated Adjusted EBITDA
|
|
$
|
127,719
|
|
|
|
|
|
|
The OLLC Credit Agreement contains customary events of default,
which would permit the lenders to accelerate the debt if not
cured within applicable grace periods. 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.
On December 31, 2009, we had $255 million of
outstanding borrowings and $120 million of borrowing
capacity under the OLLC Credit Agreement. On February 17,
2010, we had $260 million of outstanding borrowings and
$115 million of borrowing capacity under the OLLC Credit
Agreement.
Capitalization. At December 31, 2009, we
had total assets of $719.7 million and total capitalization
of $661.0 million, of which 61 percent was represented
by partners equity and 39 percent by long-term debt.
At December 31, 2008, we had total assets of
$813.3 million and total capitalization of
$769.4 million, of which 81 percent was represented by
partners equity and 19 percent by long-term debt. The
percentages of our capitalization represented by partners
equity and long-term debt could vary in the future if debt or
equity is used to finance capital projects or acquisitions.
67
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ENERGY PARTNERS LP
Changes
in Prices
Our oil and natural gas revenues, the value of our assets, and
our ability to obtain bank loans or additional capital on
attractive terms are affected by changes in oil and natural gas
prices, which fluctuate significantly. The following table
provides our average realized oil and natural gas prices for the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2009
|
|
2008
|
|
2007
|
|
Average realized prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
54.61
|
|
|
$
|
89.45
|
|
|
$
|
60.74
|
|
Natural gas ($/Mcf)
|
|
|
3.68
|
|
|
|
8.67
|
|
|
|
6.80
|
|
Combined ($/BOE)
|
|
|
44.75
|
|
|
|
78.59
|
|
|
|
54.75
|
|
Increases in oil and natural gas prices may be accompanied by or
result in: (1) increased development costs, as the demand
for drilling operations increases; (2) increased severance
taxes, as we are subject to higher severance taxes due to the
increased value of oil and natural gas extracted from our wells;
(3) increased LOE, as the demand for services related to
the operation of our wells increases; and (4) increased
electricity costs. Decreases in oil and natural gas prices may
be accompanied by or result in: (1) decreased development
costs, as the demand for drilling operations decreases;
(2) decreased severance taxes, as we are subject to lower
severance taxes due to the decreased value of oil and natural
gas extracted from our wells; (3) decreased LOE, as the
demand for services related to the operation of our wells
decreases; (4) decreased electricity costs;
(5) impairment of oil and natural gas properties; and
(6) decreased revenues and cash flows. We believe our risk
management program and available borrowing capacity under our
revolving credit facility provide means for us to manage
commodity price risks.
Critical
Accounting Policies and Estimates
Preparing financial statements in accordance with GAAP requires
management to make certain estimates and assumptions that affect
the reported amounts of assets, liabilities, revenues, and
expenses, and related disclosures. Management considers an
accounting estimate to be critical if it requires assumptions to
be made that were uncertain at the time the estimate was made,
and changes in the estimate or different estimates that could
have been selected, could have a material impact on our
consolidated results of operations or financial condition.
Management has identified the following critical accounting
policies and estimates.
Oil
and Natural Gas Properties
Successful efforts method. We use the
successful efforts method of accounting for oil and natural gas
properties under ASC 932 (formerly SFAS No. 19,
Financial Accounting and Reporting by Oil and Gas
Producing Companies). 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.
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 the period in which the determination was made. If an
exploratory well finds reserves but they cannot be classified as
proved, we continue 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 we are making sufficient
progress 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 are expensed 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
68
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ENERGY PARTNERS LP
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 unsuccessful,
the costs are charged to expense.
DD&A expense is directly affected by our reserve estimates.
Significant revisions to reserve estimates can be and are made
by our reserve engineers each year. Mostly these are the result
of changes in price, but as reserve quantities are estimates,
they can also change as more or better information is collected,
especially in the case of estimates in newer fields. Downward
revisions have the effect of increasing our DD&A rate,
while upward revisions have the effect of decreasing our
DD&A rate. Assuming no other changes, such as an increase
in depreciable base, as our reserves increase, the amount of
DD&A expense in a given period decreases and vice versa.
DD&A expense associated with lease and well equipment and
intangible drilling costs is based upon proved developed
reserves, while DD&A expense for capitalized leasehold
costs is based upon total proved reserves. As a result, changes
in the classification of our reserves could have a material
impact on our DD&A expense.
Miller and Lents estimates our reserves annually on
December 31. This results in a new DD&A rate which we
use for the preceding fourth quarter after adjusting for fourth
quarter production. We internally estimate 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.
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 BOE at the rate of six Mcf of natural gas to one
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.
In accordance with ASC
360-10, 205,
840, 958, and
855-10-60-1
(formerly SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets), we
assess 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 assets carrying
value to its undiscounted expected future net cash flows, then
an impairment charge is recognized to the extent the
assets carrying value exceeds its fair value. Expected
future net cash flows are based on existing proved reserves (and
appropriately risk-adjusted probable reserves), forecasted
production information, and managements outlook of future
commodity prices. Any impairment charge incurred is expensed and
reduces our net basis in the asset. 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. We use prices consistent with
the prices we believe a market participant would use in bidding
on acquisitions
and/or
assessing capital projects. These price assumptions are critical
to the impairment analysis as lower prices could trigger
impairment.
Unproved properties, the majority 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 impairment, a loss is 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 is determined by amortizing the
portion of the unproved properties costs which we believe
will not be transferred to proved properties over the life of
the lease. One of the primary factors in determining what
portion will not be transferred to proved properties is the
relative proportion of the unproved properties on which proved
reserves have been found in the past. Since wells drilled on
unproved acreage are inherently exploratory in nature, actual
results could vary from estimates especially in newer areas in
which we do not have a long history of drilling.
69
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ENERGY PARTNERS LP
Oil and natural gas reserves. Our estimates of
proved reserves are based on the quantities of oil and natural
gas, which, by analysis of geoscience and engineering data, can
be estimated with reasonable certainty to be economically
producible from a given date forward from known reservoirs under
existing conditions and operating methods. Miller and Lents
prepares a reserve and economic evaluation of all of our
properties on a
well-by-well
basis. Assumptions used by Miller and Lents in calculating
reserves or regarding the future cash flows or fair value of our
properties are subject to change in the future. The accuracy of
reserve estimates is a function of the:
|
|
|
|
|
quality and quantity of available data;
|
|
|
|
interpretation of that data;
|
|
|
|
accuracy of various mandated economic assumptions; and
|
|
|
|
judgment of the independent reserve engineer.
|
Future prices received for production and future production
costs may vary, perhaps significantly, from the prices and costs
assumed for purposes of calculating reserve estimates. We may
not be able to develop proved reserves within the periods
estimated. Furthermore, prices and costs may not remain
constant. Actual production may not equal the estimated amounts
used in the preparation of reserve projections. As these
estimates change, calculated reserves change. Any change in
reserves directly impacts our estimate of future cash flows from
the property, the propertys fair value, and our DD&A
rate.
Asset retirement obligations. In accordance
with ASC
410-20,
450-20,
835-20,
360-10-35,
840-10, and
980-410
(formerly SFAS No. 143, Accounting for Asset
Retirement Obligations), we recognize 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 an oil or natural gas
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 our oil and natural gas properties. The
liability is recorded at its discounted risk adjusted fair value
and then accreted each period until it is settled or the asset
is sold, at which time the liability is reversed.
The fair value of the liability associated with the asset
retirement obligation is determined using significant
assumptions, including current estimates of the plugging and
abandonment costs, annual expected inflation of these costs, the
productive life of the asset, and our credit-adjusted risk-free
interest rate used to discount the expected future cash flows.
Changes in any of these assumptions can result in significant
revisions to the estimated asset retirement obligation.
Revisions to the obligation are recorded with an offsetting
change to the carrying amount of the related oil and natural gas
properties, resulting in prospective changes to DD&A and
accretion expense. Because of the subjectivity of assumptions
and the relatively long life of most of our oil and natural gas
properties, the costs to ultimately retire these assets may vary
significantly from our estimates.
Goodwill
and Other Intangible Assets
We account for goodwill and other intangible assets under the
provisions of ASC 350,
730-10-60-3,
323-10-35-13,
205-20-60-4,
and
280-10-60-2
(formerly 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 is assessed
for impairment annually on December 31 or whenever indicators of
impairment exist. The goodwill test is performed at the
reporting unit level. We have determined that we have only one
reporting unit, which is oil and natural gas production in the
United States. If indicators of impairment are determined to
exist, an impairment charge is recognized for the amount by
which the carrying value of goodwill exceeds its implied fair
value.
We utilize both a market capitalization and an income approach
to determine the fair value of our reporting units. The primary
component of the income approach is the estimated discounted
future net cash flows expected to be recovered from the
reporting units oil and natural gas properties. Our
analysis concluded
70
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ENERGY PARTNERS LP
that there was no impairment of goodwill as of December 31,
2009. Any sharp decreases in the prices of oil and natural gas
or any significant negative reserve adjustments from the
December 31, 2009 assessment could change our estimates of
the fair value of our reporting units and could result in an
impairment charge.
Intangible assets with definite useful lives are amortized over
their estimated useful lives. In accordance with ASC
360-10, 205,
840, 958, and
855-10-60-1,
we evaluate 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 the
estimated undiscounted cash flows expected to result from the
use of the asset and its eventual disposition are less than its
carrying amount.
We allocate the purchase price paid for the acquisition of a
business to the assets and liabilities acquired based on the
estimated fair values of those assets and liabilities. Estimates
of fair value are based upon, among other things, reserve
estimates, anticipated future prices and costs, and expected net
cash flows to be generated. These estimates are often highly
subjective and may have a material impact on the amounts
recorded for acquired assets and liabilities.
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 volumes and prices
of oil and natural gas sales 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. Natural gas
revenues are reduced by any processing and other fees incurred
except for transportation costs paid to third parties, which are
recorded as expense. Natural gas revenues are recorded using the
sales method of accounting whereby revenue is recognized based
on our actual sales of natural gas rather than our proportionate
share of natural gas production. If our overproduced imbalance
position (i.e., we have cumulatively been over-allocated
production) is greater than our 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 production in
tanks, oil marketed on behalf of joint interest owners in our
properties, or oil in pipelines that has not been delivered to
the purchaser.
Derivatives
We use various financial instruments for non-trading purposes to
manage and reduce price volatility and other market risks
associated with our oil and natural gas production. These
arrangements are structured to reduce our exposure to commodity
price decreases, but they can also limit the benefit we might
otherwise receive from commodity price increases. Our risk
management activity is generally accomplished through
over-the-counter
derivative contracts with large financial institutions. We also
use derivative instruments in the form of interest rate swaps,
which hedge risk related to interest rate fluctuation.
We apply the provisions of ASC 815 (formerly
SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities), which requires
each derivative instrument to be recorded in the balance sheet
at fair value. If a derivative has not been designated as a
hedge or does not otherwise 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, the effective portion of changes in fair
value can be recognized in accumulated other comprehensive
income or loss until such time as the hedged item is recognized
in earnings. In order 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.
We have elected to designate our outstanding 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 or loss in partners
equity and reclassified into earnings in the same period in
which
71
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ENERGY PARTNERS LP
the hedged transaction affects earnings. Any ineffective portion
of the
mark-to-market
gain or loss is recognized immediately in earnings. While
management does not anticipate changing the designation of our
interest rate swaps as hedges, factors beyond our control can
preclude the use of hedge accounting.
We have not elected to designate our current portfolio of
commodity derivative contracts as hedges. Therefore, changes in
fair value of these derivative instruments are recognized in
earnings each period.
Please read Item 7A. Quantitative and Qualitative
Disclosures About Market Risk for discussion regarding our
sensitivity analysis for financial instruments.
New
Accounting Pronouncements
FASB
Launches Accounting Standards Codification
In June 2009, the FASB issued ASC
105-10
(formerly SFAS No. 168, The FASB Accounting
Standards Codification and the Hierarchy of Generally Accepted
Accounting Principles). ASC
105-10
establishes the FASB Accounting Standards Codification as the
sole source of authoritative accounting principles recognized by
the FASB to be applied by all nongovernmental entities in the
preparation of financial statements in conformity with GAAP. ASC
105-10 was
prospectively effective for financial statements issued for
fiscal years ending on or after September 15, 2009, and
interim periods within those fiscal years. The adoption of ASC
105-10 on
July 1, 2009 did not impact our results of operations or
financial condition.
Following the Codification, the FASB does not issue new
standards in the form of Statements, FASB Staff Positions
(FSP), or EITF Abstracts. Instead, it issues
Accounting Standards Updates (ASU), which update the
Codification, provide background information about the guidance,
and provide the basis for conclusions on the changes to the
Codification.
The Codification did not change GAAP; however, it did change the
way GAAP is organized and presented. As a result, these changes
impact how companies, including us, reference GAAP in their
financial statements and in their significant accounting
policies.
ASC
820-10
(formerly FSP
No. FAS 157-2,
Effective Date of FASB Statement
No. 157)
In February 2008, the FASB issued ASC
820-10,
which delayed the effective date of ASC
820-10 for
one year for nonfinancial assets and liabilities, except those
that are recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually). ASC
820-10 was
prospectively effective for financial statements issued for
fiscal years beginning after November 15, 2008, and interim
periods within those fiscal years. We elected a partial deferral
of ASC
820-10 for
all instruments within the scope of ASC
820-10,
including, but not limited to, our asset retirement obligations
and indefinite lived assets. The adoption of ASC
820-10 on
January 1, 2009 as it relates to nonfinancial assets and
liabilities did not have a material impact on our results of
operations or financial condition.
ASC
805 (formerly SFAS No. 141 (revised 2007),
Business Combinations)
In December 2007, the FASB issued ASC 805, which 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. In April 2009, the FASB issued ASC
805-20
(formerly FSP No. FAS 141(R)-1, Accounting
for Assets Acquired and Liabilities Assumed in a Business
Combination That Arises from Contingencies), which
amends and clarifies ASC 805 to address application issues,
including: (1) initial recognition and measurement;
(2) subsequent measurement and accounting; and
(3) disclosure of assets and liabilities arising from
contingencies in a business combination. ASC 805 and ASC
805-20 were
prospectively effective for business combinations consummated in
fiscal years
72
ENCORE
ENERGY PARTNERS LP
beginning on or after December 15, 2008. The accounting for
transactions between entities under common control is unchanged
under ASC 805 and ASC
805-20. The
application of ASC 805 and ASC
805-20 to
the acquisition of certain oil and natural gas properties and
related assets in 2009 was nominal.
ASC
815-10
(formerly SFAS No. 161, Disclosures about
Derivative Instruments and Hedging Activities an
amendment of FASB Statement No. 133)
In March 2008, the FASB issued ASC
815-10,
which requires enhanced disclosures: including (1) how and
why an entity uses derivative instruments; (2) how
derivative instruments and related hedged items are accounted
for under ASC 815; and (3) how derivative instruments and
related hedged items affect an entitys financial position,
financial performance, and cash flows. ASC
815-10 was
prospectively effective for financial statements issued for
fiscal years beginning on or after November 15, 2008, and
interim periods within those fiscal years. The adoption of ASC
815-10 on
January 1, 2009 required additional disclosures regarding
our derivative instruments; however, it did not impact our
results of operations or financial condition.
ASC
260-10
(formerly EITF Issue
No. 07-4,
Application of the Two-Class Method under FASB
Statement No. 128, Earnings per Share, to Master Limited
Partnerships)
In March 2008, the FASB issued ASC
260-10,
which addresses how master limited partnerships should calculate
earnings per unit using the two-class method and how current
period earnings of a master limited partnership should be
allocated to the general partner, limited partners, and other
participating securities. ASC
260-10 was
retrospectively effective for financial statements issued for
fiscal years beginning after December 15, 2008, and interim
periods within those years. In this Report, periods prior to the
adoption of ASC
260-10 have
been restated to calculate earnings per unit in accordance with
this pronouncement. The retrospective application of ASC
260-10
reduced our basic and diluted earnings per common unit by $0.01
for 2007. The adoption of ASC
260-10 did
not have an impact on our basic or diluted earnings per common
unit for 2008.
ASC
260-10
(formerly FSP No. EITF
03-6-1,
Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating
Securities)
In June 2008, the FASB issued ASC
260-10,
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. ASC
260-10 was
retroactively effective for financial statements issued for
fiscal years beginning after December 15, 2008, and interim
periods within those years. The adoption of ASC
260-10 on
January 1, 2009 did not have a material impact on our
earnings per unit calculations. In this Report, periods prior to
the adoption of ASC
260-10 have
been restated to calculate earnings per unit in accordance with
this pronouncement.
SEC
Release
No. 33-8995,
Modernization of Oil and Gas Reporting
(Release
33-8995)
In December 2008, the SEC issued Release
33-8995,
which amends oil and natural gas reporting requirements under
Regulations S-K and S-X. Release
33-8995 also
adds a section to
Regulation S-K
(Subpart 1200) to codify the revised disclosure
requirements in Securities Act Industry Guide 2, which is being
phased out. Release
33-8995
permits the use of new technologies to determine proved reserves
if those technologies have been demonstrated empirically to lead
to reliable conclusions about reserves volumes. Release
33-8995 will
also allow companies to disclose their probable and possible
reserves to investors at the companys option. In addition,
the new disclosure requirements require companies to:
(1) report the independence and qualifications of its
reserves preparer or auditor; (2) file reports when a third
party is relied upon to prepare reserves estimates or conduct a
reserves audit; and (3) report oil and gas reserves using
an average price based upon the prior
12-month
period rather than a year-end price, unless prices are defined
by contractual arrangements, excluding escalations based on
future conditions. Release
33-8995 was
prospectively effective for financial statements issued for
fiscal years ending on or after December 31, 2009.
73
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ENERGY PARTNERS LP
ASC
855-10
(formerly SFAS No. 165, Subsequent
Events)
In June 2009, the FASB issued ASC
855-10 to
establish general standards of accounting for and disclosure of
events that occur after the balance sheet date but before
financial statements are issued or available to be issued. In
particular, ASC
855-10 sets
forth: (1) the period after the balance sheet date during
which management of a reporting entity should evaluate events or
transactions that may occur for potential recognition or
disclosure in the financial statements; (2) the
circumstances under which an entity should recognize events or
transactions occurring after the balance sheet date in its
financial statements; and (3) the disclosures that an
entity should make about events or transactions that occurred
after the balance sheet date. ASC
855-10 was
prospectively effective for financial statements issued for
interim or annual periods ending after June 15, 2009. The
adoption of ASC
855-10 on
June 30, 2009 did not impact our results of operations or
financial condition.
ASU
No. 2009-05,
Fair Value Measurement and Disclosure: Measuring
Liabilities at Fair Value (ASU
2009-05)
In August 2009, the FASB issued ASU
2009-05 to
provide clarification on measuring liabilities at fair value
when a quoted price in an active market is not available. In
particular, ASU
2009-05
specifies that a valuation technique should be applied that used
either the quote of the liability when traded as an asset, the
quoted prices for similar liabilities or similar liabilities
when traded as assets, or another valuation technique consistent
with existing fair value measurement guidance. ASU
2009-05 was
prospectively effective for financial statements issued for
interim or annual periods ending after October 1, 2009. The
adoption of ASU
2009-05 on
December 31, 2009 did not impact our results of operations
or financial condition.
ASU
No. 2010-03,
Oil and Gas Reserve Estimation and Disclosure
(ASU
2010-03)
In January 2010, the FASB issued ASU
2010-03 to
align the oil and natural gas reserve estimation and disclosure
requirements of Extractive Activities Oil and Gas
(ASC 932) with the requirements in the SECs final
rule, Modernization of the Oil and Gas
Reporting. ASU
2010-03 was
prospectively effective for financial statements issued for
annual periods ending on or after December 31, 2009.
ASU
No. 2010-06,
Improving Disclosures about Fair Value Measurements
(ASU
2010-06)
In January 2010, the FASB issued ASU
2010-06 to
require additional information to be disclosed principally in
respect of level 3 fair value measurements and transfers to
and from Level 1 and Level 2 measurements; in
addition, enhanced disclosure is required concerning inputs and
valuation techniques used to determine Level 2 and
Level 3 fair value measurements. ASU
2010-06 was
generally effective for interim and annual reporting periods
beginning after December 15, 2009; however, the
requirements to disclose separately purchases, sales, issuances,
and settlements in the Level 3 reconciliation are effective
for fiscal years beginning after December 15, 2010 (and for
interim periods within such years) with early adoption allowed.
The adoption of ASU
2010-06 on
December 31, 2009 did not impact our results of operations
or financial condition.
Information
Concerning Forward-Looking Statements
This Report contains forward-looking statements, which give our
current expectations or forecasts of future events.
Forward-looking statements can be identified by the fact that
they do not relate strictly to historical or current facts.
These statements may include words such as may,
will, could, anticipate,
estimate, expect, project,
intend, plan, believe,
should, predict, potential,
pursue, target, continue,
and other words and terms of similar meaning. In particular,
forward-looking statements included in this Report relate to,
among other things, the following:
|
|
|
|
|
the occurrence of any event, change, or other circumstance that
could affect the consummation of the Merger or give rise to the
termination of the Merger Agreement in connection with the
Merger;
|
74
ENCORE
ENERGY PARTNERS LP
|
|
|
|
|
the inability to complete the Merger due to the failure to
satisfy any conditions required to consummate the Merger;
|
|
|
|
items of income and expense (including, without limitation, LOE,
production taxes, DD&A, and G&A);
|
|
|
|
expected capital expenditures and the focus of our capital
program;
|
|
|
|
areas of future growth;
|
|
|
|
our development and exploitation programs;
|
|
|
|
future secondary development and tertiary recovery potential;
|
|
|
|
anticipated prices for oil and natural gas and expectations
regarding differentials between wellhead prices and benchmark
prices (including, without limitation, the effects of the
worldwide economic recession);
|
|
|
|
projected results of operations;
|
|
|
|
timing and amount of future production of oil and natural gas;
|
|
|
|
availability of pipeline capacity;
|
|
|
|
expected commodity derivative positions and payments related
thereto (including the ability of counterparties to fulfill
obligations);
|
|
|
|
expectations regarding working capital, cash flow, and liquidity;
|
|
|
|
projected borrowings under our revolving credit facility (and
the ability of lenders to fund their commitments); and
|
|
|
|
the marketing of our oil and natural gas production.
|
You are cautioned not to place undue reliance on such
forward-looking statements, which speak only as of the date of
this Report. Our actual results may differ significantly from
the results discussed in the forward-looking statements. Such
statements involve risks and uncertainties, including, but not
limited to, the matters discussed in Item 1A. Risk
Factors and elsewhere in this Report and in our other
filings with the SEC. If one or more of these risks or
uncertainties materialize (or the consequences of such a
development changes), or should underlying assumptions prove
incorrect, actual outcomes may vary materially from those
forecasted or expected. We undertake no responsibility to update
forward-looking statements for changes related to these or any
other factors that may occur subsequent to this filing for any
reason.
Except for our obligations to disclose material information
under United States federal securities laws, we undertake no
obligation to release publicly any revision to any
forward-looking statement, to report events or circumstances
after the date of this Report, or to report the occurrence of
unanticipated events.
|
|
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 and reduce 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
75
ENCORE
ENERGY PARTNERS LP
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.
Counterparties. At December 31, 2009, we
had committed 10 percent of greater (in terms of fair
market value) of either our oil or natural gas commodity
derivative contracts in asset positions to the following
counterparties:
|
|
|
|
|
|
|
|
|
|
|
Fair Market Value of
|
|
Fair Market Value of
|
|
|
Oil Derivative
|
|
Natural Gas Derivative
|
|
|
Contracts
|
|
Contracts
|
Counterparty
|
|
Committed
|
|
Committed
|
|
|
(In thousands)
|
|
BNP Paribas
|
|
$
|
13,955
|
|
|
$
|
2,795
|
|
Calyon
|
|
|
3,820
|
|
|
|
6,167
|
|
Royal Bank of Canada
|
|
|
4,158
|
|
|
|
(a
|
)
|
Wachovia
|
|
|
3,069
|
|
|
|
1,148
|
|
|
|
|
(a) |
|
Less than 10 percent. |
In order to mitigate the credit risk of financial instruments,
we enter into master netting agreements with certain
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 is
intended to benefit 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 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 enter into floor
spreads. In a floor spread, we purchase puts at a
specified price (a purchased put) and also sell a
put at a lower price (a short put). This strategy
enables us to achieve some downside protection for a portion of
our production, while funding the cost of such protection by
selling a put at a lower price. If the price of the commodity
falls below the strike price of the purchased put, then we have
protection against additional commodity price decreases for the
covered production down to the strike price of the short put. At
commodity prices below the strike price of the short put, the
benefit from the purchased put is generally offset by the
expense associated with the short put. For example, in 2007, we
purchased oil put options for 2,000 Bbls/D in 2010 at $65
per Bbl. As NYMEX prices increased in 2008, we wanted to protect
downside price exposure at the higher price. In order to do
this, we purchased oil put options for 2,000 Bbls/D in 2010
at $75 per Bbl and simultaneously sold oil put options for
2,000 Bbls/D in 2010 at $65 per Bbl. Thus, after these
transactions were completed, we had purchased two oil put
options for 2,000 Bbls/D in 2010 (one at $65 per Bbl and
one at $75 per Bbl) and sold one oil put option for
2,000 Bbls/D in 2010 at $65 per Bbl. However, the net
effect resulted in us owning one oil put option for
2,000 Bbls/D at
76
ENCORE
ENERGY PARTNERS LP
$75 per Bbl. In the following tables, the purchased floor
component of these floor spreads are shown net and included with
our other floor contracts.
The counterparties to our commodity derivative contracts are a
diverse group of five institutions, all of which are currently
rated A or better by Standard & Poors
and/or
Fitch. As of December 31, 2009, the fair market value of
our oil derivative contracts was a net liability of
approximately $3.9 million and the fair market value of our
natural gas derivative contracts was a net asset of
approximately $10.6 million. Based on our open commodity
derivative positions at December 31, 2009, a
10 percent increase in the respective NYMEX prices for oil
and natural gas would decrease our net commodity derivative
asset by approximately $28.8 million, while a
10 percent decrease in the respective NYMEX prices for oil
and natural gas would increase our net commodity derivative
asset by approximately $30.2 million.
The following tables summarize our open commodity derivative
contracts as of December 31, 2009:
Oil
Derivative Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
Average
|
|
|
Weighted
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
|
|
Daily
|
|
|
Average
|
|
|
Daily
|
|
|
Average
|
|
|
Daily
|
|
|
Average
|
|
|
Asset (Liability)
|
|
|
|
Floor
|
|
|
Floor
|
|
|
Cap
|
|
|
Cap
|
|
|
Swap
|
|
|
Swap
|
|
|
Fair Market
|
|
Period
|
|
Volume
|
|
|
Price
|
|
|
Volume
|
|
|
Price
|
|
|
Volume
|
|
|
Price
|
|
|
Value
|
|
|
|
(Bbl)
|
|
|
(per Bbl)
|
|
|
(Bbl)
|
|
|
(per Bbl)
|
|
|
(Bbl)
|
|
|
(per Bbl)
|
|
|
(In thousands)
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,476
|
)
|
|
|
|
880
|
|
|
$
|
80.00
|
|
|
|
440
|
|
|
$
|
93.80
|
|
|
|
760
|
|
|
$
|
75.43
|
|
|
|
|
|
|
|
|
2,000
|
|
|
|
75.00
|
|
|
|
1,000
|
|
|
|
77.23
|
|
|
|
250
|
|
|
|
65.95
|
|
|
|
|
|
|
|
|
760
|
|
|
|
67.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,638
|
|
|
|
|
1,880
|
|
|
|
80.00
|
|
|
|
1,440
|
|
|
|
95.41
|
|
|
|
760
|
|
|
|
78.46
|
|
|
|
|
|
|
|
|
1,000
|
|
|
|
70.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
760
|
|
|
|
65.00
|
|
|
|
|
|
|
|
|
|
|
|
250
|
|
|
|
69.65
|
|
|
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,020
|
)
|
|
|
|
750
|
|
|
|
70.00
|
|
|
|
500
|
|
|
|
82.05
|
|
|
|
210
|
|
|
|
81.62
|
|
|
|
|
|
|
|
|
1,510
|
|
|
|
65.00
|
|
|
|
250
|
|
|
|
79.25
|
|
|
|
1,300
|
|
|
|
76.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3,858
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
77
ENCORE
ENERGY PARTNERS LP
Natural
Gas Derivative Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
Average
|
|
|
Weighted
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
|
|
Daily
|
|
|
Average
|
|
|
Daily
|
|
|
Average
|
|
|
Daily
|
|
|
Average
|
|
|
Asset
|
|
|
|
Floor
|
|
|
Floor
|
|
|
Cap
|
|
|
Cap
|
|
|
Swap
|
|
|
Swap
|
|
|
Fair Market
|
|
Period
|
|
Volume
|
|
|
Price
|
|
|
Volume
|
|
|
Price
|
|
|
Volume
|
|
|
Price
|
|
|
Value
|
|
|
|
(Mcf)
|
|
|
(per Mcf)
|
|
|
(Mcf)
|
|
|
(per Mcf)
|
|
|
(Mcf)
|
|
|
(per Mcf)
|
|
|
(In thousands)
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
7,963
|
|
|
|
|
3,800
|
|
|
$
|
8.20
|
|
|
|
3,800
|
|
|
$
|
9.58
|
|
|
|
5,452
|
|
|
$
|
6.20
|
|
|
|
|
|
|
|
|
4,698
|
|
|
|
7.26
|
|
|
|
|
|
|
|
|
|
|
|
550
|
|
|
|
5.86
|
|
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,105
|
|
|
|
|
3,398
|
|
|
|
6.31
|
|
|
|
|
|
|
|
|
|
|
|
7,952
|
|
|
|
6.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
550
|
|
|
|
5.86
|
|
|
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
547
|
|
|
|
|
898
|
|
|
|
6.76
|
|
|
|
|
|
|
|
|
|
|
|
5,452
|
|
|
|
6.26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
550
|
|
|
|
5.86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
10,615
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate sensitivity. At
December 31, 2009, we had outstanding borrowings under our
revolving credit facility of $255 million, which is subject
to floating market rates of interest that are linked to the
Eurodollar rate. At this level of floating rate debt, if the
Eurodollar rate increased 10 percent, we would incur an
additional $1.0 million of interest expense per year, and
if the Eurodollar rate decreased 10 percent, we would incur
$1.0 million less.
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, 2009, the
fair market value of our interest rate swaps was a net liability
of approximately $3.7 million. If the Eurodollar rate
increased 10 percent, the fair value would decrease to
approximately $3.4 million, and if the Eurodollar rate
decreased 10 percent, the fair value would increase to
approximately $3.9 million.
The following table summarizes our open interest rate swaps as
of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
Fixed
|
|
Floating
|
Term
|
|
Amount
|
|
Rate
|
|
Rate
|
|
|
(In thousands)
|
|
|
|
|
|
Jan. 2010 Jan. 2011
|
|
$
|
50,000
|
|
|
|
3.1610
|
%
|
|
|
1-month LIBOR
|
|
Jan. 2010 Jan. 2011
|
|
|
25,000
|
|
|
|
2.9650
|
%
|
|
|
1-month LIBOR
|
|
Jan. 2010 Jan. 2011
|
|
|
25,000
|
|
|
|
2.9613
|
%
|
|
|
1-month LIBOR
|
|
Jan. 2010 Mar. 2012
|
|
|
50,000
|
|
|
|
2.4200
|
%
|
|
|
1-month LIBOR
|
|
78
ENCORE
ENERGY PARTNERS LP
|
|
ITEM 8.
|
FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
|
Index to
Consolidated Financial Statements
|
|
|
|
|
|
|
Page
|
|
|
|
|
80
|
|
|
|
|
81
|
|
|
|
|
82
|
|
|
|
|
83
|
|
|
|
|
84
|
|
|
|
|
85
|
|
|
|
|
115
|
|
79
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, 2009 and 2008, and the related consolidated
statements of operations, partners equity and
comprehensive income (loss), and cash flows for each of the
three years in the period ended December 31, 2009. These
financial statements are the responsibility of the
Partnerships 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 financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Encore Energy Partners LP at
December 31, 2009 and 2008, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2009, in conformity with
U.S. generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial
statements, effective January 1, 2009, the Partnership
retroactively changed its method of calculating basic and
diluted earnings per common unit with the adoption of the
guidance originally issued in EITF Issue
No. 07-4,
Application of the Two-Class Method under FASB Statement
No. 128, Earnings per Share, to Master Limited
Partnerships (codified in FASB ASC Topic 260, Earnings
per Share) and FSP
No. EITF 03-6-1,
Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating Securities (codified
in FASB ASC Topic 260, Earnings Per Share). Additionally,
as discussed in Note 2 to the consolidated financial
statements, the Partnership has changed its reserve estimates
and related disclosures as a result of adopting new oil and gas
reserve estimation and disclosure requirements resulting from
Accounting Standards Update
No. 2010-03,
Oil and Gas Reserve Estimation and Disclosures, effective
for annual reporting periods ended on or after December 31,
2009.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States),
Encore Energy Partners LPs internal control over financial
reporting as of December 31, 2009, 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, 2010 expressed an unqualified opinion thereon.
Fort Worth, Texas
February 24, 2010
80
ENCORE
ENERGY PARTNERS LP
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except unit amounts)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,754
|
|
|
$
|
619
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Trade
|
|
|
24,543
|
|
|
|
18,965
|
|
Affiliate
|
|
|
8,213
|
|
|
|
3,896
|
|
Derivatives
|
|
|
12,881
|
|
|
|
75,131
|
|
Other
|
|
|
857
|
|
|
|
831
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
48,248
|
|
|
|
99,442
|
|
|
|
|
|
|
|
|
|
|
Properties and equipment, at cost successful efforts
method:
|
|
|
|
|
|
|
|
|
Proved properties, including wells and related equipment
|
|
|
851,833
|
|
|
|
814,903
|
|
Unproved properties
|
|
|
55
|
|
|
|
84
|
|
Accumulated depletion, depreciation, and amortization
|
|
|
(210,417
|
)
|
|
|
(154,584
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
641,471
|
|
|
|
660,403
|
|
|
|
|
|
|
|
|
|
|
Other property and equipment
|
|
|
863
|
|
|
|
802
|
|
Accumulated depreciation
|
|
|
(419
|
)
|
|
|
(240
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
444
|
|
|
|
562
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
9,290
|
|
|
|
9,290
|
|
Other intangibles, net
|
|
|
3,316
|
|
|
|
3,662
|
|
Derivatives
|
|
|
13,423
|
|
|
|
38,497
|
|
Other
|
|
|
3,459
|
|
|
|
1,457
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
719,651
|
|
|
$
|
813,313
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
577
|
|
|
$
|
1,036
|
|
Affiliate
|
|
|
2,780
|
|
|
|
5,468
|
|
Accrued liabilities:
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
3,683
|
|
|
|
4,252
|
|
Development capital
|
|
|
1,484
|
|
|
|
2,277
|
|
Interest
|
|
|
429
|
|
|
|
126
|
|
Production, ad valorem, and severance taxes
|
|
|
10,665
|
|
|
|
10,634
|
|
Derivatives
|
|
|
9,815
|
|
|
|
1,297
|
|
Oil and natural gas revenues payable
|
|
|
1,598
|
|
|
|
1,287
|
|
Other
|
|
|
1,659
|
|
|
|
1,502
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
32,690
|
|
|
|
27,879
|
|
Derivatives
|
|
|
13,401
|
|
|
|
3,491
|
|
Future abandonment cost, net of current portion
|
|
|
12,556
|
|
|
|
11,987
|
|
Long-term debt
|
|
|
255,000
|
|
|
|
150,000
|
|
Other
|
|
|
|
|
|
|
605
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
313,647
|
|
|
|
193,962
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (see Note 4)
|
|
|
|
|
|
|
|
|
Partners equity:
|
|
|
|
|
|
|
|
|
Limited partners 45,285,347 and 33,077,610 common
units issued and outstanding, respectively
|
|
|
409,777
|
|
|
|
616,076
|
|
General partner 504,851 general partner units issued
and outstanding
|
|
|
(353
|
)
|
|
|
7,534
|
|
Accumulated other comprehensive loss
|
|
|
(3,420
|
)
|
|
|
(4,259
|
)
|
|
|
|
|
|
|
|
|
|
Total partners equity
|
|
|
406,004
|
|
|
|
619,351
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity
|
|
$
|
719,651
|
|
|
$
|
813,313
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
81
ENCORE
ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
127,611
|
|
|
$
|
226,613
|
|
|
$
|
135,546
|
|
Natural gas
|
|
|
22,428
|
|
|
|
53,944
|
|
|
|
39,119
|
|
Marketing
|
|
|
478
|
|
|
|
5,324
|
|
|
|
8,582
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
150,517
|
|
|
|
285,881
|
|
|
|
183,247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
41,676
|
|
|
|
44,752
|
|
|
|
33,980
|
|
Production, ad valorem, and severance taxes
|
|
|
16,099
|
|
|
|
28,147
|
|
|
|
17,712
|
|
Depletion, depreciation, and amortization
|
|
|
56,757
|
|
|
|
57,537
|
|
|
|
47,494
|
|
Exploration
|
|
|
3,132
|
|
|
|
196
|
|
|
|
126
|
|
General and administrative
|
|
|
11,375
|
|
|
|
16,605
|
|
|
|
15,245
|
|
Marketing
|
|
|
302
|
|
|
|
5,466
|
|
|
|
6,673
|
|
Derivative fair value loss (gain)
|
|
|
47,464
|
|
|
|
(96,880
|
)
|
|
|
26,301
|
|
Other operating
|
|
|
3,099
|
|
|
|
1,670
|
|
|
|
1,426
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
179,904
|
|
|
|
57,493
|
|
|
|
148,957
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(29,387
|
)
|
|
|
228,388
|
|
|
|
34,290
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
|
(10,974
|
)
|
|
|
(6,969
|
)
|
|
|
(12,702
|
)
|
Other
|
|
|
46
|
|
|
|
99
|
|
|
|
196
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expenses
|
|
|
(10,928
|
)
|
|
|
(6,870
|
)
|
|
|
(12,506
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(40,315
|
)
|
|
|
221,518
|
|
|
|
21,784
|
|
Income tax provision
|
|
|
(14
|
)
|
|
|
(762
|
)
|
|
|
(78
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(40,329
|
)
|
|
$
|
220,756
|
|
|
$
|
21,706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocation (see Note 8):
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income (loss)
|
|
$
|
(39,913
|
)
|
|
$
|
163,070
|
|
|
$
|
(18,877
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income (loss)
|
|
$
|
(592
|
)
|
|
$
|
2,648
|
|
|
$
|
(394
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(1.01
|
)
|
|
$
|
5.33
|
|
|
$
|
(0.79
|
)
|
Diluted
|
|
$
|
(1.01
|
)
|
|
$
|
5.21
|
|
|
$
|
(0.79
|
)
|
Weighted average common units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
39,366
|
|
|
|
30,568
|
|
|
|
23,877
|
|
Diluted
|
|
|
39,366
|
|
|
|
31,938
|
|
|
|
23,877
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
82
ENCORE
ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF PARTNERS EQUITY
AND
COMPREHENSIVE INCOME (LOSS)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
Owners
|
|
|
Limited
|
|
|
|
|
|
|
|
|
Other
|
|
|
Total
|
|
|
|
Net
|
|
|
Partners
|
|
|
General Partner
|
|
|
Comprehensive
|
|
|
Partners
|
|
|
|
Equity
|
|
|
Units
|
|
|
Amount
|
|
|
Units
|
|
|
Amount
|
|
|
Loss
|
|
|
Equity
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
Balance at December 31, 2006
|
|
$
|
197,810
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
197,810
|
|
Contribution by EAC in connection with acquisition of the Elk
Basin Assets
|
|
|
103,062
|
|
|
|
10,280
|
|
|
|
|
|
|
|
221
|
|
|
|
|
|
|
|
|
|
|
|
103,062
|
|
Net contributions from owner
|
|
|
119,867
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
119,867
|
|
Equity adjustment due to combination of entities under common
control
|
|
|
(1,306
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,306
|
)
|
Contribution of Permian Basin Assets by EAC
|
|
|
(26,229
|
)
|
|
|
4,043
|
|
|
|
26,229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of owners net equity Permian Basin
Assets
|
|
|
(91,956
|
)
|
|
|
|
|
|
|
90,118
|
|
|
|
|
|
|
|
1,838
|
|
|
|
|
|
|
|
|
|
Allocation of owners net equity Permian and
Williston Basin Assets
|
|
|
(96,877
|
)
|
|
|
|
|
|
|
94,595
|
|
|
|
|
|
|
|
2,282
|
|
|
|
|
|
|
|
|
|
Allocation of owners net equity Arkoma Basin
Assets
|
|
|
(17,282
|
)
|
|
|
|
|
|
|
16,874
|
|
|
|
|
|
|
|
408
|
|
|
|
|
|
|
|
|
|
Allocation of owners net equity Williston
Basin Assets
|
|
|
(35,034
|
)
|
|
|
|
|
|
|
34,209
|
|
|
|
|
|
|
|
825
|
|
|
|
|
|
|
|
|
|
Allocation of owners net equity Rockies and
Permian Basin Assets
|
|
|
(192,737
|
)
|
|
|
|
|
|
|
188,197
|
|
|
|
|
|
|
|
4,540
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of common units, net of offering costs
|
|
|
|
|
|
|
9,864
|
|
|
|
193,863
|
|
|
|
284
|
|
|
|
(402
|
)
|
|
|
|
|
|
|
193,461
|
|
Non-cash unit-based compensation
|
|
|
|
|
|
|
|
|
|
|
6,665
|
|
|
|
|
|
|
|
139
|
|
|
|
|
|
|
|
6,804
|
|
Cash distributions to unitholders ($0.053 per unit)
|
|
|
|
|
|
|
|
|
|
|
(1,311
|
)
|
|
|
|
|
|
|
(27
|
)
|
|
|
|
|
|
|
(1,338
|
)
|
Net income attributable to owner related to pre-partnership and
pre-IPO operations
|
|
|
40,682
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,682
|
|
Net loss attributable to unitholders
|
|
|
|
|
|
|
|
|
|
|
(18,587
|
)
|
|
|
|
|
|
|
(389
|
)
|
|
|
|
|
|
|
(18,976
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
|
|
|
|
24,187
|
|
|
|
630,852
|
|
|
|
505
|
|
|
|
9,214
|
|
|
|
|
|
|
|
640,066
|
|
Net distributions to owner
|
|
|
|
|
|
|
|
|
|
|
(47,629
|
)
|
|
|
|
|
|
|
(1,166
|
)
|
|
|
(1
|
)
|
|
|
(48,796
|
)
|
Deemed distributions to affiliates in connection with
acquisition of the Permian and Williston Basin Assets
|
|
|
|
|
|
|
6,885
|
|
|
|
(122,083
|
)
|
|
|
|
|
|
|
(2,944
|
)
|
|
|
|
|
|
|
(125,027
|
)
|
Issuance of common units in exchange for net profits interest in
certain Crockett County properties
|
|
|
|
|
|
|
284
|
|
|
|
5,748
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,748
|
|
Non-cash unit-based compensation
|
|
|
|
|
|
|
|
|
|
|
5,180
|
|
|
|
|
|
|
|
83
|
|
|
|
|
|
|
|
5,263
|
|
Cash distributions to unitholders ($2.3111 per unit)
|
|
|
|
|
|
|
|
|
|
|
(73,234
|
)
|
|
|
|
|
|
|
(1,167
|
)
|
|
|
|
|
|
|
(74,401
|
)
|
Vesting of phantom units
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conversion of management incentive units
|
|
|
|
|
|
|
1,715
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to owner related to pre-partnership
operations of the Permian and Williston Basin Assets
|
|
|
|
|
|
|
|
|
|
|
3,321
|
|
|
|
|
|
|
|
80
|
|
|
|
|
|
|
|
3,401
|
|
Net income attributable to owner related to pre-partnership
operations of the Arkoma Basin Assets
|
|
|
|
|
|
|
|
|
|
|
5,922
|
|
|
|
|
|
|
|
143
|
|
|
|
|
|
|
|
6,065
|
|
Net income attributable to owner related to pre-partnership
operations of the Williston Basin Assets
|
|
|
|
|
|
|
|
|
|
|
6,637
|
|
|
|
|
|
|
|
164
|
|
|
|
|
|
|
|
6,801
|
|
Net income attributable to owner related to pre-partnership
operations of the Rockies and Permian Basin Assets
|
|
|
|
|
|
|
|
|
|
|
34,540
|
|
|
|
|
|
|
|
833
|
|
|
|
|
|
|
|
35,373
|
|
Net income attributable to unitholders
|
|
|
|
|
|
|
|
|
|
|
166,822
|
|
|
|
|
|
|
|
2,294
|
|
|
|
|
|
|
|
169,116
|
|
Change in deferred hedge loss on interest rate swaps, net of tax
of $12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,258
|
)
|
|
|
(4,258
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
216,498
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
|
|
|
|
33,078
|
|
|
|
616,076
|
|
|
|
505
|
|
|
|
7,534
|
|
|
|
(4,259
|
)
|
|
|
619,351
|
|
Net distributions to owner
|
|
|
|
|
|
|
|
|
|
|
(11,137
|
)
|
|
|
|
|
|
|
(272
|
)
|
|
|
|
|
|
|
(11,409
|
)
|
Deemed distributions in connection with acquisition of the
Arkoma Basin Assets
|
|
|
|
|
|
|
|
|
|
|
(45,333
|
)
|
|
|
|
|
|
|
(1,088
|
)
|
|
|
|
|
|
|
(46,421
|
)
|
Deemed distributions in connection with acquisition of the
Williston Basin Assets
|
|
|
|
|
|
|
|
|
|
|
(24,593
|
)
|
|
|
|
|
|
|
(593
|
)
|
|
|
|
|
|
|
(25,186
|
)
|
Deemed distributions in connection with acquisition of the
Rockies and Permian Basin Assets
|
|
|
|
|
|
|
|
|
|
|
(175,408
|
)
|
|
|
|
|
|
|
(4,232
|
)
|
|
|
|
|
|
|
(179,640
|
)
|
Proceeds from issuance of common units, net of offering costs
|
|
|
|
|
|
|
12,190
|
|
|
|
170,000
|
|
|
|
|
|
|
|
(114
|
)
|
|
|
|
|
|
|
169,886
|
|
Non-cash unit-based compensation
|
|
|
|
|
|
|
|
|
|
|
560
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
565
|
|
Cash distributions to unitholders ($2.05 per unit)
|
|
|
|
|
|
|
|
|
|
|
(80,617
|
)
|
|
|
|
|
|
|
(1,035
|
)
|
|
|
|
|
|
|
(81,652
|
)
|
Vesting of phantom units and conversion of management incentive
units
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to owners prior to acquisition of the
Williston Basin Assets
|
|
|
|
|
|
|
|
|
|
|
(188
|
)
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
(193
|
)
|
Net income attributable to owners prior to acquisition of the
Rockies and Permian Basin Assets
|
|
|
|
|
|
|
|
|
|
|
360
|
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
369
|
|
Net loss attributable to unitholders
|
|
|
|
|
|
|
|
|
|
|
(39,943
|
)
|
|
|
|
|
|
|
(562
|
)
|
|
|
|
|
|
|
(40,505
|
)
|
Change in deferred hedge loss on interest rate swaps, net of tax
of $2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
839
|
|
|
|
839
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(39,490
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
$
|
|
|
|
|
45,285
|
|
|
$
|
409,777
|
|
|
|
505
|
|
|
$
|
(353
|
)
|
|
$
|
(3,420
|
)
|
|
$
|
406,004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
83
ENCORE
ENERGY PARTNERS LP
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(40,329
|
)
|
|
$
|
220,756
|
|
|
$
|
21,706
|
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization
|
|
|
56,757
|
|
|
|
57,537
|
|
|
|
47,494
|
|
Non-cash exploration expense
|
|
|
|
|
|
|
13
|
|
|
|
23
|
|
Deferred taxes
|
|
|
(286
|
)
|
|
|
322
|
|
|
|
16
|
|
Non-cash unit-based compensation expense
|
|
|
565
|
|
|
|
5,232
|
|
|
|
6,804
|
|
Non-cash derivative loss (gain)
|
|
|
117,685
|
|
|
|
(92,286
|
)
|
|
|
27,543
|
|
Other
|
|
|
5,207
|
|
|
|
1,012
|
|
|
|
695
|
|
Changes in operating assets and liabilities, net of effects from
acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(10,591
|
)
|
|
|
12,437
|
|
|
|
(20,203
|
)
|
Current derivatives
|
|
|
(2,020
|
)
|
|
|
(9,586
|
)
|
|
|
(2,700
|
)
|
Other current assets
|
|
|
(221
|
)
|
|
|
(176
|
)
|
|
|
(417
|
)
|
Long-term derivatives
|
|
|
(9,072
|
)
|
|
|
(6,881
|
)
|
|
|
(19,717
|
)
|
Other assets
|
|
|
(3
|
)
|
|
|
578
|
|
|
|
(812
|
)
|
Accounts payable
|
|
|
(2,555
|
)
|
|
|
(1,748
|
)
|
|
|
3,268
|
|
Other current liabilities
|
|
|
(167
|
)
|
|
|
2,025
|
|
|
|
9,669
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
114,970
|
|
|
|
189,235
|
|
|
|
73,369
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of other property and equipment
|
|
|
(88
|
)
|
|
|
(315
|
)
|
|
|
(510
|
)
|
Acquisition of oil and natural gas properties
|
|
|
(31,960
|
)
|
|
|
(215
|
)
|
|
|
(495,252
|
)
|
Development of oil and natural gas properties
|
|
|
(9,037
|
)
|
|
|
(41,803
|
)
|
|
|
(29,010
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(41,085
|
)
|
|
|
(42,333
|
)
|
|
|
(524,772
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of common units, net of issuance costs
|
|
|
170,089
|
|
|
|
|
|
|
|
193,461
|
|
Proceeds from long-term debt, net of issuance costs
|
|
|
227,061
|
|
|
|
243,310
|
|
|
|
270,758
|
|
Payments on long-term debt
|
|
|
(125,000
|
)
|
|
|
(141,000
|
)
|
|
|
(225,000
|
)
|
Deemed distributions to affiliates in connection with
acquisitions
|
|
|
(251,247
|
)
|
|
|
(125,027
|
)
|
|
|
|
|
Cash distributions to unitholders
|
|
|
(81,652
|
)
|
|
|
(74,401
|
)
|
|
|
(1,338
|
)
|
Contribution by EAC in connection with purchase of Elk Basin
Assets
|
|
|
|
|
|
|
|
|
|
|
93,658
|
|
Net contributions from (distributions to) owner related to
pre-partnership or pre-IPO operations
|
|
|
(11,409
|
)
|
|
|
(48,796
|
)
|
|
|
119,867
|
|
Other
|
|
|
(592
|
)
|
|
|
(372
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(72,750
|
)
|
|
|
(146,286
|
)
|
|
|
451,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in cash and cash equivalents
|
|
|
1,135
|
|
|
|
616
|
|
|
|
3
|
|
Cash and cash equivalents, beginning of period
|
|
|
619
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
1,754
|
|
|
$
|
619
|
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements
84
ENCORE
ENERGY PARTNERS LP
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 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. Encore Energy
Partners GP LLC (the General Partner), a Delaware
limited liability company and indirect wholly owned subsidiary
of EAC, serves as ENPs general partner and Encore Energy
Partners Operating LLC (OLLC), a Delaware limited
liability company and direct wholly owned subsidiary of ENP,
owns and operates ENPs properties. ENPs properties
and oil and natural gas reserves are located in four core areas:
|
|
|
|
|
the Big Horn Basin in Wyoming and Montana;
|
|
|
|
the Permian Basin in West Texas and New Mexico;
|
|
|
|
the Williston Basin in North Dakota and Montana; and
|
|
|
|
the Arkoma Basin in Arkansas and Oklahoma.
|
EACs
Merger with Denbury
On October 31, 2009, EAC, the ultimate parent of the
General Partner, entered into an Agreement and Plan of Merger
(the Merger Agreement) with Denbury Resources Inc.
(Denbury) pursuant to which EAC has agreed to merge
with and into Denbury, with Denbury as the surviving entity (the
Merger). The Merger Agreement, which was unanimously
approved by EACs Board of Directors and by Denburys
Board of Directors, provides for Denburys acquisition of
all of the issued and outstanding shares of EAC common stock.
Completion of the Merger is conditioned upon, among other
things, approval by the stockholders of both EAC and Denbury.
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 in full 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 (EAP
Operating), a Delaware limited liability company and
direct wholly owned subsidiary of EAC, and reduce outstanding
borrowings under OLLCs revolving credit facility. Please
read Note 6. Long-Term Debt for additional
discussion of ENPs long-term debt.
At the closing of the IPO, the following transactions, among
others, 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 contributed certain oil and natural gas
properties and related assets in the Permian Basin in West Texas
(the Permian Basin Assets) to ENP in exchange for
4,043,478 common units; and
|
85
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
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 over-allotment option to purchase additional
common units, the General Partner exchanged such number of
common units for general partner units as was necessary to
enable it to maintain its then two percent general partner
interest in ENP. The General Partner received the common units
through capital contributions from EAC of common units it 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 performs administrative services for ENP.
Please read Note 11. 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 adopted by the board of
directors of the General Partner. Please read Note 9.
Unit-Based Compensation Plans for additional discussion
regarding the LTIP.
|
|
Note 2.
|
Summary
of Significant Accounting Policies
|
Principles
of Consolidation
ENPs 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 ENPs
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.
In February 2008, ENP acquired certain oil and natural gas
properties and related assets in the Permian Basin in West Texas
and in the Williston Basin in North Dakota (the Permian
and Williston Basin Assets) from Encore Operating. In
January 2009, ENP acquired certain oil and natural gas
properties and related assets in the Arkoma Basin in Arkansas
and royalty interest properties primarily in Oklahoma, as well
as 10,300 unleased mineral acres (the Arkoma Basin
Assets) from Encore Operating. In June 2009, ENP acquired
certain oil and natural gas properties and related assets in the
Williston Basin in North Dakota and Montana (the Williston
Basin Assets) from Encore Operating. In August 2009, ENP
acquired certain oil and natural gas properties and related
assets in the Big Horn Basin in Wyoming, the Permian Basin in
West Texas and New Mexico, and the Williston Basin in Montana
and North Dakota (the Rockies and Permian Basin
Assets) from Encore Operating. Because these assets were
acquired from an affiliate, the acquisitions were accounted for
as transactions between entities under common control, similar
to a pooling of interests, whereby the assets and liabilities of
the acquired properties were recorded at Encore Operatings
carrying value and ENPs historical financial information
was recast to include the acquired properties for all periods in
which the properties were owned by Encore Operating.
Accordingly, the consolidated financial statements and notes
thereto reflect the historical results of ENP combined with
those of the Permian and Williston Basin Assets, the Arkoma
Basin Assets, the Williston Basin Assets, and the Rockies and
Permian Basin Assets. Please read Note 3.
Acquisitions for additional discussion of these
acquisitions.
The results of operations of the Williston Basin Assets and the
Rockies and Permian Basin Assets related to pre-partnership
operations were allocated to the EAC affiliates based on their
respective ownership percentages in ENP. The effect of recasting
ENPs consolidated financial statements to account for this
86
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
common control transaction increased ENPs net income by
approximately $42.2 million and $23.9 million in 2008
and 2007, respectively.
ENP, the Permian Basin Assets, the Permian and Williston Basin
Assets, the Arkoma Basin Assets, Williston Basin Assets, and the
Rockies and Permian Basin Assets were 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, liabilities, revenues, and expenses, and the disclosure
of contingent assets and liabilities in the consolidated
financial statements. 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.
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 ENPs Consolidated Statements of Cash Flows.
Prior to the formation of ENP, EAC provided cash as needed to
support the operations of the Predecessor and collected cash
from sales of production. Net cash received by or paid to 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 (Loss) and
Consolidated Statements of Cash Flows.
The following table sets forth supplemental disclosures of cash
flow information for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2009
|
|
2008
|
|
2007
|
|
|
(In thousands)
|
|
Cash paid during the period for:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
9,761
|
|
|
$
|
6,614
|
|
|
$
|
11,857
|
|
Income taxes
|
|
|
297
|
|
|
|
|
|
|
|
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Contribution of commodity derivative contracts from EAC
|
|
|
|
|
|
|
|
|
|
|
9,404
|
|
Contribution of Permian Basin Assets from EAC
|
|
|
|
|
|
|
|
|
|
|
26,229
|
|
Issuance of common units in connection with acquisition of net
profits interest in certain Crockett County properties(a)
|
|
|
|
|
|
|
5,748
|
|
|
|
|
|
Issuance of common units in connection with acquisition of the
Permian and Williston Basin Assets(a)
|
|
|
|
|
|
|
125,027
|
|
|
|
|
|
|
|
|
(a) |
|
Please read Note 3. Acquisitions for additional
discussion. |
87
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, 2009 and 2008, 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 Financial Accounting Standards Board
(FASB) Accounting Standards Codification
(ASC) 932 (formerly Statement of Financial
Accounting Standards (SFAS) No. 19,
Financial Accounting and Reporting by Oil and Gas
Producing Companies). 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.
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 ENPs Consolidated Statements of Operations and shown as
an adjustment to net income (loss) in the Operating
activities section of ENPs 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 ENP
is making sufficient progress 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 an adjustment to net income
(loss) in the Operating activities section of
ENPs 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 unsuccessful, 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 ENPs 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., ENPs independent reserve engineer,
estimates ENPs 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.
88
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In accordance with ASC
360-10, 205,
840, 958, and
855-10-60-1
(formerly SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets) 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 assets carrying
value to its undiscounted expected future net cash flows, then
an impairment charge is recognized to the extent the
assets carrying value exceeds its fair value. Expected
future net cash flows are based on existing proved reserves (and
appropriately risk-adjusted probable reserves), forecasted
production information, and managements outlook of future
commodity prices. Any impairment charge incurred is expensed and
reduces the net basis in the asset. 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 it believes a market participant would use in bidding
on acquisitions
and/or
assessing capital projects. These price assumptions are critical
to the impairment analysis as lower prices could trigger
impairment.
Unproved properties, the majority 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 impairment, a loss is 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 is 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:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Proved leasehold costs
|
|
$
|
609,692
|
|
|
$
|
580,695
|
|
Wells and related equipment Completed
|
|
|
241,953
|
|
|
|
227,970
|
|
Wells and related equipment In process
|
|
|
188
|
|
|
|
6,238
|
|
|
|
|
|
|
|
|
|
|
Total proved properties
|
|
$
|
851,833
|
|
|
$
|
814,903
|
|
|
|
|
|
|
|
|
|
|
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 in
the accompanying Consolidated Statements of Operations.
Goodwill
and Other Intangible Assets
ENP accounts for goodwill and other intangible assets under the
provisions of ASC 350,
730-10-60-3,
323-10-35-13,
205-20-60-4,
and
280-10-60-2
(formerly 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 is tested for
impairment annually on December 31 or whenever indicators of
impairment exist. 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. If indicators of impairment are determined to
exist, an impairment charge is recognized for the amount by
which the carrying value of goodwill exceeds its implied fair
value.
89
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
ENP utilizes both a market capitalization and an income approach
to determine the fair value of its reporting units. The primary
component of the income approach is the estimated discounted
future net cash flows expected to be recovered from the
reporting units oil and natural gas properties. ENPs
analysis concluded that there was no impairment of goodwill as
of December 31, 2009. Significant decreases in the prices
of oil and natural gas or significant negative reserve
adjustments from the December 31, 2009 assessment could
change ENPs estimates of the fair value of its reporting
units and could result in an impairment charge.
Intangible assets with definite useful lives are amortized over
their estimated useful lives. In accordance with ASC
410-20,
450-20,
835-20,
360-10-35,
840-10, and
980-410, 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 the 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. As of December 31, 2009, the gross carrying value of
this contact was $4.2 million and accumulated amortization
was $0.9 million. During each of 2009, 2008, and 2007, ENP
recorded approximately $0.3 million of amortization expense
related to this contract. The net carrying value is shown as
Other intangibles, net on the accompanying
Consolidated Balance Sheets and is being amortized on a
straight-line basis through November 2020. 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 ASC
410-20,
450-20,
835-20,
360-10-35,
840-10, and
980-410
(formerly 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
ENPs oil and natural gas properties. The liability is
recorded at its discounted risk adjusted fair value and then
accreted each period until it is settled or the asset 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.
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. ENP accounts
for unit-based compensation according to the provisions of ASC
718, 505-50,
and
260-10-60-1A
(formerly SFAS No. 123 (revised 2004),
Share-Based Payment), which requires the
recognition of compensation expense for unit-based awards over
the requisite service period in an amount equal to the grant
date fair value of the awards. Please read Note 9.
Unit-Based Compensation Plans for additional discussion of
ENPs 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. All
revenues are derived from customers located in the United States.
90
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Major
Customers / Concentration of Credit Risk
The following purchasers accounted for 10 percent or
greater of the sales of production for the period indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Total Sales of
|
|
|
Production for the Year Ended
|
|
|
December 31,
|
Purchaser
|
|
2009
|
|
2008
|
|
2007
|
|
Marathon Oil Corporation
|
|
|
43
|
%
|
|
|
19
|
%
|
|
|
24
|
%
|
ConocoPhillips
|
|
|
(a
|
)
|
|
|
17
|
%
|
|
|
10
|
%
|
Tesoro Refining & Marketing Co
|
|
|
(a
|
)
|
|
|
15
|
%
|
|
|
17
|
%
|
|
|
|
(a) |
|
Less than 10 percent for the period indicated. |
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 ENPs taxable income. Therefore, no provision for
current or deferred federal income taxes has been provided for
in the accompanying consolidated financial statements. However,
the portion of ENPs operations that is located in Texas is
subject to an entity-level tax, the Texas margin tax, at an
effective rate of up to 0.7 percent of 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 unitholders tax accounting, which
is partially dependent upon the unitholders 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 unitholders tax attributes in ENP.
ENP accounts for uncertainty in income taxes in accordance with
ASC 740,
805-740, and
835-10
(formerly FASB Interpretation No. 48, Accounting
for Uncertainty in Income Taxes an Interpretation of
FASB Statement No. 109). ENP performs a periodic
evaluation of tax positions to review the appropriate
recognition threshold for each tax position recognized in its
consolidated financial statements. As of December 31, 2009
and 2008, all of ENPs tax positions met the
more-likely-than-not threshold prescribed by ASC
740,
805-740, and
835-10. As a
result, no additional tax expense, interest, or penalties have
been accrued.
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 volumes and prices
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
91
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
ENPs proportionate share of natural gas production. If
ENPs overproduced imbalance position (i.e., ENP has
cumulatively been over-allocated production) is greater than
ENPs 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 ENPs properties, or
oil in pipelines that has not been delivered to the purchaser.
Natural gas imbalances at December 31, 2009 and 2008 were
15,139 million British thermal units (MMBtu)
and 38,010 MMBtu, respectively, over-delivered to ENP, the
value of which was approximately $0.1 million and
$0.2 million, respectively.
Marketing
Revenues and Expenses
In March 2007, ENP acquired a crude oil pipeline and a natural
gas pipeline as part of the Big Horn 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 oil and natural gas
purchased from third parties, as well as pipeline tariffs
charged for transportation volumes through ENPs pipelines.
Marketing revenues derived from sales of oil or 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. As ENP takes title to the oil and natural
gas and has risks and rewards of ownership, these transactions
are presented gross in the accompanying Consolidated Statements
of Operations, unless they meet the criteria for netting as
outlined in ASC
845-10
(formerly Emerging Issues Task Force (EITF) Issue
No. 04-13,
Accounting for Purchases and Sales of Inventory with
the Same Counterparty).
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 ENPs exposure to
commodity price decreases, but they can also limit the benefit
ENP might otherwise receive from commodity price increases.
ENPs risk management activity is generally accomplished
through
over-the-counter
derivative 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 ASC 815 (formerly
SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities), which requires
each derivative instrument to be recorded in the balance sheet
at fair value. If a derivative has not been designated as a
hedge or does not otherwise 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, the effective portion of changes in fair
value can be recognized in accumulated other comprehensive
income or loss until such time as the hedged item is recognized
in earnings. In order to qualify for cash flow hedge accounting,
the cash flows from the hedging instrument must be highly
92
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
effective in offsetting changes in cash flows of the hedged
item. In addition, all hedging relationships must be designated,
documented, and reassessed periodically.
ENP has elected to designate its outstanding 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 loss on the
accompanying Consolidated Balance Sheets and reclassified into
earnings in the same period in which the hedged transaction
affects earnings. Any ineffective portion of the
mark-to-market
gain or loss is recognized in earnings and included in
Derivative fair value loss (gain) in the
accompanying Consolidated Statements of Operations.
ENP has not elected to designate its current portfolio of
commodity derivative contracts as hedges. Therefore, changes in
fair value of these derivative instruments are recognized in
earnings and included in Derivative fair value loss
(gain) in the accompanying Consolidated Statements of
Operations.
Earnings
Per Unit
ENPs 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 ASC
260-10
(formerly EITF Issue
No. 03-6,
Participating Securities and the Two {d208}
Class Method under FASB Statement No. 128).
Under the two-class method of calculating earnings per unit,
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 distributions
with common units. For purposes of calculating earnings per
unit, general partner units, unvested phantom units, and
unvested management incentive units are considered 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 participating
securities, by the weighted average common units outstanding.
Please read New Accounting Pronouncements below and
Note 8. Earnings Per Unit for additional
discussion.
Comprehensive
Income (Loss)
ENP has elected to show comprehensive income (loss) as part of
its Consolidated Statements of Partners Equity and
Comprehensive Income (Loss) rather than in its Consolidated
Statements of Operations or in a separate statement.
FASB
Launches Accounting Standards Codification
In June 2009, the FASB issued ASC
105-10
(formerly SFAS No. 168, The FASB Accounting
Standards Codification and the Hierarchy of Generally Accepted
Accounting Principles). ASC
105-10
establishes the Codification as the sole source of authoritative
accounting principles recognized by the FASB to be applied by
all nongovernmental entities in the preparation of financial
statements in conformity with GAAP. ASC
105-10 was
prospectively effective for financial statements issued for
fiscal years ending on or after September 15, 2009, and
interim periods within those fiscal years. The adoption of ASC
105-10 on
July 1, 2009 did not impact ENPs results of
operations or financial condition.
Following the Codification, the FASB does not issue new
standards in the form of Statements, FASB Staff Positions
(FSP), or EITF Abstracts. Instead, it issues
Accounting Standards Updates (ASU), which update the
Codification, provide background information about the guidance,
and provide the basis for conclusions on the changes to the
Codification.
The Codification did not change GAAP; however, it did change the
way GAAP is organized and presented. As a result, these changes
impact how companies, including ENP, reference GAAP in their
financial statements and in their significant accounting
policies.
93
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
New
Accounting Pronouncements
ASC
820-10
(formerly FSP
No. FAS 157-2,
Effective Date of FASB Statement
No. 157)
In February 2008, the FASB issued ASC
820-10,
which delayed the effective date of ASC
820-10 for
one year for nonfinancial assets and liabilities, except those
that are recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually). ASC
820-10 was
prospectively effective for financial statements issued for
fiscal years beginning after November 15, 2008, and interim
periods within those fiscal years. ENP elected a partial
deferral of ASC
820-10 for
all instruments within the scope of ASC
820-10,
including, but not limited to, its asset retirement obligations
and indefinite lived assets. The adoption of ASC
820-10 on
January 1, 2009 as it relates to nonfinancial assets and
liabilities did not have a material impact on ENPs results
of operations or financial condition. Please read
Note 10. Fair Value Measurements for additional
discussion.
ASC 805
(formerly SFAS No. 141 (revised 2007), Business
Combinations)
In December 2007, the FASB issued ASC 805, which 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. In April 2009, the FASB issued ASC
805-20
(formerly FSP No. FAS 141(R)-1, Accounting
for Assets Acquired and Liabilities Assumed in a Business
Combination That Arises from Contingencies), which
amends and clarifies ASC 805 to address application issues,
including: (1) initial recognition and measurement;
(2) subsequent measurement and accounting; and
(3) disclosure of assets and liabilities arising from
contingencies in a business combination. ASC 805 and ASC
805-20 were
prospectively effective for business combinations consummated in
fiscal years beginning on or after December 15, 2008. The
accounting for transactions between entities under common
control is unchanged under ASC 805 and ASC
805-20. The
application of ASC 805 and ASC
805-20 to
the acquisition of certain oil and natural gas properties and
related assets during 2009 was nominal. Please read
Note 3. Acquisitions for additional discussion.
ASC
815-10
(formerly SFAS No. 161, Disclosures about
Derivative Instruments and Hedging Activities an
amendment of FASB Statement No. 133)
In March 2008, the FASB issued ASC
815-10,
which requires enhanced disclosures: including (1) how and
why an entity uses derivative instruments; (2) how
derivative instruments and related hedged items are accounted
for under ASC 815; and (3) how derivative instruments and
related hedged items affect an entitys financial position,
financial performance, and cash flows. ASC
815-10 was
prospectively effective for financial statements issued for
fiscal years beginning on or after November 15, 2008, and
interim periods within those fiscal years. The adoption of ASC
815-10 on
January 1, 2009 required additional disclosures regarding
ENPs derivative instruments; however, it did not impact
ENPs results of operations or financial condition. Please
read Note 10. Fair Value Measurements for
additional discussion.
ASC
260-10
(formerly EITF Issue
No. 07-4,
Application of the Two-Class Method under FASB
Statement No. 128, Earnings per Share, to Master Limited
Partnerships)
In March 2008, the FASB issued ASC
260-10,
which addresses how master limited partnerships should calculate
earnings per unit using the two-class method and how current
period earnings of a master limited partnership should be
allocated to the general partner, limited partners, and other
participating securities. ASC
260-10 was
retrospectively effective for financial statements issued for
fiscal years beginning after December 15, 2008, and interim
periods within those years. In the accompanying Consolidated
Financial Statements,
94
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
periods prior to the adoption of ASC
260-10 have
been restated to calculate earnings per unit in accordance with
this pronouncement. The retrospective application of ASC
260-10
reduced ENPs basic and diluted earnings per common unit by
$0.01 for the year ended December 31, 2007. The adoption of
ASC 260-10
did not have an impact on ENPs basic or diluted earnings
per common unit for the year ended December 31, 2008.
Please read Note 8. Earnings Per Unit for
additional discussion.
ASC
260-10
(formerly FSP No. EITF
03-6-1,
Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating
Securities)
In June 2008, the FASB issued ASC
260-10,
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. ASC
260-10 was
retroactively effective for financial statements issued for
fiscal years beginning after December 15, 2008, and interim
periods within those years. In the accompanying Consolidated
Financial Statements, periods prior to the adoption of ASC
260-10 have
been restated to calculate earnings per unit in accordance with
this pronouncement. Please read Note 8. Earnings Per
Unit for additional discussion.
SEC
Release
No. 33-8995,
Modernization of Oil and Gas Reporting
(Release
33-8995)
In December 2008, the United States Securities and Exchange
Commission (the SEC) issued Release
33-8995,
which amends oil and natural gas reporting requirements under
Regulations S-K and S-X. Release
33-8995 also
adds a section to
Regulation S-K
(Subpart 1200) to codify the revised disclosure
requirements in Securities Act Industry Guide 2, which is being
phased out. Release
33-8995
permits the use of new technologies to determine proved reserves
if those technologies have been demonstrated empirically to lead
to reliable conclusions about reserves volumes. Release
33-8995 will
also allow companies to disclose their probable and possible
reserves to investors at the companys option. In addition,
the new disclosure requirements require companies to:
(1) report the independence and qualifications of its
reserves preparer or auditor; (2) file reports when a third
party is relied upon to prepare reserves estimates or conduct a
reserves audit; and (3) report oil and gas reserves using
an average price based upon the prior
12-month
period rather than a year-end price, unless prices are defined
by contractual arrangements, excluding escalations based on
future conditions. Release
33-8995 was
prospectively effective for financial statements issued for
fiscal years ending on or after December 31, 2009.
ASC
855-10
(formerly SFAS No. 165, Subsequent
Events)
In June 2009, the FASB issued ASC
855-10 to
establish general standards of accounting for and disclosure of
events that occur after the balance sheet date but before
financial statements are issued or available to be issued. In
particular, ASC
855-10 sets
forth: (1) the period after the balance sheet date during
which management of a reporting entity should evaluate events or
transactions that may occur for potential recognition or
disclosure in the financial statements; (2) the
circumstances under which an entity should recognize events or
transactions occurring after the balance sheet date in its
financial statements; and (3) the disclosures that an
entity should make about events or transactions that occurred
after the balance sheet date. ASC
855-10 was
prospectively effective for financial statements issued for
interim or annual periods ending after June 15, 2009. The
adoption of ASC
855-10 on
June 30, 2009 did not impact ENPs results of
operations or financial condition.
ASU
No. 2009-05,
Fair Value Measurement and Disclosure: Measuring
Liabilities at Fair Value (ASU
2009-05)
In August 2009, the FASB issued ASU
2009-05 to
provide clarification on measuring liabilities at fair value
when a quoted price in an active market is not available. In
particular, ASU
2009-05
specifies that a
95
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
valuation technique should be applied that used either the quote
of the liability when traded as an asset, the quoted prices for
similar liabilities or similar liabilities when traded as
assets, or another valuation technique consistent with existing
fair value measurement guidance. ASU
2009-05 was
prospectively effective for financial statements issued for
interim or annual periods ending after October 1, 2009. The
adoption of ASU
2009-05 on
December 31, 2009 did not impact ENPs results of
operations or financial condition.
ASU
No. 2010-03,
Oil and Gas Reserve Estimation and Disclosure
(ASU
2010-03)
In January 2010, the FASB issued ASU
2010-03 to
align the oil and natural gas reserve estimation and disclosure
requirements of Extractive Activities Oil and Gas
(ASC 932) with the requirements in the SECs final
rule, Modernization of the Oil and Gas
Reporting. ASU
2010-03 was
prospectively effective for financial statements issued for
annual periods ending on or after December 31, 2009.
ASU
No. 2010-06,
Improving Disclosures about Fair Value Measurements
(ASU
2010-06)
In January 2010, the FASB issued ASU
2010-06 to
require additional information to be disclosed principally in
respect of level 3 fair value measurements and transfers to
and from Level 1 and Level 2 measurements; in
addition, enhanced disclosure is required concerning inputs and
valuation techniques used to determine Level 2 and
Level 3 fair value measurements. ASU
2010-06 was
generally effective for interim and annual reporting periods
beginning after December 15, 2009; however, the
requirements to disclose separately purchases, sales, issuances,
and settlements in the Level 3 reconciliation are effective
for fiscal years beginning after December 15, 2010 (and for
interim periods within such years) with early adoption allowed.
The adoption of ASU
2010-06 on
December 31, 2009 did not impact ENPs results of
operations or financial condition.
Rockies
and Permian Basin Assets
In August 2009, ENP acquired the Rockies and Permian Basin
Assets from Encore Operating for approximately
$179.6 million in cash, which was financed through
borrowings under OLLCs revolving credit facility and
proceeds from the issuance of ENP common units to the public. As
previously discussed, the acquisition was accounted for as a
transaction between entities under common control. Therefore,
the assets and liabilities of the acquired properties were
recorded at Encore Operatings carrying value as of
July 31, 2009 of approximately $194.4 million and
$4.2 million, respectively, and the historical financial
information of ENP was recast to include the Rockies and Permian
Basin Assets for all periods the properties were owned by Encore
Operating. As the historical basis in the Rockies and Permian
Basin Assets is included in the accompanying Consolidated
Balance Sheets, the cash purchase price was recorded as a deemed
distribution when paid to EAC.
Williston
Basin Assets
In June 2009, ENP acquired the Williston Basin Assets from
Encore Operating for approximately $25.2 million in cash,
which was financed through borrowings under OLLCs
revolving credit facility and proceeds from the issuance of ENP
common units to the public. As previously discussed, the
acquisition was accounted for as a transaction between entities
under common control. Therefore, the assets and liabilities of
the acquired properties were recorded at Encore Operatings
carrying value as of May 31, 2009 of approximately
$31.9 million and $1.3 million, respectively, and the
historical financial information of ENP was recast to include
the Williston Basin Assets for all periods the properties were
owned by Encore Operating. As the historical basis in the
Williston Basin Assets is included in the accompanying
Consolidated Balance Sheets, the cash purchase price was
recorded as a deemed distribution when paid to EAC.
96
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Vinegarone
Assets
In May 2009, ENP acquired certain natural gas properties in the
Vinegarone Field in Val Verde County, Texas (the
Vinegarone Assets) from an independent energy
company for approximately $27.5 million in cash, which was
financed through proceeds from the issuance of ENP common units
to the public. The results of operations of the Vinegarone
Assets are included with those of ENP from the date of
acquisition forward.
Arkoma
Basin Assets
In January 2009, ENP acquired the Arkoma Basin Assets from
Encore Operating for approximately $46.4 million in cash,
which was financed through borrowings under OLLCs
revolving credit facility. As previously discussed, the
acquisition was accounted for as a transaction between entities
under common control. Therefore, the assets and liabilities of
the acquired properties were recorded at Encore Operatings
carrying value as of December 31, 2008 of approximately
$18.1 million and $0.7 million, respectively, and the
historical financial information of ENP was recast to include
the Arkoma Basin Assets for all periods the properties were
owned by Encore Operating. As the historical basis in the Arkoma
Basin Assets is included in the accompanying Consolidated
Balance Sheets, the cash purchase price was recorded as a deemed
distribution when paid to EAC.
Permian
and Williston Basin Assets
In February 2008, ENP acquired the Permian and Williston Basin
Assets from Encore Operating for approximately
$125.0 million in cash and the issuance of 6,884,776 ENP
common units to Encore Operating. In determining the total
purchase price, the common units were valued at
$125.0 million. However, no accounting value was ascribed
to the common units as the cash consideration exceeded Encore
Operatings carrying value of the properties. The cash
portion of the purchase price was financed through borrowings
under OLLCs revolving credit facility. As previously
discussed, the acquisition was accounted for as a transaction
between entities under common control. Therefore, the assets and
liabilities of the acquired properties were recorded at Encore
Operatings carrying value as of December 31, 2007 of
approximately $105.0 million and $5.1 million,
respectively, and the historical financial information of ENP
was recast to include the Permian and Williston Basin Assets for
all periods the properties were owned by Encore Operating. As
the historical basis in the Permian and Williston Basin Assets
is included in the accompanying Consolidated Balance Sheets, the
cash purchase price was recorded as a deemed distribution when
paid to EAC.
In May 2008, ENP acquired an existing net profits interest in
certain of its properties in the Permian Basin in West Texas
from an independent energy company for 283,700 ENP common units,
which were valued at approximately $5.8 million at the time
of the acquisition.
Big
Horn Basin Assets
In March 2007, EAC acquired certain oil and natural gas
properties and related assets in the Big Horn Basin in Wyoming
and Montana (the Big Horn Basin Assets) from an
independent energy company. Prior to closing, EAC assigned the
rights and duties under the purchase and sale agreement relating
to the Elk Basin Assets to ENP. The purchase price for the Elk
Basin Assets was approximately $330.7 million in cash. The
results of operations of the Big Horn Basin Assets are included
with those of ENP from the date of acquisition forward.
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, and borrowings under OLLCs revolving credit
facility. Please read Note 6. Long-Term Debt
for additional discussion of ENPs long-term debt.
97
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following unaudited pro forma condensed financial data for
2007 (in thousands, except per unit amounts) 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, 2007. 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, 2007 and is not intended to be a
projection of future results.
|
|
|
|
|
Pro forma total revenues
|
|
$
|
197,408
|
|
|
|
|
|
|
Pro forma net income
|
|
$
|
19,621
|
|
|
|
|
|
|
Pro forma net loss per common unit:
|
|
|
|
|
Basic
|
|
$
|
(0.79
|
)
|
Diluted
|
|
$
|
(0.79
|
)
|
|
|
Note 4.
|
Commitments
and Contingencies
|
Litigation
ENP is a party to ongoing legal proceedings in the ordinary
course of business. The General Partners management does
not believe the result of these proceedings will have a material
adverse effect on ENPs business, financial position,
results of operations, liquidity, or ability to pay
distributions.
Leases
ENP leases equipment that have 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, 2009 (in thousands):
|
|
|
|
|
2010
|
|
$
|
687
|
|
2011
|
|
|
687
|
|
2012
|
|
|
514
|
|
2013
|
|
|
|
|
2014
|
|
|
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,888
|
|
|
|
|
|
|
ENPs operating lease rental expense was approximately
$1.1 million, $1.0 million, and $1.1 million in
2009, 2008, and 2007, 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 ENPs asset retirement obligations for the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Future abandonment liability at January 1
|
|
$
|
12,376
|
|
|
$
|
11,254
|
|
Acquisition of properties
|
|
|
67
|
|
|
|
|
|
Wells drilled
|
|
|
22
|
|
|
|
104
|
|
Accretion of discount
|
|
|
709
|
|
|
|
538
|
|
Plugging and abandonment costs incurred
|
|
|
(164
|
)
|
|
|
(62
|
)
|
Revision of previous estimates
|
|
|
120
|
|
|
|
542
|
|
|
|
|
|
|
|
|
|
|
Future abandonment liability at December 31
|
|
$
|
13,130
|
|
|
$
|
12,376
|
|
|
|
|
|
|
|
|
|
|
98
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As of December 31, 2009, $12.6 million of ENPs
asset retirement obligations were long-term and recorded in
Future abandonment cost, net of current portion and
$0.6 million were current and included in Other
current liabilities in the accompanying Consolidated
Balance Sheets. Approximately $4.7 million of the long-term
future abandonment liability represents the estimated cost for
decommissioning the Elk Basin natural gas processing plant.
Revolving
Credit Facility
OLLC is a party to a five-year credit agreement dated
March 7, 2007 (as amended, the OLLC Credit
Agreement). The OLLC Credit Agreement matures on
March 7, 2012. In March 2009, OLLC amended the OLLC Credit
Agreement to, among other things, increase the interest rate
margins and commitment fees applicable to loans made under the
OLLC Credit Agreement. In August 2009, OLLC amended the OLLC
Credit Agreement to, among other things, (1) increase the
borrowing base from $240 million to $375 million,
(2) increase the aggregate commitments of the lenders from
$300 million to $475 million, and (3) increase
the interest rate margins and commitment fees applicable to
loans made under the OLLC Credit Agreement. In November 2009,
OLLC amended the OLLC Credit Agreement, which will be effective
upon the closing of the Merger, to, among other things, permit
the consummation of the Merger from being a Change of
Control under the OLLC Credit Agreement.
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
$475 million. Availability under the OLLC Credit Agreement
is subject to a borrowing base, which is redetermined
semi-annually and upon requested special redeterminations. As of
December 31, 2009, the borrowing base was $375 million
and there were $255 million of outstanding borrowings and
$120 million of borrowing capacity under the OLLC Credit
Agreement.
OLLC incurs a commitment fee of 0.5 percent on the unused
portion of the OLLC Credit Agreement.
Obligations under the OLLC Credit Agreement are secured by a
first-priority security interest in substantially all of
OLLCs proved oil and natural gas reserves and in the
equity interests of OLLC and its restricted subsidiaries. In
addition, obligations under the OLLC Credit Agreement are
guaranteed by ENP and OLLCs 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) amount outstanding in
relation to the borrowing base and (2) whether the loan is
a Eurodollar loan or a base rate loan. Eurodollar loans under
the OLLC Credit Agreement bear interest at the Eurodollar rate
plus the applicable margin indicated in the following table, and
base rate loans under the OLLC Credit Agreement bear interest at
the base rate plus the applicable margin indicated in the
following table:
|
|
|
|
|
|
|
|
|
|
|
Applicable Margin for
|
|
Applicable Margin for
|
Ratio of Outstanding Borrowings to Borrowing Base
|
|
Eurodollar Loans
|
|
Base Rate Loans
|
|
Less than .50 to 1
|
|
|
2.250
|
%
|
|
|
1.250
|
%
|
Greater than or equal to .50 to 1 but less than .75 to 1
|
|
|
2.500
|
%
|
|
|
1.500
|
%
|
Greater than or equal to .75 to 1 but less than .90 to 1
|
|
|
2.750
|
%
|
|
|
1.750
|
%
|
Greater than or equal to .90 to 1
|
|
|
3.000
|
%
|
|
|
2.000
|
%
|
The Eurodollar rate for any interest period (either
one, two, three, or six months, as selected by ENP) is the rate
equal to the British Bankers Association London Interbank
Offered Rate (LIBOR) for deposits in dollars for a
similar interest period. The Base Rate is calculated
as the highest of: (1) the annual rate of
99
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
interest announced by Bank of America, N.A. as its prime
rate; (2) the federal funds effective rate plus
0.5 percent; or (3) except during a LIBOR
Unavailability Period, the Eurodollar rate (for dollar
deposits for a one-month term) for such day plus
1.0 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 including, among
others, the following:
|
|
|
|
|
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
OLLCs 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 to consolidated current liabilities of not less
than 1.0 to 1.0;
|
|
|
|
a requirement that ENP and OLLC maintain a ratio of consolidated
EBITDA to the sum of consolidated net interest expense plus
letter of credit fees of not less than 2.5 to 1.0; and
|
|
|
|
a requirement that ENP and OLLC maintain a ratio of consolidated
funded debt to consolidated adjusted EBITDA of not more than 3.5
to 1.0.
|
As of December 31, 2009, ENP and OLLC were in compliance
with all covenants of the OLLC Credit Agreement.
The OLLC Credit Agreement contains customary events of default
including, among others, the following:
|
|
|
|
|
failure to pay principal on any loan when due;
|
|
|
|
failure to pay accrued interest on any loan or fees when due and
such failure continues for more than three days;
|
|
|
|
failure to observe or perform covenants and agreements contained
in the OLLC Credit Agreement, subject in some cases to a
30-day grace
period after discovery or notice of such failure;
|
|
|
|
failure to make a payment when due on any other debt in a
principal amount equal to or greater than $3 million or any
other event or condition occurs which results in the
acceleration of such debt or entitles the holder of such debt to
accelerate the maturity of such debt;
|
|
|
|
the commencement of liquidation, reorganization, or similar
proceedings with respect to OLLC or any guarantor under
bankruptcy or insolvency law, or the failure of OLLC or any
guarantor generally to pay its debts as they become due;
|
|
|
|
the entry of one or more judgments in excess of $3 million
(to the extent not covered by insurance) and such judgment(s)
remain unsatisfied and unstayed for 30 days;
|
|
|
|
the occurrence of certain ERISA events involving an amount in
excess of $3 million;
|
100
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
there cease to exist liens covering at least 80 percent of
the borrowing base properties; or
|
|
|
|
the occurrence of a change in control.
|
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.
Subordinated
Credit Agreement
In March 2007, OLLC entered into a six-year subordinated credit
agreement with EAP Operating 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
at which point the credit agreement was terminated.
Long-Term
Debt Maturities
The following table shows ENPs long-term debt maturities
as of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
Total
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
Thereafter
|
|
|
(In thousands)
|
|
Revolving credit facility
|
|
$
|
255,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
255,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
During 2009, 2008, and 2007, the weighted average interest rate
for total indebtedness was 5.0 percent, 4.8 percent,
and 8.9 percent, respectively.
|
|
Note 7.
|
Partners
Equity and Distributions
|
Distributions
ENPs partnership agreement requires that, within
45 days after the end of each quarter, it distribute all of
its available cash (as defined in ENPs partnership
agreement) to its unitholders. Distributions are not cumulative.
ENP distributes available cash to its unitholders in accordance
with their ownership percentages.
The following table provides information regarding ENPs
distributions of available cash for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Distribution
|
|
|
|
|
|
|
Date
|
|
Declared per
|
|
|
|
Total
|
2009
|
|
Declared
|
|
Common Unit
|
|
Date Paid
|
|
Distribution
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Quarter ended December 31
|
|
|
1/25/2010
|
|
|
$
|
0.5375
|
|
|
|
2/12/2010
|
|
|
$
|
24,642
|
|
Quarter ended September 30
|
|
|
10/26/2009
|
|
|
$
|
0.5375
|
|
|
|
11/13/2009
|
|
|
|
24,642
|
|
Quarter ended June 30
|
|
|
7/27/2009
|
|
|
$
|
0.5125
|
|
|
|
8/14/2009
|
|
|
|
23,481
|
|
Quarter ended March 31
|
|
|
4/27/2009
|
|
|
$
|
0.5000
|
|
|
|
5/15/2009
|
|
|
|
16,813
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter ended December 31
|
|
|
1/26/2009
|
|
|
$
|
0.5000
|
|
|
|
2/13/2009
|
|
|
|
16,813
|
|
Quarter ended September 30
|
|
|
11/7/2008
|
|
|
$
|
0.6600
|
|
|
|
11/14/2008
|
|
|
|
22,191
|
|
Quarter ended June 30
|
|
|
8/11/2008
|
|
|
$
|
0.6881
|
|
|
|
8/14/2008
|
|
|
|
23,119
|
|
Quarter ended March 31
|
|
|
5/9/2008
|
|
|
$
|
0.5755
|
|
|
|
5/15/2008
|
|
|
|
19,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter ended December 31
|
|
|
2/6/2008
|
|
|
$
|
0.3875
|
|
|
|
2/14/2008
|
|
|
|
9,843
|
|
Quarter ended September 30
|
|
|
11/8/2007
|
|
|
$
|
0.0530
|
(a)
|
|
|
11/14/2007
|
|
|
|
1,346
|
|
|
|
|
(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. |
101
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Shelf
Registration Statement on
Form S-3
In November 2008, ENPs shelf registration
statement on
Form S-3
was declared effective by the SEC. Under the shelf registration
statement, ENP may offer common units, senior debt, or
subordinated debt in one or more offerings with a total initial
offering price of up to $1 billion.
Public
Offerings of Common Units
In July 2009, ENP issued 9,430,000 common units under its shelf
registration statement at a price to the public of $14.30 per
common unit. ENP used the net proceeds of approximately
$129.2 million, after deducting the underwriters
discounts and commissions of $5.4 million, in the
aggregate, and offering costs of approximately
$0.2 million, to fund a portion of the purchase price of
the Rockies and Permian Basin Assets.
In May 2009, ENP issued 2,760,000 common units under its shelf
registration statement at a price to the public of $15.60 per
common unit. ENP used the net proceeds of approximately
$40.9 million, after deducting the underwriters
discounts and commissions of $1.9 million, in the
aggregate, and offering costs of approximately
$0.2 million, to fund the purchase price of the Vinegarone
Assets and a portion of the purchase price of the Williston
Basin Assets.
|
|
Note 8.
|
Earnings
Per Unit
|
As discussed in Note 2. Summary of Significant
Accounting Policies, ENP adopted ASC
260-10 on
January 1, 2009 and all periods prior to adoption have been
restated to calculate earnings per unit in accordance therewith.
For 2008, basic earnings per unit and diluted earnings per unit
were unaffected by the adoption of ASC
260-10. For
2007, basic earnings per unit and diluted earnings per unit each
decreased $0.01 per common unit as a result of the adoption of
ASC 260-10.
For 2007, earnings per unit was calculated based on the net loss
for the period from the closing of the IPO in September 2007
through December 31, 2007.
102
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table reflects the allocation of net income (loss)
to ENPs limited partners and earnings per unit
computations for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
Net income (loss)
|
|
$
|
(40,329
|
)
|
|
$
|
220,756
|
|
|
$
|
21,706
|
|
Less: net income for pre-IPO and pre-partnership operations of
assets acquired from affiliates
|
|
|
(176
|
)
|
|
|
(51,640
|
)
|
|
|
(40,682
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to unitholders
|
|
$
|
(40,505
|
)
|
|
$
|
169,116
|
|
|
$
|
(18,976
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator for basic EPU:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to unitholders
|
|
$
|
(40,505
|
)
|
|
$
|
169,116
|
|
|
$
|
(18,976
|
)
|
Less: distributions earned by participating securities
|
|
|
(1,054
|
)
|
|
|
(4,498
|
)
|
|
|
(517
|
)
|
Plus: cash distributions in excess of (less than) income
allocated to the general partner
|
|
|
1,646
|
|
|
|
(1,548
|
)
|
|
|
616
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocated to limited partners
|
|
|
(39,913
|
)
|
|
|
163,070
|
|
|
|
(18,877
|
)
|
Plus: income allocated to dilutive participating securities
|
|
|
|
|
|
|
3,398
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator for diluted EPU
|
|
$
|
(39,913
|
)
|
|
$
|
166,468
|
|
|
$
|
(18,877
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic EPU:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common units outstanding
|
|
|
39,366
|
|
|
|
30,568
|
|
|
|
23,877
|
|
Effect of dilutive management incentive units(a)
|
|
|
|
|
|
|
1,367
|
|
|
|
|
|
Effect of dilutive phantom units(b)
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted EPU
|
|
|
39,366
|
|
|
|
31,938
|
|
|
|
23,877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(1.01
|
)
|
|
$
|
5.33
|
|
|
$
|
(0.79
|
)
|
Diluted
|
|
$
|
(1.01
|
)
|
|
$
|
5.21
|
|
|
$
|
(0.79
|
)
|
|
|
|
(a) |
|
For 2007, 550,000 management incentive units were outstanding
but were excluded from the diluted earnings per unit
calculations because their effect would have been antidilutive.
Please read Note 9. Unit-Based Compensation
Plans for additional discussion of the management
incentive units. |
|
(b) |
|
Unvested phantom units have no contractual obligation to absorb
losses of ENP. Therefore, for 2009 and 2007, 56,250 and 20,000
phantom units, respectively, were outstanding but were excluded
from the diluted earnings per unit calculations because their
effect would have been antidilutive. Please read
Note 9. Unit-Based Compensation Plans for
additional discussion of phantom units. |
|
|
Note 9.
|
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. During the fourth quarter of
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, and all 550,000 management incentive units were converted
into 1,715,205 ENP common units.
103
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The fair value of the management incentive units was estimated
on the date of grant using a discounted dividend model. During
2008 and 2007, ENP recognized non-cash unit-based compensation
expense for the management incentive units of approximately
$4.8 million and $6.8 million, respectively, which is
included in General and administrative expense in
the accompanying Consolidated Statements of Operations. 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
adopted 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 are eligible to be
granted awards 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 under the LTIP, ENP may issue common units,
acquire common units in the open market, or use common units
owned by EAC.
The total number of common units reserved for issuance pursuant
to the LTIP is 1,150,000. As of December 31, 2009, there
were 1,075,000 common units available for issuance under the
LTIP.
Phantom Units. Each October, ENP issues 5,000
phantom units to each member of the General Partners 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 to the
grantee; therefore, these phantom units are classified as equity
instruments. Phantom units vest equally over a four-year period.
The holders of phantom units also receive distribution
equivalent rights prior to vesting, which entitle them to
receive cash equal to the amount of any cash distributions paid
by ENP with respect to a common unit during the period the right
is outstanding. During 2009, 2008, and 2007, ENP recognized
non-cash unit-based compensation expense for the phantom units
of approximately $0.4 million, $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 ENPs
unvested phantom units for 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Grant Date
|
|
|
|
Shares
|
|
|
Fair Value
|
|
|
Outstanding at January 1, 2009
|
|
|
43,750
|
|
|
$
|
18.67
|
|
Granted
|
|
|
25,000
|
|
|
|
18.13
|
|
Vested
|
|
|
(12,500
|
)
|
|
|
18.83
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009
|
|
|
56,250
|
|
|
|
18.40
|
|
|
|
|
|
|
|
|
|
|
During 2009, 2008, and 2007, ENP issued 25,000, 30,000, and
20,000, respectively, phantom units to members of the General
Partners board of directors, the vesting of which is
dependent only on the passage of
104
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
time and continuation as a board member. The following table
provides information regarding ENPs outstanding phantom
units at December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year of Vesting
|
|
|
Year of Grant
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
Total
|
|
2007
|
|
|
5,000
|
|
|
|
5,000
|
|
|
|
|
|
|
|
|
|
|
|
10,000
|
|
2008
|
|
|
7,500
|
|
|
|
7,500
|
|
|
|
6,250
|
|
|
|
|
|
|
|
21,250
|
|
2009
|
|
|
6,250
|
|
|
|
6,250
|
|
|
|
6,250
|
|
|
|
6,250
|
|
|
|
25,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
18,750
|
|
|
|
18,750
|
|
|
|
12,500
|
|
|
|
6,250
|
|
|
|
56,250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009, ENP had $0.7 million of total
unrecognized compensation cost related to unvested phantom
units, which is expected to be recognized over a weighted
average period of 2.2 years. During 2009 and 2008, there
were 12,500 and 6,250, respectively, phantom units that vested,
the total fair value of which was $0.2 million and
$0.1 million, respectively.
|
|
Note 10.
|
Fair
Value Measurements
|
The following table sets forth ENPs book value and
estimated fair value of financial instruments as of the dates
indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2009
|
|
2008
|
|
|
Book
|
|
Fair
|
|
Book
|
|
Fair
|
|
|
Value
|
|
Value
|
|
Value
|
|
Value
|
|
|
(In thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,754
|
|
|
$
|
1,754
|
|
|
$
|
619
|
|
|
$
|
619
|
|
Accounts receivable trade
|
|
|
24,543
|
|
|
|
24,543
|
|
|
|
18,965
|
|
|
|
18,965
|
|
Accounts receivable affiliate
|
|
|
8,213
|
|
|
|
8,213
|
|
|
|
3,896
|
|
|
|
3,896
|
|
Commodity derivative contracts
|
|
|
26,304
|
|
|
|
26,304
|
|
|
|
113,628
|
|
|
|
113,628
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable trade
|
|
|
577
|
|
|
|
577
|
|
|
|
1,036
|
|
|
|
1,036
|
|
Accounts payable affiliate
|
|
|
2,780
|
|
|
|
2,780
|
|
|
|
5,468
|
|
|
|
5,468
|
|
Revolving credit facility
|
|
|
255,000
|
|
|
|
255,000
|
|
|
|
150,000
|
|
|
|
150,000
|
|
Commodity derivative contracts
|
|
|
19,547
|
|
|
|
19,547
|
|
|
|
229
|
|
|
|
229
|
|
Interest rate swaps
|
|
|
3,669
|
|
|
|
3,669
|
|
|
|
4,559
|
|
|
|
4,559
|
|
The book values of 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
the revolving credit facility approximates fair value as the
interest rate is variable. ENPs credit risk has not
changed materially from the date the revolving credit facility
was entered into. Commodity derivative contracts and interest
rate swaps are
marked-to-market
each period and are thus stated at fair value in the
accompanying Consolidated Balance Sheets.
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
105
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 enters into floor spreads. In a floor
spread, ENP purchases puts at a specified price (a
purchased put) and also sells a put at a lower price
(a short put). This strategy enables ENP to achieve
some downside protection for a portion of its production, while
funding the cost of such protection by selling a put at a lower
price. If the price of the commodity falls below the strike
price of the purchased put, then ENP has protection against
additional commodity price decreases for the covered production
down to the strike price of the short put. At commodity prices
below the strike price of the short put, the benefit from the
purchased put is generally offset by the expense associated with
the short put. For example, in 2007, ENP purchased oil put
options for 2,000 Bbls/D in 2010 at $65 per Bbl. As NYMEX
prices increased in 2008, ENP wanted to protect downside price
exposure at the higher price. In order to do this, ENP purchased
oil put options for 2,000 Bbls/D in 2010 at $75 per Bbl and
simultaneously sold oil put options for 2,000 Bbls/D in
2010 at $65 per Bbl. Thus, after these transactions were
completed, ENP had purchased two oil put options for
2,000 Bbls/D in 2010 (one at $65 per Bbl and one at $75 per
Bbl) and sold one oil put option for 2,000 Bbls/D in 2010
at $65 per Bbl. However, the net effect resulted in ENP owning
one oil put option for 2,000 Bbls/D at $75 per Bbl. In the
following tables, the purchased floor component of these floor
spreads are shown net and included with ENPs other floor
contracts.
The following tables summarize ENPs open commodity
derivative contracts as of December 31, 2009:
Oil
Derivative Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
|
|
|
Daily
|
|
|
Average
|
|
|
|
Daily
|
|
|
Average
|
|
|
|
Daily
|
|
|
Average
|
|
|
|
Asset (Liability)
|
|
|
|
Floor
|
|
|
Floor
|
|
|
|
Cap
|
|
|
Cap
|
|
|
|
Swap
|
|
|
Swap
|
|
|
|
Fair Market
|
|
Period
|
|
Volume
|
|
|
Price
|
|
|
|
Volume
|
|
|
Price
|
|
|
|
Volume
|
|
|
Price
|
|
|
|
Value
|
|
|
|
(Bbls)
|
|
|
(per Bbl)
|
|
|
|
(Bbls)
|
|
|
(per Bbl)
|
|
|
|
(Bbls)
|
|
|
(per Bbl)
|
|
|
|
(in thousands)
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,476
|
)
|
|
|
|
880
|
|
|
$
|
80.00
|
|
|
|
|
440
|
|
|
$
|
93.80
|
|
|
|
|
760
|
|
|
$
|
75.43
|
|
|
|
|
|
|
|
|
|
2,000
|
|
|
|
75.00
|
|
|
|
|
1,000
|
|
|
|
77.23
|
|
|
|
|
250
|
|
|
|
65.95
|
|
|
|
|
|
|
|
|
|
760
|
|
|
|
67.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,638
|
|
|
|
|
1,880
|
|
|
|
80.00
|
|
|
|
|
1,440
|
|
|
|
95.41
|
|
|
|
|
760
|
|
|
|
78.46
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
|
70.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
760
|
|
|
|
65.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
250
|
|
|
|
69.65
|
|
|
|
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,020
|
)
|
|
|
|
750
|
|
|
|
70.00
|
|
|
|
|
500
|
|
|
|
82.05
|
|
|
|
|
210
|
|
|
|
81.62
|
|
|
|
|
|
|
|
|
|
1,510
|
|
|
|
65.00
|
|
|
|
|
250
|
|
|
|
79.25
|
|
|
|
|
1,300
|
|
|
|
76.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3,858
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
106
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Natural
Gas Derivative Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
|
|
|
Daily
|
|
|
Average
|
|
|
|
Daily
|
|
|
Average
|
|
|
|
Daily
|
|
|
Average
|
|
|
|
Asset
|
|
|
|
Floor
|
|
|
Floor
|
|
|
|
Cap
|
|
|
Cap
|
|
|
|
Swap
|
|
|
Swap
|
|
|
|
Fair Market
|
|
Period
|
|
Volume
|
|
|
Price
|
|
|
|
Volume
|
|
|
Price
|
|
|
|
Volume
|
|
|
Price
|
|
|
|
Value
|
|
|
|
(Mcf)
|
|
|
(per Mcf)
|
|
|
|
(Mcf)
|
|
|
(per Mcf)
|
|
|
|
(Mcf)
|
|
|
(per Mcf)
|
|
|
|
(in thousands)
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
7,963
|
|
|
|
|
3,800
|
|
|
$
|
8.20
|
|
|
|
|
3,800
|
|
|
$
|
9.58
|
|
|
|
|
5,452
|
|
|
$
|
6.20
|
|
|
|
|
|
|
|
|
|
4,698
|
|
|
|
7.26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
550
|
|
|
|
5.86
|
|
|
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,105
|
|
|
|
|
3,398
|
|
|
|
6.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,952
|
|
|
|
6.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
550
|
|
|
|
5.86
|
|
|
|
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
547
|
|
|
|
|
898
|
|
|
|
6.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,452
|
|
|
|
6.26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
550
|
|
|
|
5.86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
10,615
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparty Risk. At December 31, 2009,
ENP had committed 10 percent or greater (in terms of fair
market value) of either its oil or natural gas derivative
contracts in asset positions to the following counterparties:
|
|
|
|
|
|
|
|
|
|
|
Fair Market Value of
|
|
Fair Market Value of
|
|
|
Oil Derivative
|
|
Natural Gas Derivative
|
|
|
Contracts
|
|
Contracts
|
Counterparty
|
|
Committed
|
|
Committed
|
|
|
(In thousands)
|
|
BNP Paribas
|
|
$
|
13,955
|
|
|
$
|
2,795
|
|
Calyon
|
|
|
3,820
|
|
|
|
6,167
|
|
Royal Bank of Canada
|
|
|
4,158
|
|
|
|
(a
|
)
|
Wachovia
|
|
|
3,069
|
|
|
|
1,148
|
|
|
|
|
(a) |
|
Less than 10 percent. |
In order to mitigate the credit risk of financial instruments,
ENP enters into master netting agreements with certain
counterparties. The master netting agreement is a standardized,
bilateral contract between a given counterparty and ENP. Instead
of treating each financial transaction between the counterparty
and ENP separately, the master netting agreement enables the
counterparty and ENP to aggregate all financial trades and treat
them as a single agreement. This arrangement is intended to
benefit ENP in three ways: (1) the netting of the value of
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 ENPs credit
exposure to a given counterparty in the event of close-out.
ENPs accounting policy is to not offset fair value amounts
for derivative instruments.
Interest
Rate Swaps
ENP uses derivative instruments in the form of interest rate
swaps, which hedge risk related to interest rate fluctuation,
whereby it converts the interest due on certain floating rate
debt under its revolving credit
107
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
facility to a weighted average fixed rate. The following table
summarizes ENPs open interest rate swaps as of
December 31, 2009, all of which were entered into with Bank
of America, N.A.:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
Fixed
|
|
Floating
|
Term
|
|
Amount
|
|
Rate
|
|
Rate
|
|
|
(In thousands)
|
|
|
|
|
|
Jan. 2010 Jan. 2011
|
|
$
|
50,000
|
|
|
|
3.1610
|
%
|
|
|
1-month LIBOR
|
|
Jan. 2010 Jan. 2011
|
|
|
25,000
|
|
|
|
2.9650
|
%
|
|
|
1-month LIBOR
|
|
Jan. 2010 Jan. 2011
|
|
|
25,000
|
|
|
|
2.9613
|
%
|
|
|
1-month LIBOR
|
|
Jan. 2010 Mar. 2012
|
|
|
50,000
|
|
|
|
2.4200
|
%
|
|
|
1-month LIBOR
|
|
During 2009 and 2008, settlements of interest rate swaps
increased ENPs interest expense by approximately
$3.8 million and $0.2 million, respectively.
Current
Period Impact
ENP recognizes derivative fair value gains and losses related
to: (1) ineffectiveness on derivative contracts designated
as hedges; (2) changes in the fair market value of
derivative contracts not designated as hedges;
(3) settlements on derivative contracts not designated as
hedges; and (4) premium amortization. The following table
summarizes the components of Derivative fair value loss
(gain) for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Ineffectiveness
|
|
$
|
2
|
|
|
$
|
372
|
|
|
$
|
|
|
Mark-to-market
loss (gain)
|
|
|
94,438
|
|
|
|
(101,595
|
)
|
|
|
23,470
|
|
Premium amortization
|
|
|
23,245
|
|
|
|
8,936
|
|
|
|
4,073
|
|
Settlements
|
|
|
(70,221
|
)
|
|
|
(4,593
|
)
|
|
|
(1,242
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative fair value loss (gain)
|
|
$
|
47,464
|
|
|
$
|
(96,880
|
)
|
|
$
|
26,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
Other Comprehensive Loss
At December 31, 2009 and 2008, Accumulated other
comprehensive loss on the accompanying Consolidated
Balance Sheets consisted entirely of deferred losses, net of
tax, on ENPs interest rate swaps of $3.4 million and
$4.3 million, respectively. During 2010, ENP expects to
reclassify $3.4 million of deferred losses from accumulated
other comprehensive loss to interest expense. The actual gains
or losses ENP will realize from its interest rate swaps may vary
significantly from the deferred losses recorded in
Accumulated other comprehensive loss in the
accompanying Consolidated Balance Sheet due to the fluctuation
of interest rates.
108
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Tabular
Disclosures of Fair Value Measurements
The following table summarizes the fair value of ENPs
derivative contracts as of the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives
|
|
|
Liability Derivatives
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
Balance
|
|
|
|
|
Balance
|
|
|
|
|
Balance
|
|
|
|
|
Balance
|
|
|
|
|
|
Sheet
|
|
Fair
|
|
|
Sheet
|
|
Fair
|
|
|
Sheet
|
|
Fair
|
|
|
Sheet
|
|
Fair
|
|
|
|
Location
|
|
Value
|
|
|
Location
|
|
Value
|
|
|
Location
|
|
Value
|
|
|
Location
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments under ASC
815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts
|
|
Derivatives current
|
|
$
|
12,881
|
|
|
Derivatives current
|
|
$
|
75,131
|
|
|
Derivatives current
|
|
$
|
6,393
|
|
|
Derivatives current
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts
|
|
Derivatives noncurrent
|
|
|
13,423
|
|
|
Derivatives noncurrent
|
|
|
38,497
|
|
|
Derivatives noncurrent
|
|
|
13,154
|
|
|
Derivatives noncurrent
|
|
|
229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not designated as hedging instruments under
ASC 815
|
|
|
|
$
|
26,304
|
|
|
|
|
$
|
113,628
|
|
|
|
|
$
|
19,547
|
|
|
|
|
$
|
229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives designated as hedging instruments under ASC
815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps
|
|
Derivatives current
|
|
$
|
|
|
|
Derivatives current
|
|
$
|
|
|
|
Derivatives current
|
|
$
|
3,421
|
|
|
Derivatives current
|
|
$
|
1,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps
|
|
Derivatives noncurrent
|
|
|
|
|
|
Derivatives noncurrent
|
|
|
|
|
|
Derivatives noncurrent
|
|
|
248
|
|
|
Derivatives - noncurrent
|
|
|
3,262
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives designated as hedging instruments under
ASC 815
|
|
|
|
$
|
|
|
|
|
|
$
|
|
|
|
|
|
$
|
3,669
|
|
|
|
|
$
|
4,559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
|
|
$
|
26,304
|
|
|
|
|
$
|
113,628
|
|
|
|
|
$
|
23,216
|
|
|
|
|
$
|
4,788
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the effect of derivative
instruments not designated as hedges under ASC 815 on the
Consolidated Statements of Operations for the periods indicated
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Loss (Gain)
|
|
|
|
|
Recognized in Income
|
Derivatives Not Designated as
|
|
Location of Loss (Gain)
|
|
Year Ended December 31,
|
Hedges Under ASC 815
|
|
Recognized in Income
|
|
2009
|
|
2008
|
|
2007
|
|
Commodity derivative contracts
|
|
|
Derivative fair value loss (gain
|
)
|
|
$
|
47,462
|
|
|
$
|
(97,252
|
)
|
|
$
|
26,301
|
|
The following tables summarize the effect of derivative
instruments designated as hedges under ASC 815 on the
Consolidated Statements of Operations for the periods indicated
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Loss Recognized
|
|
|
in Accumulated OCI
|
|
|
(Effective Portion)
|
Derivatives Designated as
|
|
Year Ended December 31,
|
Hedges Under ASC 815
|
|
2009
|
|
2008
|
|
2007
|
|
Interest rate swaps
|
|
$
|
2,946
|
|
|
$
|
4,505
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Loss Reclassified
|
|
|
from Accumulated
|
|
|
OCI into Income
|
|
|
(Effective Portion)
|
Location of Loss Reclassified from Accumulated
|
|
Year Ended December 31,
|
OCI into Income (Effective Portion)
|
|
2009
|
|
2008
|
|
2007
|
|
Interest expense
|
|
$
|
3,785
|
|
|
$
|
246
|
|
|
$
|
|
|
109
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Loss Recognized
|
|
|
in Income as Ineffective
|
|
|
Year Ended December 31,
|
Location of Loss Recognized in Income as Ineffective
|
|
2009
|
|
2008
|
|
2007
|
|
Derivative fair value loss (gain)
|
|
$
|
2
|
|
|
$
|
372
|
|
|
$
|
|
|
Fair
Value Hierarchy
ASC 820-10
established a fair value hierarchy that prioritizes the inputs
used to measure fair value. The three levels of the fair value
hierarchy defined by ASC
820-10 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
managements best estimate of fair value.
|
ENPs 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 were used to estimate the fair values of
ENPs 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-based 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-based 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 ENPs oil and natural gas calls,
puts, and short puts are average value options, which are not
exchange-traded contracts. Settlement is determined by the
average underlying price over a predetermined period of time.
ENP uses both observable and unobservable inputs in a
Black-Scholes valuation model to determine fair value.
Accordingly, these derivative instruments are classified within
the Level 3 valuation hierarchy. The observable inputs of
ENPs valuation model include: (1) current market and
contractual prices for the underlying instruments;
(2) quoted forward prices for oil and natural gas; and
(3) interest rates, such as a LIBOR curve for a term
similar to the commodity derivative contract. The unobservable
input of ENPs valuation model is volatility. The implied
volatilities for ENPs calls, puts, and short puts with
comparable strike prices are based on the settlement values from
certain exchange-traded contracts. The implied volatilities for
calls, puts, and short puts where there are no exchange-traded
contracts with the same strike price are extrapolated from
exchange-traded implied volatilities by an independent party.
|
ENP adjusts the valuations from the valuation model for
nonperformance risk, using managements estimate of the
counterpartys credit quality for asset positions and
ENPs credit quality for liability positions. ENP uses
multiple sources of third-party credit data in determining
counterparty nonperformance risk, including credit default
swaps. ENP considers the impact of netting and offset provisions
in the agreements on counterparty credit risk, including whether
the position with the counterparty is a net asset or net
liability. There were no changes in the valuation techniques
used to measure the fair value of ENPs oil and natural gas
calls, puts, or short puts during 2009.
110
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table sets forth ENPs assets and liabilities
that were accounted for at fair value on a recurring basis as of
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at Reporting Date Using
|
|
|
|
|
|
|
Quoted Prices in
|
|
|
|
|
|
Significant
|
|
|
|
Asset (Liability) at
|
|
|
Active Markets for
|
|
|
Significant Other
|
|
|
Unobservable
|
|
|
|
December 31,
|
|
|
Identical Assets
|
|
|
Observable Inputs
|
|
|
Inputs
|
|
Description
|
|
2009
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
|
(In thousands)
|
|
|
Oil derivative contracts swaps
|
|
$
|
(12,443
|
)
|
|
$
|
|
|
|
$
|
(12,443
|
)
|
|
$
|
|
|
Oil derivative contracts floors and caps
|
|
|
8,585
|
|
|
|
|
|
|
|
|
|
|
|
8,585
|
|
Natural gas derivative contracts swaps
|
|
|
2,087
|
|
|
|
|
|
|
|
2,087
|
|
|
|
|
|
Natural gas derivative contracts floors and caps
|
|
|
8,528
|
|
|
|
|
|
|
|
|
|
|
|
8,528
|
|
Interest rate swaps
|
|
|
(3,669
|
)
|
|
|
|
|
|
|
(3,669
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,088
|
|
|
$
|
|
|
|
$
|
(14,025
|
)
|
|
$
|
17,113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the changes in the fair value of
ENPs Level 3 assets and liabilities for 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using Significant
|
|
|
|
Unobservable Inputs (Level 3)
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
Oil Derivative
|
|
|
Derivative
|
|
|
|
|
|
|
Contracts Floors
|
|
|
Contracts Floors
|
|
|
|
|
|
|
and Caps
|
|
|
and Caps
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Balance at January 1, 2009
|
|
$
|
95,430
|
|
|
$
|
12,741
|
|
|
$
|
108,171
|
|
Total gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings
|
|
|
(32,249
|
)
|
|
|
8,940
|
|
|
|
(23,309
|
)
|
Settlements
|
|
|
(54,596
|
)
|
|
|
(13,153
|
)
|
|
|
(67,749
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
$
|
8,585
|
|
|
$
|
8,528
|
|
|
$
|
17,113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The amount of total gains or losses for the period included in
earnings attributable to the change in unrealized gains or
losses relating to assets still held at the reporting date
|
|
$
|
(32,249
|
)
|
|
$
|
8,940
|
|
|
$
|
(23,309
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Since ENP does not use hedge accounting for its commodity
derivative contracts, all gains and losses on its Level 3
assets and liabilities are included in Derivative fair
value loss (gain) in the accompanying Consolidated
Statements of Operations.
All fair values have been adjusted for nonperformance risk
resulting in a reduction of the net commodity derivative asset
of approximately $0.1 million as of December 31, 2009.
For commodity derivative contracts which are in an asset
position, ENP uses the counterpartys credit default swap
rating. For commodity derivative contracts which are in a
liability position, ENP uses the average credit default swap
rating of its peer companies as ENP does not have its own credit
default swap rating.
ENPs assessment of the significance of a particular input
to the fair value measurement requires judgment and may affect
the valuation of the nonfinancial assets and liabilities and
their placement within the
111
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
fair value hierarchy levels. The following methods and
assumptions were used to estimate the fair values of ENPs
assets and liabilities that are accounted for at fair value on a
nonrecurring basis:
|
|
|
|
|
Level 3 Fair values of asset retirement
obligations are determined using discounted cash flow
methodologies based on inputs, such as plugging costs and
reserve lives, which are not readily available in public
markets. Please read Note 5. Asset Retirement
Obligations for additional discussion of ENPs asset
retirement obligations.
|
The following table sets forth ENPs assets and liabilities
that were accounted for at fair value on a nonrecurring basis as
of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|
|
Quoted Prices in
|
|
|
|
|
|
|
|
|
Liability at
|
|
Active Markets for
|
|
Significant Other
|
|
Significant
|
|
|
|
|
December 31,
|
|
Identical Assets
|
|
Observable Inputs
|
|
Unobservable Inputs
|
|
Total Gains
|
Description
|
|
2009
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
(Losses)
|
|
|
(In thousands)
|
|
Asset retirement obligations
|
|
$
|
89
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
89
|
|
|
$
|
|
|
|
|
Note 11.
|
Related
Party Transactions
|
Administrative
Services Agreement
ENP does not have any employees. The employees supporting
ENPs operations 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, facilities, goods, and
equipment necessary to perform these services which are not
otherwise provided for by ENP. 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.
Encore Operating initially received an administrative fee of
$1.75 per BOE of ENPs production for such services. From
April 1, 2008 to March 31, 2009, the administration
fee was $1.88 per BOE of ENPs production. Effective
April 1, 2009, the administrative fee increased to $2.02
per BOE of ENPs production. ENP also reimburses Encore
Operating for actual third-party expenses incurred on ENPs
behalf. Encore Operating has substantial discretion in
determining which third-party expenses to incur on ENPs
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.
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 ENP acquires 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 the board of directors of the General
Partner upon the recommendation of its conflicts
committee; and
|
|
|
|
otherwise as agreed upon by Encore Operating and the General
Partner, with the approval of the conflicts committee of the
board of directors of the General Partner.
|
ENP reimburses EAC for any state income, franchise, or similar
tax incurred by EAC resulting from the inclusion of ENP in
consolidated tax returns with EAC as required by applicable law.
The amount of any such
112
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
reimbursement is limited to the tax that ENP would have incurred
had it not been included in a combined group with EAC.
Administrative fees (including COPAS recovery) paid to Encore
Operating pursuant to the Administrative Services Agreement are
included in General and administrative expenses in
the accompanying Consolidated Statement of Operations. The
reimbursements of actual third-party expenses incurred by Encore
Operating on ENPs behalf are included in Lease
operating expense in the accompanying Consolidated
Statement of Operations. The following table shows amounts paid
by ENP to Encore Operating pursuant to the Administrative
Services Agreement for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2009
|
|
2008
|
|
2007
|
|
|
(In thousands)
|
|
Administrative fees (including COPAS recovery)
|
|
$
|
5,693
|
|
|
$
|
6,600
|
|
|
$
|
2,848
|
|
Third-party expenses
|
|
|
5,352
|
|
|
|
8,269
|
|
|
|
3,502
|
|
As of December 31, 2009 and 2008, ENP had a payable to EAC
of $2.8 million and $5.5 million, respectively, which
is reflected as Accounts payable
affiliate in the accompanying Consolidated Balance Sheets
and a receivable from EAC of $8.2 million and
$3.9 million, respectively, which is reflected as
Accounts receivable affiliate in the
accompanying Consolidated Balance Sheets.
Acquisitions
from EAC
As previously discussed, ENP acquired (1) the Permian and
Williston Basin Assets from Encore Operating in February 2008
for approximately $125.0 million in cash and the issuance
of 6,884,776 ENP common units to Encore Operating, (2) the
Arkoma Basin Assets from Encore Operating in January 2009 for
approximately $46.4 million in cash, (3) the Williston
Basin Assets from Encore Operating in June 2009 for
approximately $25.2 million in cash, and (4) the
Rockies and Permian Basin Assets from Encore Operating in August
2009 for approximately $179.6 million in cash. Prior to
acquisition by ENP, these properties were owned by EAC and were
not separate legal entities.
In addition to payroll-related expenses, EAC incurred general
and administrative expenses related to leasing office space and
other corporate overhead expenses during the period these
properties were owned by EAC. A portion of EACs
consolidated general and administrative expenses 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. A portion of EACs consolidated
indirect lease operating overhead expenses were allocated to ENP
included in the accompanying Consolidated Statements of
Operations based on its share of EACs direct lease
operating expense.
Distributions
During 2009, 2008, and 2007, ENP paid cash distributions of
approximately $43.9 million, $46.9 million, and
$0.8 million, respectively, to EAC and its subsidiaries,
including the General Partner. During 2008 and 2007, ENP paid
cash distributions of approximately $3.5 million and
$27,000, respectively, to certain executive officers of the
General Partner based on their ownership of management incentive
units.
Other
As discussed in Note 6. Long-Term Debt, during
2007, ENP had a subordinated credit agreement with EAP
Operating, which was repaid in full with a portion of the net
proceeds from the IPO.
EAC contributed $93.7 million in cash to ENP in March 2007.
These proceeds were used by ENP, along with proceeds from the
borrowings under ENPs long-term debt agreements, to
purchase the Elk Basin Assets.
113
ENCORE
ENERGY PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Additionally, EAC 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.
|
|
Note 12.
|
Subsequent
Events
|
Subsequent events were evaluated through February 24, 2010,
which is the date the financial statements were issued.
On January 25, 2010, ENP announced that the board of
directors of the General Partner declared an ENP cash
distribution for the fourth quarter of 2009 to unitholders of
record as of the close of business on February 8, 2010 at a
rate of $0.5375 per unit. Approximately $24.6 million was
paid to unitholders on February 12, 2010.
114
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:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Properties and equipment, at cost successful efforts
method:
|
|
|
|
|
|
|
|
|
Proved properties, including wells and related equipment
|
|
$
|
851,833
|
|
|
$
|
814,903
|
|
Unproved properties
|
|
|
55
|
|
|
|
84
|
|
Accumulated depletion, depreciation, and amortization
|
|
|
(210,417
|
)
|
|
|
(154,584
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
641,471
|
|
|
$
|
660,403
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes costs incurred related to oil and
natural gas properties for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties(a)
|
|
$
|
32,265
|
|
|
$
|
5,940
|
|
|
$
|
498,057
|
|
Unproved properties
|
|
|
1
|
|
|
|
|
|
|
|
105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total acquisitions
|
|
|
32,266
|
|
|
|
5,940
|
|
|
|
498,162
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development:
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and exploitation(b)
|
|
|
7,197
|
|
|
|
31,450
|
|
|
|
21,277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total development
|
|
|
7,197
|
|
|
|
31,450
|
|
|
|
21,277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration:
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and exploitation
|
|
|
1,088
|
|
|
|
8,104
|
|
|
|
9,899
|
|
Other
|
|
|
135
|
|
|
|
119
|
|
|
|
101
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total exploration
|
|
|
1,223
|
|
|
|
8,223
|
|
|
|
10,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
40,686
|
|
|
$
|
45,613
|
|
|
$
|
529,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes asset retirement obligations incurred for acquisition
activities of $66 thousand and $6.5 million in 2009 and
2007, respectively. |
|
(b) |
|
Includes asset retirement obligations incurred for development
activities of $23 thousand, $29 thousand, and $0.1 million
during 2009, 2008, and 2007, respectively. |
Oil &
Natural Gas Producing Activities
Unaudited
The estimates of ENPs proved oil and natural gas reserves,
which are located entirely within the United States, were
prepared in accordance with guidelines established by the SEC.
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
115
ENCORE
ENERGY PARTNERS LP
SUPPLEMENTARY
INFORMATION (Continued)
with SEC guidelines, 2009 estimates of future net cash flows
from ENPs properties and the representative value thereof
are made using an unweighted average of the closing oil and
natural gas prices for the applicable commodity on the first day
of each month in 2009 and are held constant throughout the life
of the properties. In accordance with past SEC guidelines, 2008
and 2007 estimates of future net cash flows from ENPs
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 constant throughout the life of the
properties. Prices used in estimating ENPs future net cash
flows were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
2008
|
|
2007
|
|
Oil (per Bbl)
|
|
$
|
61.18
|
|
|
$
|
44.60
|
|
|
$
|
96.01
|
|
Natural gas (per Mcf)
|
|
$
|
3.83
|
|
|
$
|
5.62
|
|
|
$
|
7.47
|
|
Net future cash inflows have not been adjusted for commodity
derivative contracts outstanding at the end of the year. Future
cash inflows 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, by estimated
abandonment costs, net of salvage, 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 ENPs standardized measure
as each partner is separately taxed on his share of ENPs
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 managements analysis of
impairments of oil and natural gas properties and the
calculation of DD&A on these properties.
ENPs estimated net quantities of proved oil and natural
gas reserves were as follows as of the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
26,341
|
|
|
|
24,769
|
|
|
|
30,851
|
|
Natural gas (MMcf)
|
|
|
78,379
|
|
|
|
70,462
|
|
|
|
72,955
|
|
Combined (MBOE)
|
|
|
39,404
|
|
|
|
36,513
|
|
|
|
43,010
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
2,589
|
|
|
|
2,509
|
|
|
|
4,377
|
|
Natural gas (MMcf)
|
|
|
6,320
|
|
|
|
7,549
|
|
|
|
10,283
|
|
Combined (MBOE)
|
|
|
3,643
|
|
|
|
3,767
|
|
|
|
6,091
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
28,930
|
|
|
|
27,278
|
|
|
|
35,228
|
|
Natural gas (MMcf)
|
|
|
84,699
|
|
|
|
78,011
|
|
|
|
83,238
|
|
Combined (MBOE)
|
|
|
43,047
|
|
|
|
40,280
|
|
|
|
49,101
|
|
116
ENCORE
ENERGY PARTNERS LP
SUPPLEMENTARY
INFORMATION (Continued)
The changes in ENPs proved reserves were as follows for
the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Oil
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Equivalent
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBOE)
|
|
|
Balance, December 31, 2006(a)
|
|
|
9,073
|
|
|
|
76,824
|
|
|
|
21,877
|
|
Purchases of
minerals-in-place
|
|
|
25,965
|
|
|
|
6,221
|
|
|
|
27,002
|
|
Extensions and discoveries
|
|
|
488
|
|
|
|
7,414
|
|
|
|
1,724
|
|
Revisions of previous estimates
|
|
|
1,934
|
|
|
|
(1,470
|
)
|
|
|
1,688
|
|
Production
|
|
|
(2,232
|
)
|
|
|
(5,751
|
)
|
|
|
(3,190
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007(a)
|
|
|
35,228
|
|
|
|
83,238
|
|
|
|
49,101
|
|
Purchases of
minerals-in-place
|
|
|
32
|
|
|
|
2,489
|
|
|
|
447
|
|
Extensions and discoveries
|
|
|
148
|
|
|
|
2,832
|
|
|
|
620
|
|
Revisions of previous estimates
|
|
|
(5,596
|
)
|
|
|
(4,329
|
)
|
|
|
(6,318
|
)
|
Production
|
|
|
(2,534
|
)
|
|
|
(6,219
|
)
|
|
|
(3,570
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008(a)
|
|
|
27,278
|
|
|
|
78,011
|
|
|
|
40,280
|
|
Purchases of
minerals-in-place
|
|
|
|
|
|
|
18,837
|
|
|
|
3,140
|
|
Extensions and discoveries
|
|
|
2
|
|
|
|
1,112
|
|
|
|
187
|
|
Revisions of previous estimates
|
|
|
3,987
|
|
|
|
(7,164
|
)
|
|
|
2,793
|
|
Production
|
|
|
(2,337
|
)
|
|
|
(6,097
|
)
|
|
|
(3,353
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
28,930
|
|
|
|
84,699
|
|
|
|
43,047
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes 1,585 MBOE, 1,510 MBOE, and 1,952 MBOE
of proved reserves as of December 31, 2008, 2007, and 2006,
respectively, associated with the Arkoma Basin Assets ENP
acquired from Encore Operating in January 2009. Also includes
1,899 MBOE, 2,330 MBOE, and 444 MBOE of proved
reserves as of December 31, 2008, 2007, and 2006,
respectively, associated with the Williston Basin Assets ENP
acquired from Encore Operating in June 2009. Also includes
10,732 MBOE, 13,663 MBOE, and 6,321 MBOE of
proved reserves as of December 31, 2008, 2007, and 2006,
respectively, associated with the Rockies and Permian Basin
Assets ENP acquired from Encore Operating in August 2009. The
acquisitions of these assets were accounted for as transactions
between entities under common control, similar to a pooling of
interests, whereby ENPs historical financial information
and proved reserve volumes were recast to include the acquired
properties for all periods the properties were owned by Encore
Operating. |
Recent SEC Rule-Making Activity. In December
2008, the SEC announced that it had approved revisions designed
to modernize the oil and gas company reserves reporting
requirements. Application of the new reserve rules resulted in
the use of lower prices at December 31, 2009 for both oil
and natural gas than would have resulted under the previous
rules. Use of new
12-month
average pricing rules at December 31, 2009 resulted in a
decrease in proved reserves of approximately 2.2 MMBOE.
Pursuant to the SECs final rule, prior period reserves
were not restated.
117
ENCORE
ENERGY PARTNERS LP
SUPPLEMENTARY
INFORMATION (Continued)
ENPs standardized measure of discounted estimated future
net cash flows was as follows as of the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Future cash inflows
|
|
$
|
1,879,504
|
|
|
$
|
1,406,100
|
|
|
$
|
3,392,199
|
|
Future production costs
|
|
|
(819,352
|
)
|
|
|
(706,589
|
)
|
|
|
(1,157,893
|
)
|
Future development costs
|
|
|
(46,852
|
)
|
|
|
(50,540
|
)
|
|
|
(61,961
|
)
|
Future abandonment costs, net of salvage
|
|
|
(29,339
|
)
|
|
|
(28,771
|
)
|
|
|
(27,750
|
)
|
Future income tax expense
|
|
|
(1,217
|
)
|
|
|
(182
|
)
|
|
|
(7,344
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
982,744
|
|
|
|
620,018
|
|
|
|
2,137,251
|
|
10% annual discount
|
|
|
(488,243
|
)
|
|
|
(293,396
|
)
|
|
|
(1,073,527
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted estimated future net cash
flows
|
|
$
|
494,501
|
|
|
$
|
326,622
|
|
|
$
|
1,063,724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The changes in ENPs standardized measure of discounted
estimated future net cash flows were as follows for the periods
indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Net change in prices and production costs
|
|
$
|
153,083
|
|
|
$
|
(660,592
|
)
|
|
$
|
145,074
|
|
Purchases of
minerals-in-place
|
|
|
19,136
|
|
|
|
5,856
|
|
|
|
719,376
|
|
Extensions, discoveries, and improved recovery
|
|
|
1,588
|
|
|
|
5,938
|
|
|
|
28,692
|
|
Revisions of previous quantity estimates
|
|
|
65,300
|
|
|
|
(60,036
|
)
|
|
|
46,995
|
|
Production, net of production costs
|
|
|
(95,270
|
)
|
|
|
(76,970
|
)
|
|
|
(161,737
|
)
|
Previously estimated development costs incurred during the period
|
|
|
4,732
|
|
|
|
13,685
|
|
|
|
17,542
|
|
Accretion of discount
|
|
|
32,662
|
|
|
|
106,373
|
|
|
|
25,527
|
|
Change in estimated future development costs
|
|
|
(3,527
|
)
|
|
|
(6,372
|
)
|
|
|
(39,806
|
)
|
Net change in income taxes
|
|
|
(457
|
)
|
|
|
3,345
|
|
|
|
(2,427
|
)
|
Change in timing and other
|
|
|
(9,368
|
)
|
|
|
(68,329
|
)
|
|
|
29,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in standardized measure
|
|
|
167,879
|
|
|
|
(737,102
|
)
|
|
|
808,461
|
|
Standardized measure, beginning of year
|
|
|
326,622
|
|
|
|
1,063,724
|
|
|
|
255,263
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure, end of year
|
|
$
|
494,501
|
|
|
$
|
326,622
|
|
|
$
|
1,063,724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
118
ENCORE
ENERGY PARTNERS LP
SUPPLEMENTARY
INFORMATION (Continued)
Selected
Quarterly Financial Data Unaudited
The following table provides selected quarterly financial data
for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
(In thousands, except per unit data)
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, as reported
|
|
$
|
18,651
|
|
|
$
|
27,246
|
|
|
$
|
41,032
|
|
|
$
|
46,560
|
|
Plus: revenues from assets acquired from affiliate
|
|
|
7,648
|
|
|
|
9,380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, as recast
|
|
$
|
26,299
|
|
|
$
|
36,626
|
|
|
$
|
41,032
|
|
|
$
|
46,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss), as reported
|
|
$
|
6,780
|
|
|
$
|
(35,043
|
)
|
|
$
|
10,383
|
|
|
$
|
(10,059
|
)
|
Plus: operating income (loss) from assets acquired from affiliate
|
|
|
(2,492
|
)
|
|
|
1,044
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss), as recast
|
|
$
|
4,288
|
|
|
$
|
(33,999
|
)
|
|
$
|
10,383
|
|
|
$
|
(10,059
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss), as reported
|
|
$
|
4,568
|
|
|
$
|
(37,593
|
)
|
|
$
|
7,460
|
|
|
$
|
(13,316
|
)
|
Plus: net income (loss) from assets acquired from affiliate
|
|
|
(2,492
|
)
|
|
|
1,044
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss), as recast
|
|
$
|
2,076
|
|
|
$
|
(36,549
|
)
|
|
$
|
7,460
|
|
|
$
|
(13,316
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income (loss)
|
|
$
|
4,499
|
|
|
$
|
(37,093
|
)
|
|
$
|
5,904
|
|
|
$
|
(13,169
|
)
|
General partners interest in net income (loss)
|
|
$
|
69
|
|
|
$
|
(630
|
)
|
|
$
|
63
|
|
|
$
|
(147
|
)
|
Net income (loss) per common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.14
|
|
|
$
|
(1.08
|
)
|
|
$
|
0.13
|
|
|
$
|
(0.29
|
)
|
Diluted
|
|
$
|
0.14
|
|
|
$
|
(1.08
|
)
|
|
$
|
0.13
|
|
|
$
|
(0.29
|
)
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, as reported
|
|
$
|
49,245
|
|
|
$
|
67,160
|
|
|
$
|
84,110
|
|
|
$
|
26,383
|
|
Plus: revenues from assets acquired from affiliate
|
|
|
23,377
|
|
|
|
24,312
|
|
|
|
|
|
|
|
11,294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, as recast
|
|
$
|
72,622
|
|
|
$
|
91,472
|
|
|
$
|
84,110
|
|
|
$
|
37,677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss), as reported
|
|
$
|
7,291
|
|
|
$
|
(38,817
|
)
|
|
$
|
113,981
|
|
|
$
|
120,278
|
|
Plus: operating income from assets acquired from affiliate
|
|
|
11,464
|
|
|
|
13,810
|
|
|
|
|
|
|
|
381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
18,755
|
|
|
$
|
(25,007
|
)
|
|
$
|
113,981
|
|
|
$
|
120,659
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss), as reported
|
|
$
|
5,585
|
|
|
$
|
(40,526
|
)
|
|
$
|
111,892
|
|
|
$
|
118,150
|
|
Plus: operating income from assets acquired from affiliate
|
|
|
11,550
|
|
|
|
13,810
|
|
|
|
|
|
|
|
295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
17,135
|
|
|
$
|
(26,716
|
)
|
|
$
|
111,892
|
|
|
$
|
118,445
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income (loss)
|
|
$
|
(247
|
)
|
|
$
|
(45,441
|
)
|
|
$
|
89,716
|
|
|
$
|
115,332
|
|
General partners interest in net income (loss)
|
|
$
|
(36
|
)
|
|
$
|
(735
|
)
|
|
$
|
1,444
|
|
|
$
|
1,843
|
|
Net income (loss) per common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.01
|
)
|
|
$
|
(1.45
|
)
|
|
$
|
2.86
|
|
|
$
|
3.68
|
|
Diluted
|
|
$
|
(0.01
|
)
|
|
$
|
(1.45
|
)
|
|
$
|
2.86
|
|
|
$
|
3.49
|
|
In June 2009, ENP acquired the Williston Basin Assets from
Encore Operating. In August 2009, ENP acquired the Rockies and
Permian Basin Assets from Encore Operating. Because these assets
were acquired from an affiliate, the acquisitions were accounted
for as transactions between entities under common control,
similar to a pooling of interests, whereby the assets and
liabilities of the acquired properties were recorded at Encore
Operatings carrying value and ENPs historical
financial information was recast to include the acquired
properties for all periods in which the properties were owned by
Encore Operating. Accordingly, the above selected quarterly
financial data reflects the historical results of ENP combined
with those of the Williston Basin Assets and the Rockies and
Permian Basin Assets.
119
ENCORE
ENERGY PARTNERS LP
SUPPLEMENTARY
INFORMATION (Continued)
As discussed in Note 2. Summary of Significant
Accounting Policies and Note 8. Earnings Per
Unit, ENP adopted
ASC 260-10
on January 1, 2009 and all periods have been restated to
calculate earnings per unit in accordance therewith.
120
ENCORE
ENERGY PARTNERS LP
|
|
ITEM 9.
|
CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
|
None.
|
|
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 general partners management,
including the Chief Executive Officer and Chief Financial
Officer of our general partner, of the effectiveness of the
design and operation of our disclosure controls and procedures.
Based on that evaluation, the Chief Executive Officer and Chief
Financial Officer of our general partner concluded that our
disclosure controls and procedures were effective as of
December 31, 2009 to ensure that information required to be
disclosed in the reports we file or submit under the Exchange
Act is recorded, processed, summarized, and reported within the
time periods specified in the SECs 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.
Managements
Report on Internal Control Over Financial Reporting
Our general partners management is responsible for
establishing and maintaining adequate internal control over
financial reporting. Our internal control over financial
reporting is a process designed under the supervision of our
general partners Chief Executive Officer and Chief
Financial Officer to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of our
financial statements for external purposes in accordance with
GAAP.
As of December 31, 2009, our general partners
management assessed the effectiveness of our 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, our general
partners management determined that we maintained
effective internal control over financial reporting as of
December 31, 2009, based on those criteria.
Ernst & Young LLP, the independent registered public
accounting firm that audited our consolidated financial
statements included in this Report, has issued an attestation
report on the effectiveness of our internal control over
financial reporting as of December 31, 2009. The report,
which expresses an unqualified opinion on the effectiveness of
our internal control over financial reporting as of
December 31, 2009, is included below.
121
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 LPs (the
Partnership) internal control over financial
reporting as of December 31, 2009, 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
LPs 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
Managements Report on Internal Control Over Financial
Reporting. Our responsibility is to express an opinion on the
Partnerships 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 companys 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 companys
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
companys 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, 2009, 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, 2009 and 2008, and the related consolidated
statements of operations, partners equity and
comprehensive income (loss), and cash flows for each of the
three years in the period ended December 31, 2009 and our
report dated February 24, 2010 expressed an unqualified
opinion thereon.
/s/ Ernst & Young LLP
Fort Worth,
Texas
February 24, 2010
122
ENCORE
ENERGY PARTNERS LP
Changes
in Internal Control over Financial Reporting
There were no changes in our internal control over financial
reporting during the fourth quarter of 2009 that materially
affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
|
|
ITEM 9B.
|
OTHER
INFORMATION
|
None.
PART III
|
|
ITEM 10.
|
DIRECTORS,
EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
Our general partner 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.
Our general partner has a board of directors that oversees its
management, operations, and activities. 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.
123
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.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
|
Position with Encore Energy Partners GP LLC
|
|
I. Jon Brumley
|
|
|
70
|
|
|
Chairman of the Board
|
Jon S. Brumley
|
|
|
39
|
|
|
Chief Executive Officer, President, and Director
|
Robert C. Reeves
|
|
|
40
|
|
|
Senior Vice President, Chief Financial Officer, Treasurer, and
Corporate Secretary
|
L. Ben Nivens
|
|
|
49
|
|
|
Senior Vice President and Chief Operating Officer
|
John W. Arms
|
|
|
42
|
|
|
Senior Vice President, Acquisitions
|
Kevin Treadway
|
|
|
44
|
|
|
Senior Vice President, Land
|
Andrea Hunter
|
|
|
35
|
|
|
Vice President, Controller, and Principal Accounting Officer
|
Thomas H. Olle
|
|
|
55
|
|
|
Vice President, Strategic Solutions
|
Andy R. Lowe
|
|
|
58
|
|
|
Vice President, Marketing
|
Arnold L. Chavkin
|
|
|
58
|
|
|
Director
|
John E. Jackson
|
|
|
51
|
|
|
Director
|
J. Luther King, Jr.
|
|
|
69
|
|
|
Director
|
Clayton E. Melton
|
|
|
66
|
|
|
Director
|
George W. Passela
|
|
|
64
|
|
|
Director
|
Executive
Officers
I. Jon Brumley has been Chairman of the Board of our
general partner since February 2007. Mr. Brumley has been
Chairman of the Board of EAC 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
MESAs 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 EACs 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.
124
ENCORE
ENERGY PARTNERS LP
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 the Senior Vice President, Chief
Financial Officer, and Treasurer of EAC since November 2006 and
Corporate Secretary of EAC since May 2008. From November 2006
until January 2007, Mr. Reeves also served as 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 EACs 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 EACs 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 and
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. Mr. Treadway served as the Vice
President Land of our general partner from February
2007 to February 2008. Mr. Treadway served as the Vice
President Land of EAC from April 2003 to February
2008. From May 2000 to April 2003, Mr. Treadway held
various positions of increasing responsibility in EACs
land department. Prior to joining EAC in May 2000,
Mr. Treadway served as a landman at Coho Resources.
Mr. Treadway received a Bachelor of Science in Petroleum
Land Management from the University of Southwestern Louisiana.
Andrea Hunter has been the Vice President, Controller,
and Principal Accounting Officer of our general partner and EAC
since February 2008. From September 2007 to February 2008,
Ms. Hunter 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 Publishings 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 been the 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 EACs Senior Vice
125
ENCORE
ENERGY PARTNERS LP
President, Asset Management. Mr. Olle served as EACs
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.
Andy R. Lowe has been the Vice President, Marketing of
our general partner since February 2008. Mr. Lowe has been
the Vice President, Marketing of EAC since February 2007. From
May 2006 until February 2007, Mr. Lowe was EACs
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.
Directors
I. Jon Brumley. Please refer to
page 123.
Jon S. Brumley. Please refer to page 123.
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 of our general partner.
Mr. Chavkin is also a member of the conflicts committee of
the board of directors of our general partner. 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 Banks 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 EAC 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 served as
Chairman, Chief Executive Officer, and President of Price
Gregory Services, Inc. (a pipeline-related infrastructure
service provider in North America) from February 2008 until its
sale on October 1, 2009. Mr. Jackson has served as a
director of Exterran Holding, Inc. (formerly Hanover Compressor
Company) since July 2004 and served as Hanovers 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 the
Vice President/General Manager of Gemaire, Texas a subsidiary of
Gemaire Distributors L.L.C., a
126
ENCORE
ENERGY PARTNERS LP
distributor of heating and air conditioning equipment located in
Deerfield Beach, Florida, since October 1, 2009. From
January 2003 to October 2009, he served as President of Atlantic
Service & Supply LLC, a distributor of heating and air
conditioning supplies. 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
34 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 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
Bostons 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.
The board of directors of our general partner has adopted
categorical standards to assist it in making independence
determinations. However, the board of directors of our general
partner considers all material relationships with each director
in making its independence determinations. A relationship falls
within the categorical standards if it:
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Is a type of relationship addressed in Item 404 of
Regulation S-K
under the Exchange Act or Section 303A.02(b) of the NYSE
Listed Company Manual, but those rules neither require
disclosure nor preclude a determination of independence; or
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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 percent of the organizations
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.
127
ENCORE
ENERGY PARTNERS LP
Board
Committees
As of February 17, 2010, the board of directors of our
general partner had an audit committee and a conflicts
committee. The following table sets forth the membership on each
committee:
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Name
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Audit
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Conflicts
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Arnold L. Chavkin
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Chair
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Member
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John E. Jackson
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J. Luther King, Jr.
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Member
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Member
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Clayton E. Melton
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Member
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Member
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George W. Passela
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Member
|
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Chair
|
In 2009, the Audit Committee held 5 meetings, the Conflicts
Committee held 4 meetings, and the board of directors of our
general partner held 9 meetings. Each director attended at least
75 percent of all board and applicable committee meetings
in 2009.
Audit Committee. The Audit Committees
purpose is, among other things, to assist the board of directors
of our general partner in overseeing:
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the integrity of our financial statements;
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our compliance with legal and regulatory requirements;
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the independence, qualifications, and performance of our
independent registered public accounting firm; and
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the performance of our internal audit function.
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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 defined in Item 407(d)(5) of
Regulation S-K.
The charter of the Audit Committee is available free of charge
on the Corporate Governance section of our website
at www.encoreenp.com.
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.
The board of directors of our general partner has determined
that all members of the Conflicts Committee are independent
under the listing standards of the NYSE.
Code of
Business Conduct and Ethics and Governance Guidelines
We have adopted a Code of Business Conduct and Ethics for our
general partners directors, officers (including our
general partners principal executive officer, principal
financial officer, and principal accounting officer), and
employees. We have also adopted Governance Guidelines, which, in
conjunction with our certificate of limited partnership, bylaws,
and committee charters of the board of directors of our general
partner, form the framework for our governance. We will post on
our website any amendments to the Code of
128
ENCORE
ENERGY PARTNERS LP
Business Conduct and Ethics or waivers of the Code of Business
Conduct and Ethics for directors and executive officers of our
general partner.
Our Code of Business Conduct and Ethics and the Governance
Guidelines are available free of charge on the Corporate
Governance section of our website at
www.encoreenp.com.
Executive
Sessions of Non-Management Directors
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 non-management
directors meet in executive session without management
participation at least three times per year. The purpose of
these executive sessions is to promote open and candid
discussion among the non-management directors. These meetings
are chaired by the chairman of the Audit Committee.
Unitholder
Communications
Individuals may communicate with the entire board of directors
of our general partner or with our general partners
non-management directors. Any such communication should be sent
via letter addressed to the member or members of the board of
directors of our general partner to whom the communication is
directed. All such communications, other than unsolicited
commercial solicitations or communications, will be forwarded to
the appropriate director or directors for review.
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 2009, the directors and
executive officers of our general partner and our
10 percent unitholders complied with all Section 16(a)
filing requirements. 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.
|
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ITEM 11.
|
EXECUTIVE
COMPENSATION
|
Compensation
Discussion and Analysis
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 serve in
the same capacities for EAC. The compensation of EACs
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 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.
129
ENCORE
ENERGY PARTNERS LP
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
Summary
Compensation Table
The following table summarizes the total compensation awarded
to, earned by, or paid to our general partners named
executive officers for the periods indicated:
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|
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|
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|
|
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|
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Change in Pension
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|
|
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|
|
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Value and
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|
|
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Nonqualified
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Stock
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Non-Equity
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Deferred
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Cash
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Awards
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Option
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Incentive Plan
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Compensation
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All Other
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Name and Title
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Year
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Salary
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Bonus
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(a)
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Awards
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Compensation
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Earnings
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Compensation
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Total
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I. Jon Brumley
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|
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2009
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$
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|
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$
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|
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|
$
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|
|
$
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|
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$
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$
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$
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$
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Chairman of the Board
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2008
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|
|
|
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|
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1,236,785
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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1,236,785
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|
|
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|
2007
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|
|
|
|
|
|
|
|
|
|
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1,769,074
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|
|
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|
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|
|
|
|
|
|
|
|
|
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1,769,074
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Jon S. Brumley
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2009
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|
|
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|
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|
|
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Chief Executive Officer
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|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
1,236,785
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,236,785
|
|
and President
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|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
1,769,074
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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1,769,074
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Robert C. Reeves
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2009
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|
|
|
|
|
|
|
|
|
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Senior Vice President,
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2008
|
|
|
|
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951,373
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|
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|
|
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|
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|
|
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951,373
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Chief Financial Officer,
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2007
|
|
|
|
|
|
|
|
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1,360,825
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
1,360,825
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Treasurer, and Corporate Secretary
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|
|
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L. Ben Nivens
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|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
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|
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Senior Vice President
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2008
|
|
|
|
|
|
|
|
|
|
|
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665,961
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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665,961
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and Chief Operating
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|
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2007
|
|
|
|
|
|
|
|
|
|
|
|
952,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
952,578
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|
Officer
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
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|
|
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|
|
|
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|
|
|
|
|
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|
|
|
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|
John W. Arms
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|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
|
|
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|
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|
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Senior Vice President,
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|
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2008
|
|
|
|
|
|
|
|
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665,961
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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665,961
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Acquisitions
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
952,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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952,578
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|
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(a) |
|
Reflects the compensation cost recognized by us with respect to
grants of management incentive units, which does not correspond
to the actual value that may be realized by the named executive
officers. Pursuant to SEC rules, the amounts shown exclude the
impact of estimated forfeitures related to service-based vesting
conditions. |
Grants of
Plan-Based Awards for 2009
Our general partners named executive officers did not
receive any grants of plan based awards with respect
to performance in 2009.
Outstanding
Equity Awards at December 31, 2009
At December 31, 2009, 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 in the fourth quarter of 2008.
130
ENCORE
ENERGY PARTNERS LP
Units
Vested
There were no vestings of plan-based awards for our general
partners named executive officers during 2009.
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, 2009.
Compensation
Committee Interlocks and Insider Participation
As previously discussed, our general partners board of
directors is not required to maintain, and does not maintain, a
compensation committee. I. Jon Brumley, our general
partners chairman of the board of directors, serves as the
chairman of the board of directors of EAC, and Jon S. Brumley,
our general partners Chief Executive Officer and President
and member of our general partners 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 Item 13. Certain Relationships and Related
Transactions, and Director Independence for information
about relationships among us, our general partner, and EAC.
Director
Compensation
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 2009:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Value and
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonqualified
|
|
|
|
|
|
|
Fees Earned
|
|
|
|
Non-Equity
|
|
Deferred
|
|
|
|
|
|
|
or Paid in
|
|
Unit
|
|
Incentive Plan
|
|
Compensation
|
|
All Other
|
|
|
Name
|
|
Cash(a)
|
|
Awards(b)
|
|
Compensation
|
|
Earnings
|
|
Compensation
|
|
Total(c)
|
|
Arnold L. Chavkin
|
|
$
|
130,000
|
|
|
$
|
90,650
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
220,650
|
|
John E. Jackson
|
|
|
68,000
|
|
|
|
90,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
158,650
|
|
J. Luther King, Jr.
|
|
|
123,000
|
|
|
|
90,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
213,650
|
|
Clayton E. Melton
|
|
|
121,000
|
|
|
|
90,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
211,650
|
|
George W. Passela
|
|
|
133,000
|
|
|
|
90,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
223,650
|
|
|
|
|
(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. Each
member of the conflicts committee receives a fee of $25,000 each |
131
ENCORE
ENERGY PARTNERS LP
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|
time we seek 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.
Amount is determined by multiplying the number of phantom units
granted by $18.13, the closing price of our common units on the
NYSE on October 26, 2009, which was the date of grant.
Phantom units vest in four equal annual installments, subject to
immediate vesting in the event of a change in control or
termination of employment due to 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) |
|
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 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 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
132
ENCORE
ENERGY PARTNERS LP
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 EACs 2000
Incentive Stock Plan, unless provided otherwise by the plan
administrator. The consequences of the termination of a
grantees 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;
|
|
|
|
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 EACs 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 EACs 2000
Incentive Stock Plan more than 20 percent of EACs
outstanding capital stock;
|
|
|
|
EACs incumbent board members, as of the effective date of
EACs 2000 Incentive Stock Plan, cease to constitute at
least a majority of EACs board of directors, provided
that, any subsequent director whose election or nomination was
approved by a majority vote of the directors then comprising
EACs incumbent board members will generally be considered
an EAC incumbent board member;
|
133
ENCORE
ENERGY PARTNERS LP
|
|
|
|
|
approval by EACs stockholders of a reorganization, merger,
share exchange, or consolidation, unless, in each case following
the transaction, (1) all or substantially all of EACs
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 EACs board of
directors, providing for such transaction; or
|
|
|
|
approval by EACs stockholders of a complete liquidation or
dissolution of EAC or sale or other disposition of all or
substantially all of EACs 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 EACs incumbent board
members at the time of the execution of the initial agreement,
or of the action of EACs board of directors, providing for
such sale or other disposition or were elected, appointed, or
nominated by EACs 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.
|
|
ITEM 12.
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED UNITHOLDER MATTERS
|
The following table sets forth the beneficial ownership of our
common units as of February 17, 2010 by:
|
|
|
|
|
each person known by us to beneficially own 5 percent or
more of our outstanding common 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.
|
134
ENCORE
ENERGY PARTNERS LP
Unless otherwise noted, the persons named below have sole voting
and investment power with respect to such units.
|
|
|
|
|
|
|
|
|
|
|
Common Units
|
|
|
Name and Address of Beneficial Owner
|
|
Beneficially Owned
|
|
Percent of Class
|
|
5% Beneficial Owners
|
|
|
|
|
|
|
|
|
Encore Acquisition Company(a)
|
|
|
20,924,055
|
|
|
|
46.1
|
%
|
777 Main Street, Suite 1400
Fort Worth, TX 76040
|
|
|
|
|
|
|
|
|
Encore Partners LP Holdings LLC(a)
|
|
|
9,995,801
|
|
|
|
22.0
|
%
|
777 Main Street, Suite 1400
Fort Worth, TX 76040
|
|
|
|
|
|
|
|
|
Encore Operating, L.P.(a)
|
|
|
10,928,254
|
|
|
|
24.1
|
%
|
777 Main Street, Suite 1400
Fort Worth, TX 76040
|
|
|
|
|
|
|
|
|
Directors and Named Executive Officers(b)
|
|
|
|
|
|
|
|
|
I. Jon Brumley(c)
|
|
|
616,711
|
|
|
|
1.4
|
%
|
Jon S. Brumley
|
|
|
456,415
|
|
|
|
1.0
|
%
|
Robert C. Reeves(d)
|
|
|
347,588
|
|
|
|
*
|
|
L. Ben Nivens
|
|
|
242,862
|
|
|
|
*
|
|
John W. Arms
|
|
|
265,062
|
|
|
|
*
|
|
Arnold L. Chavkin
|
|
|
20,500
|
|
|
|
*
|
|
John E. Jackson
|
|
|
15,000
|
|
|
|
*
|
|
J. Luther King, Jr.(e)
|
|
|
133,750
|
|
|
|
*
|
|
Clayton E. Melton
|
|
|
18,400
|
|
|
|
*
|
|
George W. Passela
|
|
|
25,000
|
|
|
|
*
|
|
All directors and executive officers as a group (14 persons)
|
|
|
2,145,288
|
|
|
|
4.7
|
%
|
|
|
|
* |
|
Less than 1%. |
|
(a) |
|
EAC is the ultimate parent company of Encore Energy Partners LP
Holdings LLC and Encore Operating and therefore, may be deemed
to beneficially own the ENP common units held by Encore Partners
LP Holdings LLC and Encore Operating. |
|
(b) |
|
Includes unvested phantom units as of February 17, 2010 as
follows: Mr. Chavkin (11,250), Mr. Jackson (11,250),
Mr. King (11,250), Mr. Melton (11,250), and
Mr. Passela (11,250), and all directors and executive
officers as a group (56,250). |
|
(c) |
|
Mr. Brumley is the sole officer, director, and shareholder
of a corporation that is the sole general partner of a limited
partnership that owns 596,317 common units. Accordingly,
Mr. Brumley has sole voting and dispositive power with
respect to the common units owned by the partnership. In
addition, 573,156 of the common units identified above are
pledged as security with respect to outstanding indebtedness of
Mr. Brumley. |
|
(d) |
|
Includes 346,541 common units which are pledged as security with
respect to outstanding indebtedness of Mr. Reeves. |
|
(e) |
|
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. |
135
ENCORE
ENERGY PARTNERS LP
The following table sets forth, as of February 17, 2010,
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.
|
|
|
|
|
|
|
|
|
|
|
Shares Beneficially
|
|
|
Name of Beneficial Owner(a)(b)
|
|
Owned
|
|
Percent of Class
|
|
I. Jon Brumley(c)
|
|
|
2,615,105
|
|
|
|
4.6
|
%
|
Jon S. Brumley
|
|
|
1,087,115
|
|
|
|
1.9
|
%
|
Robert C. Reeves
|
|
|
221,512
|
|
|
|
*
|
|
John W. Arms
|
|
|
152,442
|
|
|
|
*
|
|
L. Ben Nivens
|
|
|
122,528
|
|
|
|
*
|
|
Arnold L. Chavkin
|
|
|
|
|
|
|
*
|
|
John E. Jackson
|
|
|
400
|
|
|
|
*
|
|
J. Luther King, Jr.(d)
|
|
|
284,385
|
|
|
|
*
|
|
Clayton E. Melton
|
|
|
|
|
|
|
*
|
|
George W. Passela
|
|
|
|
|
|
|
*
|
|
All executive officers and directors as a group (14 persons)
|
|
|
4,831,989
|
|
|
|
8.5
|
%
|
|
|
|
* |
|
Less than 1%. |
|
(a) |
|
Includes options that are or become exercisable within
60 days of February 17, 2010 as follows:
Mr. I. Jon Brumley (337,638), Mr. Jon S.
Brumley (374,506), Mr. Reeves (105,182), Mr. Nivens
(28,685), and Mr. Arms (64,034), and all executive officers
and directors as a group (1,101,748) upon the exercise of stock
options granted pursuant to EACs incentive stock plans. |
|
(b) |
|
Includes unvested restricted stock as of February 17, 2010
as follows: Mr. I. Jon Brumley (81,552), Mr. Jon S.
Brumley (143,227), Mr. Reeves (62,375), Mr. Nivens
(66,715), and Mr. Arms (43,545), and all directors and
executive officers as a group (486,000). |
|
(c) |
|
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. |
|
(d) |
|
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 the LTIP as of December 31,
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
(b)
|
|
(c)
|
|
|
|
|
|
|
Number of
|
|
|
Number of
|
|
|
|
Securities Remaining
|
|
|
Securities to
|
|
|
|
Available for
|
|
|
be Issued
|
|
Weighted-Average Exercise
|
|
Future Issuance
|
|
|
Upon Exercise
|
|
Price of
|
|
Under Equity Compensation
|
|
|
of Outstanding
|
|
Outstanding Options,
|
|
Plans (Excluding
|
|
|
Options, Warrants
|
|
Warrants and
|
|
Securities
|
|
|
and Rights(a)
|
|
Rights
|
|
Reflected in Column (a))
|
|
Equity compensation plans approved by unitholders
|
|
|
|
|
|
|
|
|
|
|
1,075,000
|
|
Equity compensation plans not approved by unitholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
1,075,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
There are no outstanding warrants or equity rights awarded under
the LTIP. Excludes 56,250 shares of unvested phantom units. |
136
ENCORE
ENERGY PARTNERS LP
For discussion of our unit-based compensation plans, please read
Item 11. Executive Compensation.
|
|
ITEM 13.
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
|
As of February 17, 2010, affiliates of our general partner,
including directors and executive officers of our general
partner, owned 22,950,393 common units representing
approximately 50.7 of our outstanding common units. In addition,
our general partner owned all 504,851 general partner units
representing a 1.1 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 $2.02 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. |
137
ENCORE
ENERGY PARTNERS LP
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, facilities, goods, and
equipment necessary to perform these services which are not
otherwise provided for by us. 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.
Encore Operating initially received an administrative fee of
$1.75 per BOE of our production for such services. From
April 1, 2008 to March 31, 2009, the administrative
fee was $1.88 per BOE of our production. Effective April 1,
2009, the administrative fee increased to $2.02 per BOE of our
production. We also reimburse Encore Operating for 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.
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 acquire 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 the board of directors of our
general partner upon the recommendation of its conflicts
committee; or
|
|
|
|
otherwise as agreed upon by Encore Operating and our general
partner, with the approval of the conflicts committee of the
board of directors of our general partner.
|
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 Operatings failure to pay
an employee within 30 days of the date such employees
payment is due, subject to certain limitations; or
|
|
|
|
upon the bankruptcy, dissolution, liquidation, or winding up of
Encore Operating.
|
We also reimburse EAC for any state income, franchise, or
similar tax incurred by EAC resulting from the inclusion of us
in consolidated tax returns with EAC as required by applicable
law. The amount of any such reimbursement is limited to the tax
that we would have incurred had we not been included in a
combined group with EAC.
Policies
and Procedures for Approval of Related Person
Transactions
The board of directors of our general partner has 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:
|
|
|
|
|
ENP is a participant;
|
|
|
|
any related person has a direct or indirect material
interest; and
|
138
ENCORE
ENERGY PARTNERS LP
|
|
|
|
|
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.
|
PRINCIPAL
ACCOUNTANT FEES AND SERVICES
|
The Audit Committee of the board of directors of our general
partner appointed Ernst & Young LLP as our independent
registered public accounting firm for 2010.
Fees
Incurred by Us for Services Provided by Ernst & Young
LLP
The following table shows the fees paid or accrued by us for
services provided by Ernst & Young LLP during the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Audit fees(a)
|
|
$
|
1,038,847
|
|
|
$
|
868,471
|
|
Audit-related fees
|
|
|
|
|
|
|
|
|
Tax fees
|
|
|
|
|
|
|
|
|
All other fees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,038,847
|
|
|
$
|
868,471
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Represent fees for professional services provided in connection
with: (1) the annual audit of our consolidated financial
statements and our general partners consolidated balance
sheets; (2) the annual audit of our internal control over
financial reporting; (3) the review of our quarterly
consolidated financial statements; and (4) audit services
provided in connection with SEC filings, including comfort
letters, consents, and comment letters. |
Audit
Committees Pre-Approval Policy and Procedures
The policy of our general partners Audit Committee 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. Our general partners
Audit Committee requires our independent registered public
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, our general partners
Audit Committee of our general partner requires specific
pre-approval before engaging our independent registered public
accounting firm. Our general partners 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 services provided by our independent registered public
accounting firm were pre-approved.
139
ENCORE
ENERGY PARTNERS LP
PART IV
|
|
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
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
No.
|
|
Description
|
|
|
|
|
3
|
.1
|
|
Certificate of Limited Partnership of Encore Energy Partners LP
(incorporated by reference from Exhibit 3.1 to ENPs
Registration Statement on Form S-1 (File No. 333-142847), filed
with the SEC on May 11, 2007).
|
|
|
|
3
|
.2
|
|
Second Amended and Restated Agreement of Limited Partnership of
Encore Energy Partners LP, dated as of September 17, 2007
(incorporated by reference from Exhibit 3.1 to ENPs
Current Report on Form 8-K, filed with the SEC on September 21,
2007).
|
|
|
|
3
|
.2.1
|
|
Amendment No. 1 to Second Amended and Restated Agreement of
Limited Partnership of Encore Energy Partners LP, dated as of
May 10, 2007 (incorporated by reference from Exhibit 3.1 to
ENPs Current Report on Form 8-K, filed with the SEC on
April 18, 2008).
|
|
|
|
10
|
.1
|
|
Credit Agreement, dated as of March 7, 2007, by and among Encore
Energy Partners Operating LLC, Encore Energy Partners LP, Bank
of America, N.A., as administrative agent and L/C Issuer, Banc
of America Securities LLC, as sole lead arranger and sole book
manager, and other lenders (incorporated by reference from
Exhibit 10.2 to EACs Current Report on Form 8-K, filed
with the SEC on March 13, 2007).
|
|
|
|
10
|
.2
|
|
First Amendment to Credit Agreement, dated as of August 22,
2007, by and among Encore Energy Partners Operating LLC, Encore
Energy Partner LP, Bank of America, N.A., as administrative
agent and L/C Issuer, Banc of America Securities LLC, as sole
lead arranger and sole book manager, and other lenders
(incorporated by reference from Exhibit 10.2 to Amendment No. 4
to ENPs Registration Statement on Form S-1, filed with the
SEC on August 28, 2007).
|
|
|
|
10
|
.3
|
|
Second Amendment to Credit Agreement, dated as of March 10,
2009, by and among Encore Energy Partners Operating LLC, Encore
Energy Partners LP, Bank of America, N.A., as administrative
agent and L/C issuer, and the lenders party thereto
(incorporated by reference to Exhibit 10.1 of ENPs Current
Report on Form 8-K, filed with the SEC on March 11, 2009).
|
|
|
140
ENCORE
ENERGY PARTNERS LP
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
No.
|
|
Description
|
|
|
|
|
10
|
.4
|
|
Third Amendment to Credit Agreement, dated as of August 11,
2009, by and among Encore Energy Partners Operating LLC, Encore
Energy Partners LP, Bank of America, N.A., as the administrative
agent and L/C issuer, and the lenders party thereto
(incorporated by reference from Exhibit 10.1 of ENPs
Current Report on Form 8-K filed on August 13, 2009).
|
|
|
|
10
|
.5
|
|
Fourth Amendment to Credit Agreement, dated as of November 24,
2009, by and among Encore Energy Partners Operating LLC, Encore
Energy Partners LP, Bank of America, N.A., as the administrative
agent and L/C issuer, and the lenders party thereto
(incorporated by reference to Exhibit 10.1 of Encore Energy
Partners LPs Current Report on Form 8-K, filed with the
SEC on December 1, 2009).
|
|
|
|
10
|
.6
|
|
Amended and Restated Administrative Services Agreement, dated as
of September 17, 2007, by and among Encore Energy Partners GP
LLC, Encore Energy Partners LP, Encore Energy Partners Operating
LLC, Encore Acquisition Company and Encore Operating, L.P.
(incorporated by reference from Exhibit 10.2 to ENPs
Current Report on Form 8-K, filed with the SEC on September 21,
2007).
|
|
|
|
10
|
.7+
|
|
Encore Energy Partners GP LLC Long-Term Incentive Plan, dated as
of September 17, 2007 (incorporated by reference from Exhibit
10.3 to ENPs Current Report on Form 8-K, filed with the
SEC on September 21, 2007).
|
|
|
|
10
|
.8+
|
|
Form of Phantom Unit Award Agreement (incorporated by reference
from Exhibit 10.10 to Amendment No. 3 to ENPs Registration
Statement on Form S-1, filed with the SEC on August 10, 2007).
|
|
|
|
10
|
.9
|
|
Purchase and Sale Agreement, dated May 18, 2009, by and among
Encore Energy Partners LP, Encore Energy Partners Operating LLC,
and Encore Operating, L.P. (incorporated by reference from
Exhibit 2.1 of ENPs Current Report on Form 8-K, filed with
the SEC on June 5, 2009).
|
|
|
|
10
|
.10
|
|
Purchase and Sale Agreement, dated June 28, 2009, by and among
Encore Energy Partners LP, Encore Energy Partners Operating LLC,
and Encore Operating, L.P. (incorporated by reference from
Exhibit 2.1 of ENPs Current Report on Form 8-K, filed with
the SEC on June 29, 2009).
|
|
|
|
12
|
.1*
|
|
Statement showing computation of ratio of earnings (loss) to
fixed charges.
|
|
|
|
21
|
.1*
|
|
Subsidiaries of Encore Energy Partners LP as of February 22,
2010.
|
|
|
|
23
|
.1*
|
|
Consent of Ernst & Young LLP.
|
|
|
|
23
|
.2*
|
|
Consent of Miller and Lents, Ltd.
|
|
|
|
24
|
.1*
|
|
Power of Attorney (included on the signature page of this
Report).
|
|
|
|
31
|
.1*
|
|
Rule 13a-14(a)/15d-14(a) Certification (Principal Executive
Officer of our General Partner).
|
|
|
|
31
|
.2*
|
|
Rule 13a-14(a)/15d-14(a) Certification (Principal Financial
Officer of our General Partner).
|
|
|
|
32
|
.1*
|
|
Section 1350 Certification (Principal Executive Officer of our
General Partner).
|
|
|
|
32
|
.2*
|
|
Section 1350 Certification (Principal Financial Officer of our
General Partner).
|
|
|
|
99
|
.1*
|
|
Miller and Lents, Ltd. report on the Reserves and Future Net
Revenues of Encore Energy Partners LP as of December 31, 2009.
|
|
|
|
|
|
* |
|
Filed herewith. |
|
+ |
|
Management contract or compensatory plan, contract, or
arrangement. |
141
ENCORE
ENERGY PARTNERS LP
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 22, 2010
|
|
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 and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
|
|
|
|
Title or Capacity (Position with Encore
|
|
|
Signature
|
|
Energy Partners GP LLC)
|
|
Date
|
|
|
|
|
|
|
/s/ I.
Jon Brumley
I.
Jon Brumley
|
|
Chairman of the Board and Director
|
|
February 22, 2010
|
|
|
|
|
|
/s/ Jon
S. Brumley
Jon
S. Brumley
|
|
Chief Executive Officer, President, and Director (Principal
Executive Officer)
|
|
February 22, 2010
|
|
|
|
|
|
/s/ Robert
C. Reeves
Robert
C. Reeves
|
|
Senior Vice President, Chief Financial Officer, Treasurer, and
Corporate Secretary (Principal Financial Officer)
|
|
February 22, 2010
|
|
|
|
|
|
/s/ Andrea
Hunter
Andrea
Hunter
|
|
Vice President, Controller, and Principal Accounting Officer
|
|
February 22, 2010
|
|
|
|
|
|
/s/ Arnold
L. Chavkin
Arnold
L. Chavkin
|
|
Director
|
|
February 22, 2010
|
|
|
|
|
|
/s/ John
E. Jackson
John
E. Jackson
|
|
Director
|
|
February 22, 2010
|
|
|
|
|
|
/s/ J.
Luther King, Jr.
J.
Luther King, Jr.
|
|
Director
|
|
February 22, 2010
|
|
|
|
|
|
/s/ Clayton
E. Melton
Clayton
E. Melton
|
|
Director
|
|
February 22, 2010
|
|
|
|
|
|
/s/ George
W. Passela
George
W. Passela
|
|
Director
|
|
February 22, 2010
|
142